Edgar Filing: EL PASO NATURAL GAS CO

epng200810k.htm

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, 2008

	OR

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

	For the transition period from to .

Commission File Number 1-2700

El Paso Natural Gas Company

(Exact Name of Registrant as Specified in Its Charter)

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

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

Telephone Number: (713) 420-2600

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

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

Indicate by check mark 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 £	Accelerated filer £	Non-accelerated filer R	Smaller reporting company £
	(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 March 2, 2009: 1,000

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

Documents Incorporated by Reference: None

EL PASO NATURAL GAS COMPANY

TABLE OF CONTENTS


		Caption	Page

	PART I

Item 1.	Business		1
Item 1A.	Risk Factors		5
Item 1B.	Unresolved Staff Comments		12
Item 2.	Properties		12
Item 3.	Legal Proceedings		12
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		13
Item 6.	Selected Financial Data		*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		19
Item 8.	Financial Statements and Supplementary Data		20
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

____________

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

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

/d	=	per day	LNG	=	liquefied natural gas
BBtu	=	billion British thermal units	MMcf	=	million cubic feet
Bcf	=	billion 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 east-end deliverability of 800 MMcf/d. During 2008, 2007 and 2006, average throughput was 4,379 BBtu/d, 4,189 BBtu/d and 4,179 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 2008, 2007 and 2006, average throughput was 349 BBtu/d, 458 BBtu/d and 461 BBtu/d. Mojave’s 2008, 2007 and 2006 throughput includes 306 BBtu/d, 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. We utilize 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 and 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 and storage services in both 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 has been a growing supply sector of the natural gas market. LNG terminals and other regasification facilities can serve as alternate 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 has been a growing demand sector of the natural gas market. The growth of natural gas fired electric power benefits the natural gas industry by creating more demand for natural gas. This potential benefit is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity 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 transportation contracts with natural gas pipelines.

We provide transportation services to the southwestern U.S. and to the Mexican border through connections to other pipelines. The market demand for natural gas distribution as well as gas-fired electric generation capacity has experienced considerable growth in these areas in recent years. Historically, California customers have been the largest holders of capacity on our EPNG system. Currently, California and Arizona customers account for the majority of transportation on the EPNG system. Following California and Arizona, Texas accounts for the next highest load, followed by New Mexico. The EPNG system also delivers natural gas to the U.S./Mexico Border serving customers in Chihuahua, Sonora, and Baja California, Mexico.

We expect growth of the natural gas market will be adversely affected by the current economic recession in the U. S. and global economies. The decline in economic activity will reduce industrial demand for natural gas and electricity, which will cause lower natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. The demand for natural gas and electricity in the residential and commercial segments of the market will likely be less affected by the economy. The lower demand and the credit restrictions on investments in the current environment may also slow development of supply projects. While our pipelines could experience some level of reduced throughput and revenues, or slower development of expansion projects as a result of these factors, each generates a significant (greater than 80%) portion of their revenues through fixed monthly reservation or demand charges on long-term contracts at rates stipulated under our tariffs.

Our existing transportation and storage contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted 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 maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

The EPNG system 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 the southwestern U.S. and northern Mexico were completed in 2008.

The Mojave system 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 the southwestern U.S. and northern Mexico were completed in 2008.

The following table details our customer and contract information for each of our pipeline systems as of December 31, 2008. Firm customers reserve capacity on our pipeline systems and storage facility 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 transport, store, inject or withdraw.

Pipeline System	Customer Information	Contract Information
EPNG	Approximately 160 firm and interruptible customers.	Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately three years.

	Major Customers:
	Sempra Energy and Subsidiaries, including Southern California Gas Company (SoCal)
	(130 BBtu/d)	Expires in 2009.
	(246 BBtu/d)	Expires in 2010.
	(323 BBtu/d)	Expires in 2011.

	ConocoPhillips Company
	(447 BBtu/d)	Expires in 2009.
	(150 BBtu/d)	Expires in 2010.
	(392 BBtu/d)	Expires in 2012.

	Southwest Gas Corporation
	(412 BBtu/d)	Expires in 2011.
	(75 BBtu/d)	Expires in 2015.

Mojave	Approximately 10 firm and interruptible customers.	Approximately five firm transportation contracts. Weighted average remaining contract term of approximately seven years.

	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 the 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 23, 2009, we had approximately 880 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.

The financial 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 third parties, including our customers, 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;

•

price competition;

•

expiration or turn back of significant contracts;

•

changes in regulation and action of regulatory bodies;

•

weather conditions that impact natural gas throughput and storage levels;

•

weather fluctuations or warming or cooling trends that may impact demand in the markets in which we do business, including trends potentially attributed to climate change;

•

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

•

continued development of additional sources of gas supply that can be accessed;

•

decreased natural gas demand due to various factors, including economic recession (as further discussed below) and increases in prices;

•

legislative, regulatory or judicial actions, such as mandatory greenhouse gas regulations and/or legislation that could result in (i) changes in the demand for natural gas and oil, (ii) changes in the availability of or demand for alternative energy sources such as hydroelectric and nuclear power, wind and solar and/or (iii) changes in the demand for less carbon intensive energy sources;

•

availability and cost to fund ongoing maintenance and growth projects, especially in periods of prolonged economic decline;

•

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.

A substantial portion of our revenues are generated from firm transportation contracts that must be renegotiated periodically.

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

•

legislative and/or regulatory actions.

For additional information on our revenues from 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.

We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers, including default risk associated with adverse economic conditions. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of our existing or future customers, and they fail to pay and/or perform due to an unanticipated deterioration in their creditworthiness and we are unable to remarket the capacity, our business, the results of our operations and our financial condition could be adversely affected. We may not be able to effectively remarket capacity during and after insolvency proceedings involving a shipper.

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 may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our financial condition, results of operations and liquidity. 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 and regulation;

•

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 the 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. In June 2008, EPNG filed a rate case with the FERC as required under the settlement of its previous rate case. The filing proposed an increase in our base tariff rates. In August 2008, the FERC issued an order accepting the proposed rates to be effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference.

In addition, in April 2008, the FERC adopted a new policy that will allow master limited partnerships to be included in rate of return proxy groups for determining rates for services provided by interstate natural gas and oil pipelines. 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’s policy statement concludes among other items that (i) there should be no cap on the level of distributions included in the current discounted cash flow methodology and (ii) there should be a downward adjustment to the long-term growth rate used for the equity cost of capital of natural gas pipeline master limited partnerships. 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 a January 15, 2009 decision that discussed an individual pipeline’s rate of return, the FERC analyzed the operations of each company proposed for inclusion in that pipeline’s proxy group to determine whether each company to be included had commensurate risks to the pipeline whose rates were being determined. The FERC included in that proxy group two primarily gas pipeline master limited partnerships (with the adjusted gross domestic product) and a diversified company that had higher risk exploration, production and trading operations in addition to pipeline operations. Companies whose distribution, electric or natural gas liquids operations exceeded pipeline operations were excluded. In light of this, it is expected that pipeline returns on equity will be driven largely by fact-based proxy group determinations in each case.

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 U. S. Environmental Protection Agency (EPA) 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, financial position or cash flows. 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;

•

receiving regulatory approval for remediation programs;

•

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.

In addition to potentially increasing the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards and potential mandatory greenhouse gas reporting and emission reductions. Future environmental compliance costs relating to greenhouse gases (GHGs) associated with our operations are not yet clear. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. Various federal and state legislative proposals have been made over the last several years and it is possible that legislation may be enacted in the future that could negatively impact our operations and financial results. The level of such impact will likely depend upon whether any of our facilities will be directly responsible for compliance with GHG regulations and legislation; whether federal legislation will preempt any potentially conflicting state/regional GHG programs; whether cost containment measures will be available; the ability to recover compliance costs from our customers; and the manner in which allowances are provided. At the federal regulatory level, the EPA has requested public comments on the potential regulation of GHGs under the Clean Air Act. Some of the regulatory alternatives identified by the EPA in its request for comments, if eventually promulgated as final rules, would likely impact our operations and financial results. It is uncertain whether the EPA will proceed with adopting final rules or whether the regulation of GHGs will be addressed in federal and state legislation.

Legislation and regulation are also in various stages of discussion or implementation in many of the states and regions in which we operate, including the Western Climate Initiative (WCI) proposal to institute a cap-and-trade program and target emission reductions. There is uncertainty regarding whether and to what extent each member state will adopt the WCI recommendations, and the details of the programs as eventually adopted may differ significantly among the member states. In addition, California has enacted legislation that imposes GHG emission reductions. However, California’s governing state regulatory agency must enact implementing regulations to define the scope of the coverage, the compliance schedule and other relevant provisions governing GHG emissions. Therefore, it is not yet possible to determine whether the regulations implementing the WCI recommendations or the California legislation will be material to our operations or our financial results.

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

Although it is uncertain what impact these legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could 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 the costs associated with our environmental liabilities and environmental and GHG compliance in the rates charged by our pipelines and in the prices at which we sell natural gas, our ability to recover such 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 regulations and 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. Analyses performed by various governmental and private organizations indicate potential physical risks associated with climate change events (such as flooding, etc). Some of the studies indicate that potential impacts on energy infrastructure are highly uncertain and not well understood, including both the timing and potential magnitude of such impacts. As the science is better understood and analyzed, we will review the operational and uninsured risks to our facilities attributed to climate change.

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. In addition, there is a risk that our insurers may default on their coverage obligations. 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 access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;

•

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, 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/or demand; 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. There is also the risk that the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

We are exposed to the decline in value on our long-lived assets.

Our long-lived assets are subject to the decline in their 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. Therefore, actual results may differ from these estimates.

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 general domestic economic conditions could negatively 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 U.S. economy has experienced recession and the financial markets have experienced extreme volatility and instability. In response to the volatility in the financial markets, El Paso has announced certain actions that are designed to reduce its need to access such financial markets, including reductions in the capital programs of certain of its operating subsidiaries and the sale of several non-core assets.

If we or El Paso experience prolonged periods of recession or slowed economic growth in the United States, demand growth from consumers for natural gas transported by us may continue to decrease, which could impact the development of our future expansion projects. Additionally, our or El Paso’s access to capital could continue to be impeded and the cost of capital we obtain could be higher. Finally, we are subject to the risks arising from changes in legislation and regulation associated with any such recession or prolonged economic slowdown, including creating preference for renewables, as part of a legislative package to stimulate the economy. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.

We are subject to financing and interest rate risk.

Our future success, financial condition and liquidity could be adversely affected based on our ability to access capital markets and obtain financing at cost effective rates. This is dependent on a number of factors in addition to general economic conditions discussed above, many of which we cannot control, including changes in:

•

our credit ratings;

•

the structured and commercial financial markets;

•

market perceptions of us or the natural gas and energy industry;

•

tax rates due to new tax laws; and

•

market prices for hydrocarbon products.

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, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as credit rating agencies continue to review our and El Paso’s leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital and collateral requirements.

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 we have established. 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, 2008. 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. During 2008, we utilized $200 million of our notes receivable from the cash management program to pay dividends to our parent. No common stock dividends were declared or paid in 2007.

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 primary business consists of the 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, solar, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.

		Percent of Total
Type	Description	Revenues in 2008

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.	87

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.	13

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, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather. We have 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 reduces the financial impacts of our operational gas costs.

We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues from expiring contracts. Our ability to extend our 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 maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable 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 our active contracts is approximately three years as of December 31, 2008. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2008, including those with terms beginning in 2009 or later.

			Percent of Total					Percent of Total
	BBtu/d (1)		Contracted Capacity		Reservation Revenue			Reservation Revenue
					(In millions)
2009		1,286		24		$	125		23
2010		931		18			95		17
2011		1,228		23			136		24
2012		639		12			79		14
2013		182		4			17		3
2014 and beyond		1,015		19			103		19
Total		5,281		100		$	555		100

____________

(1)	Excludes EPNG capacity on the Mojave system.

Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business. We believe EBIT is useful to investors because it allows them to evaluate more effectively 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, 2008 compared with 2007.

Operating Results:

	2008			2007
	(In millions,
	except for volumes)
Operating revenues	$	590		$	557
Operating expenses		(333	)		(319	)
Operating income		257			238
Other income, net		5			4
EBIT		262			242
Interest and debt expense		(90	)		(98	)
Affiliated interest income, net		46			71
Income taxes		(83	)		(83	)
Net income	$	135		$	132
Throughput volumes (BBtu/d)(1)		4,422			4,216

____________

(1)	Throughput volumes exclude throughput transported on the Mojave system on behalf of EPNG.

EBIT Analysis:

	Revenue		Expense			Other			EBIT Impact
	Favorable/(Unfavorable)
	(In millions)
Reservation and other services revenues	$	29	$	—		$	—		$	29
Enron bankruptcy settlement		4		1			—			5
Operating and general and administrative expenses		—		(12	)		—			(12	)
Asset impairments		—		(5	)		(1	)		(6	)
Other (1)		—		2			2			4
Total impact on EBIT	$	33	$	(14	)	$	1		$	20

____________

(1)	Consists of individually insignificant items.

Reservation and Other Services Revenues. Our reservation and other services revenues were higher for the year ended December 31, 2008 compared to 2007, primarily due to an increase in reservation charges for capacity on our EPNG system resulting from higher amounts charged on recontracted capacity in California and Arizona, higher pipeline integrity program surcharges and increased pipeline usage by firm customers in 2008.

In June 2008, EPNG filed a rate case with the FERC as required under the settlement of its previous rate case. The filing proposed an increase in our base tariff rates. In August 2008, the FERC issued an order accepting the proposed rates to be effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of our proposals in the technical conference proceeding. The FERC appointed an administrative law judge who will decide the remaining issues should we be unable to reach a settlement with our customers in upcoming negotiations.

Enron Bankruptcy Settlement. During 2008 and 2007, we recorded income of approximately $10 million and $5 million, net of amounts owed to certain customers as a result of the Enron bankruptcy settlement.

Operating and General and Administrative Expenses. During the year ended December 31, 2008, our operating and general, and administrative expenses increased primarily as a result of increased maintenance costs and additional accruals for certain outstanding legal matters.

Asset Impairments. During 2008, we recorded impairments of approximately $14 million due to declining real estate values related to our Arizona storage projects, which we are no longer developing. During 2007, we recorded an impairment of approximately $9 million related to our East Valley Line Lateral pursuant to a FERC order on our accounting treatment for the planned sale of certain transmission facilities.

Interest and Debt Expense

Interest and debt expense for the year ended December 31, 2008, was $8 million lower than in 2007 primarily due to interest recorded in 2007 for EPNG’s rate refund provision related to our rate case effective January 1, 2006.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, 2008, was $25 million lower than in 2007 primarily due to lower average short-term interest rates and lower average advances to El Paso under its cash management program. The average short-term interest rate decreased from 6.2% in 2007 to 4.4% in 2008. In addition, the average advances due from El Paso of $1.2 billion in 2007 decreased to $1.1 billion in 2008.

Income Taxes

Our effective tax rate of 38 percent and 39 percent for the years ended December 31, 2008 and 2007 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 Resources

Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities and El Paso’s cash management program. Our primary uses of cash are for working capital and capital expenditures. We have historically advanced cash to El Paso under its cash management program, which we reflect in investing activities in our statement of cash flows. During 2008, we utilized $200 million of our notes receivable from the cash management program to pay dividends to our parent. At December 31, 2008, we had a note receivable from El Paso of approximately $1.0 billion. We do not intend to settle this note within the next twelve months and therefore, classified it as non-current on our balance sheet. See Item 8, Financial Statements and Supplementary Data, Note 10, for a further discussion of El Paso’s cash management program. We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program will be adequate to meet our capital requirements and our existing operating needs.

In addition to the cash management program, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2008, El Paso had approximately $0.7 billion of capacity remaining and available to us under this credit agreement, 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.

Extreme volatility in the financial markets, the energy industry and the global economy will likely continue through 2009. The global financial markets remain extremely volatile and it is uncertain whether recent U.S. and foreign government actions will successfully restore confidence and liquidity in the global financial markets. This could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Based on the liquidity available to us through cash on hand, our operating activities and El Paso’s cash management program, we do not anticipate having a need to directly access the financial markets in 2009 for any of our operating activities or expansion capital needs. Additionally, although the impacts are difficult to quantify at this point, a downward trend in the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.

As of December 31, 2008, El Paso had approximately $1.0 billion of cash and approximately $1.2 billion of capacity available to it under various committed credit facilities. In light of the current economic climate and in response to the financial market volatility, El Paso, since November 2008, has generated approximately $1.2 billion of additional liquidity through three separate note offerings and has obtained additional revolving credit facility capacity and letter of credit capacity. Although we do not anticipate to directly access the financial markets in 2009, the volatility in the financial markets could impact our or El Paso’s ability to access these markets at reasonable rates in the future.

For further detail on our risk factors including adverse general economic conditions and our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A, Risk Factors.

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

	2008		2007
	(In millions)
Maintenance	$	134	$	99
Expansion/Other		52		21
Total	$	186	$	120

Under our current plan for 2009, we have budgeted to spend (i) approximately $122 million 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 and (ii) approximately $3 million to expand the capacity and services of our pipeline systems.

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

We are exposed to the risk of changing interest rates. At December 31, 2008, we had a note receivable from El Paso of approximately $1.0 billion, with a variable interest rate of 3.2% 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 and the fact that it is a demand note.

The table below shows the carrying value and related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities estimated based on quoted market prices for the same or similar issues.

	December 31, 2008
	Expected Fiscal Year of Maturity of Carrying Amounts										December 31, 2007
	2010			2014 and Thereafter			Total		Fair Value		Carrying Amount		Fair Value
							(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate	$	54		$	1,112		$	1,166	$	1,021	$	1,166	$	1,309
Average effective interest rate		7.8	%		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, 2008. 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, 2008.

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, 2008 and 2007, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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 December 31, 2006 and January 1, 2008, the Company adopted the recognition and measurement date provisions, respectively, 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).

/s/ Ernst & Young LLP

Houston, Texas

February 26, 2009

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Year Ended December 31,
	2008			2007			2006
Operating revenues	$	590		$	557		$	588
Operating expenses
Operation and maintenance		213			201			184
(Gain) loss on long-lived assets		14			9			(1	)
Depreciation and amortization		80			82			92
Taxes, other than income taxes		26			27			30
		333			319			305
Operating income		257			238			283
Other income, net		5			4			3
Interest and debt expense		(90	)		(98	)		(95	)
Affiliated interest income, net		46			71			53
Income before income taxes		218			215			244
Income taxes		83			83			92
Net income	$	135		$	132		$	152

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

	December 31,
	2008		2007
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts and notes receivable
Customer, net of allowance of $2 in 2008 and $4 in 2007		66		73
Affiliates		6		6
Other		6		1
Materials and supplies		43		41
Deferred income taxes		12		7
Prepaids		15		4
Other		8		3
Total current assets		156		135
Property, plant and equipment, at cost		3,804		3,710
Less accumulated depreciation and amortization		1,365		1,298
Total property, plant and equipment, net		2,439		2,412
Other assets
Note receivable from affiliate		986		1,113
Other		103		133
		1,089		1,246
Total assets	$	3,684	$	3,793

LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	48	$	101
Affiliates		21		17
Other		18		33
Taxes payable		79		56
Accrued interest		20		20
Accrued liabilities		9		20
Regulatory liabilities		33		19
Other		31		13
Total current liabilities		259		279
Long-term debt		1,166		1,166
Other liabilities
Deferred income taxes		389		370
Other		72		116
		461		486
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		530		594
Total stockholder’s equity		1,798		1,862
Total liabilities and stockholder’s equity	$	3,684	$	3,793

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities
Net income	$	135		$	132		$	152
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		80			82			92
Deferred income taxes		14			37			15
(Gain) loss on long-lived assets		14			9			(1	)
Other non-cash income items		12			8			—
Asset and liability changes
Accounts receivable		3			9			35
Accounts payable		(65	)		65			(17	)
Taxes payable		24			(27	)		55
Other current assets		(13	)		(5	)		—
Other current liabilities		(13	)		(88	)		38
Non-current assets		56			(66	)		(30	)
Non-current liabilities		8			(31	)		(17	)
Net cash provided by operating activities		255			125			322

Cash flows from investing activities
Additions to property, plant and equipment		(186	)		(120	)		(143	)
Net change in notes receivable from affiliate		127			(43	)		(198	)
Net change in restricted cash		—			—			17
Other		4			2			2
Net cash used in investing activities		(55	)		(161	)		(322	)

Cash flows from financing activities
Dividends paid to parent		(200	)		—			—
Net proceeds from issuance of long-term debt		—			350			—
Payments to retire long-term debt		—			(314	)		—
Net cash provided by (used in) financing activities		(200	)		36			—

Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—
End of period	$	—		$	—		$	—

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In millions, except share amounts)

	Common stock				Additional Paid-in		Retained			Accumulated Other Comprehensive			Total Stockholder’s
	Shares		Amount		Capital		Earnings			Income (Loss)			Equity
January 1, 2006		1,000	$	—	$	1,268	$	310			—		$	1,578
Net income								152						152
Adoption of SFAS No. 158, net of income taxes of $3 (Note 7)											(4	)		(4	)
December 31, 2006		1,000		—		1,268		462			(4	)		1,726
Net income								132						132
Reclassification to regulatory asset (Note 7)											4			4
December 31, 2007		1,000		—		1,268		594			—			1,862
Net income								135						135
Dividend paid to parent								(200	)					(200	)
Adoption of SFAS No. 158, net of income taxes of less than $1 (Note 7)								1						1
December 31, 2008		1,000	$	—	$	1,268	$	530		$	—		$	1,798

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. Our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or stockholder’s equity.

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, fuel recovery mechanism and related gas cost and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of 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.

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 percent 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 percent 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 a remaining life of 24 years, and we do not recover these excess costs in our rates. At December 31, 2008 and 2007, we had unamortized additional acquisition costs of $58 million and $60 million.

At December 31, 2008 and 2007, we had $54 million and $98 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 each of the years ended December 31, 2008, 2007 and 2006, were $1 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 taxes) during the years ended December 31, 2008, 2007 and 2006, were $3 million, $2 million and $2 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 its 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 and actual amounts may differ from these estimates. 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 2008, we recorded impairments of approximately $14 million due to declining real estate values related to our Arizona storage projects, which we are no longer developing. During 2007, we recorded an impairment of approximately $9 million related to our East Valley Line lateral pursuant to a FERC order on our accounting treatment for the planned sale of certain transmission facilities.

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. 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 (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period 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.

We evaluate our tax positions for all jurisdictions and for all years where the statute of limitations has not expired in accordance with 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 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.

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 in the period the obligation is incurred. 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, 2008 and 2007, 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 the 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.

Effective December 31, 2006, we began accounting for our postretirement benefit plan under 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 recorded a $4 million increase, net of income taxes of $3 million, to accumulated other comprehensive loss related to the adoption of this standard. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $4 million from accumulated other comprehensive loss to a regulatory asset.

Effective January 1, 2008, we adopted the measurement date provisions of SFAS No. 158 and changed the measurement date of our postretirement benefit plan from September 30 to December 31. We recorded an increase of $1 million, net of income taxes of less than $1 million, to our January 1, 2008 retained earnings balance upon the adoption of the measurement date provisions of this standard. 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, 2008, the following accounting standards had not yet been adopted by us.

Fair Value Measurements. We have adopted the provisions of SFAS No. 157, Fair Value Measurements in measuring the fair value of financial assets and liabilities in the financial statements. We have elected to defer the adoption of SFAS No. 157 for certain of our non-financial assets and liabilities until January 1, 2009, the adoption of which will not 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 interest, subsequently renamed “noncontrolling interest”, in the financial statements. This standard requires that noncontrolling interest be presented as a separate component of equity rather than as a “mezzanine” item between liabilities and equity, and also requires that noncontrolling interest be presented as a separate caption in the income statement. This standard also requires all transactions with noncontrolling interest holders, including the issuance and repurchase of noncontrolling interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs. We will adopt the provisions of this standard effective January 1, 2009. The adoption of this standard will not have a material impact 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 state and local income tax examinations by tax authorities for years prior to 1999 and U.S. income tax examinations for years prior to 2005. In June 2008, the Internal Revenue Service’s examination of El Paso’s U.S. income tax returns for 2003 and 2004 was settled at the appellate level with approval by the Joint Committee on Taxation. The settlement of issues raised in this examination did not materially impact our results of operations, financial condition or liquidity. 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:

	2008		2007		2006
	(In millions)
Current
Federal	$	61	$	40	$	66
State		8		6		11
		69		46		77
Deferred
Federal		12		32		13
State		2		5		2
		14		37		15
Total income taxes	$	83	$	83	$	92

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:

	2008			2007			2006
	(In millions, except for rates)
Income taxes at the statutory federal rate of 35%	$	76		$	75		$	85
Increase (decrease)
State income taxes, net of federal income tax effect		7			7			8
Non-deductible expenses		—			1			—
Other		—			—			(1	)
Income taxes	$	83		$	83		$	92
Effective tax rate		38	%		39	%		38	%

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

	2008		2007
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	489	$	462
Regulatory and other assets		27		29
Total deferred tax liability		516		491
Deferred tax assets
U.S. net operating loss and tax credit carryovers		77		80
Other liabilities		62		48
Total deferred tax asset		139		128
Net deferred tax liability	$	377	$	363

We believe it is more likely than not that we will realize the benefit of our deferred tax assets due to expected future taxable income, including the effect of future reversals of existing taxable temporary differences primarily related to depreciation.

Tax Credits and Carryovers. As of December 31, 2008, we had approximately $19 million of alternative minimum tax credits that carryover indefinitely. We also have approximately $167 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, 2008 and 2007, 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. At December 31, 2008 and 2007, we had an interest bearing note receivable from El Paso of approximately $1.0 billion and $1.1 billion due upon demand, with a variable interest rate of 3.2% and 6.5%. 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 and the fact that it is a demand note.

In addition, 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:

	2008				2007
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)

Long-term debt	$	1,166	$	1,021	$	1,166	$	1,309

4. Regulatory Assets and Liabilities

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

	2008		2007
	(In millions)
Current regulatory assets
Deferred fuel loss and unaccounted for gas	$	5	$	—
Other		2		—
Total current regulatory assets		7		—
Non-current regulatory assets
Taxes on capitalized funds used during construction		22		21
Unamortized loss on reacquired debt		27		30
Postretirement benefits		9		8
Under-collected state income taxes		6		6
Deferred fuel variance		—		6
Other		4		3
Total non-current regulatory assets		68		74
Total regulatory assets	$	75	$	74

Current regulatory liabilities
Property and plant depreciation	$	5	$	10
Over-collected fuel variance		15		—
Pipeline integrity program		3		—
Other		10		9
Total current regulatory liabilities		33		19
Non-current regulatory liabilities
Property and plant depreciation		37		47
Postretirement benefits		4		29
Over-collected fuel variance		—		8
Excess deferred federal income taxes		2		2
Total non-current regulatory liabilities		43		86
Total regulatory liabilities	$	76	$	105

5. Debt and Credit Facilities

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

	2008		2007
	(In millions)
7.625% Notes due August 2010	$	54	$	54
5.95% Notes due April 2017		355		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		1,169
Less: Unamortized discount		3		3
Total long-term debt	$	1,166	$	1,166

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 Facility. We are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2008, El Paso had approximately $0.7 billion of capacity remaining and available to us under this credit agreement, 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. The indentures governing some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. For the year ended December 31, 2008, 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 filed motions with the trial court to dismiss on other grounds. The court dismissed a Nevada unfair trade practices act claim and a fraudulent concealment claim against El Paso, but the motions were otherwise denied. Discovery is proceeding. 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. 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. The case has been set for trial in September 2009 and discovery has commenced. 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 and 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 claims 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 April 2009. 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. Our costs and legal exposure related to this lawsuit are not currently determinable.

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 believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2008, we accrued approximately $6 million for our outstanding legal matters.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At December 31, 2008, we had accrued approximately $22 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 $42 million. Our accrual includes $20 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, 2008 to December 31, 2008 (in millions):

Balance at January 1, 2008	$	25
Additions/adjustments for remediation activities		1
Payments for remediation activities		(4	)
Balance at December 31, 2008	$	22

For 2009, we estimate that our total remediation expenditures will be approximately $7 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, 2008, we have estimated our share of the remediation costs at these sites to be between $11 million and $15 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. Since then, we have responded fully to the request and have been working with the ADEQ on this matter. Based upon the 38 studies now completed on our facilities in Arizona, Texas and New Mexico, as well as on tribal lands in Arizona and New Mexico, we have determined that the vast majority of the sites examined did not have chromium contamination above regulatory thresholds and no further action is required at those sites. We are undertaking further action at seven sites, but based on our information at this time, do not anticipate substantial issues with chromium at those sites.

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, 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 Rate Case. In June 2008, we filed a rate case with the FERC as required under the settlement of our previous rate case. The filing proposed an increase in our base tariff rates. In August 2008, the FERC issued an order accepting the proposed rates to be effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of our proposals in the technical conference proceeding. The FERC appointed an administrative law judge who will decide the remaining issues should we be unable to reach a settlement with our customers in upcoming negotiations.

Greenhouse Gas (GHG) Emissions. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. In the United States, it is likely that federal legislation requiring GHG controls will be enacted in the next few years. In addition, the EPA is considering initiating a rulemaking to regulate GHGs under the Clean Air Act. Legislation and regulation are also in various stages of discussions or implementation in many of the states in which we operate. These measures include recommendations released by the Western Climate Initiative regarding a cap-and-trade program and targeted emission reductions in several states in which we operate in the western United States, as well as recent legislation enacted in California that imposes GHG emission reduction targets. Additionally, lawsuits have been filed seeking to force the federal government to regulate GHG emissions and individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects. Our costs and legal exposure related to GHG regulations are not currently determinable.

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 (BIA). Subject to final reviews and approvals by the Navajo Nation, we have reached an agreement in principle on the terms of tribal consent to the BIA’s rights-of-way grant through October 2025. We made a payment to the Navajo Nation in October 2008 covering a twelve-month period through October 2009 and will continue to make annual payments per the terms of the definitive agreement. We have filed with the FERC for recovery of these amounts in our recent rate case.

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 have taken 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, 2008, we had capital commitments of approximately $20 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, 2008, were as follows:

Year Ending December 31,	(In millions)
2009	$	2
2010		1
2011		1
Thereafter		2
Total	$	6

Rental expense on our operating leases for each of the three years ended December 31, 2008, 2007 and 2006 was $22 million, $20 million and $17 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. With the exception of the rights of way on lands crossing the Navajo Nation discussed above, 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 that are not recorded in our financial statements. 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, 2008, we have financial and performance guarantees with a maximum exposure of approximately $11 million, not otherwise recognized in the 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 former 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 depending on its performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits. We provide postretirement medical benefits for a closed group of employees who retired on or before March 1, 1986, and limited postretirement life insurance for employees who retired after January 1, 1985. As such, our obligation to accrue for other postretirement employee benefits is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the 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 2009.

Effective December 31, 2006, we began accounting for our postretirement benefit plan under the recognition provisions of SFAS No. 158. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $4 million from accumulated other comprehensive loss to a regulatory asset.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. The table below provides information about our postretirement benefit plan. In 2008, we adopted the measurement date provisions of SFAS No. 158 and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008. For 2007, the information is presented and computed as of and for the twelve months ended September 30, 2007.

	December 31, 2008			September 30, 2007
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation — beginning of period	$	62		$	88
Interest cost		5			4
Actuarial gain		(8	)		(24	)
Benefits paid(1)		(7	)		(6	)
Accumulated postretirement benefit obligation — end of period	$	52		$	62
Change in plan assets:
Fair value of plan assets — beginning period	$	104		$	96
Actual return on plan assets		(25	)		14
Benefits paid		(8	)		(6	)
Fair value of plan assets — end of period	$	71		$	104
Reconciliation of funded status:
Fair value of plan assets	$	71		$	104
Less: accumulated postretirement benefit obligation		52			62
Fourth quarter contributions					—
Net asset at December 31	$	19		$	42

____________

(1)	Amounts shown are net of a subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

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 exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is the result of general economic and capital market conditions. As a result of the general decline in the markets for debt and equity securities, the fair value of our plan’s assets and the funded status of our postretirement benefit plan declined during 2008, which resulted in a significant decrease in our plan assets and regulatory liability when our plan’s assets and obligation were remeasured at December 31, 2008. The following table provides the target and actual asset allocations in our postretirement benefit plan as of December 31, 2008 and September 30, 2007:

Asset Category	Target		Actual 2008		Actual 2007
	(Percent)
Equity securities		65		65		63
Debt securities		35		34		33
Cash and cash equivalents		—		1		4
Total		100		100		100

Expected Payment of Future Benefits. As of December 31, 2008, we expect the following payments (net of an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003) under our plan (in millions):

Year Ending December 31,
2009	$	6
2010		6
2011		6
2012		6
2013		5
2014 — 2018		22

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 and net benefit costs for 2008, 2007 and 2006:

	2008		2007		2006
	(Percent)
Assumptions related to benefit obligations at December 31, 2008 and September 30, 2007 and 2006 measurement dates:
Discount rate		5.90		6.05		5.50
Assumptions related to benefit costs at December 31:
Discount rate		6.05		5.50		5.25
Expected return on plan assets(1)		8.00		8.00		8.00

____________

(1)

The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return.

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 8.6 percent in 2008, 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 2008 or 2007. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31, 2008 and 2007:

	2008			2007
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	3		$	4
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(3	)	$	(4	)

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

	2008			2007			2006
	(In millions)
Interest cost	$	4		$	4		$	5
Expected return on plan assets		(7	)		(6	)		(6	)
Amortization of net actuarial (gain) loss		(2	)		—			1
Net postretirement benefit income	$	(5	)	$	(2	)	$	—

8. Transactions with Major Customers

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

	2008		2007		2006(1)
	(In millions)
Sempra Energy and Subsidiaries (2)	$	85	$	93	$	152
ConocoPhillips Company(3)		82		47		33
Southwest Gas Corporation(4)		51		54		66

____________

(1)	Revenues reflect rates subject to refund.

(2)	Includes SoCal revenues.

(3)	In 2007 and 2006, ConocoPhillips did not represent more than 10 percent of our revenues.

(4)	In 2008 and 2007, Southwest Gas Corporation did not represent more than 10 percent of our revenues.

9. Supplemental Cash Flow Information

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

	2008		2007		2006
	(In millions)
Interest paid, net of capitalized interest	$	88	$	106	$	93
Income tax payments		45		112		22

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. During 2008, we utilized $200 million of our notes receivable from the cash management program to pay dividends to our parent. At December 31, 2008 and 2007, we had a note receivable from El Paso of approximately $1.0 billion and $1.1 billion. We do not intend to settle this note within twelve months and therefore, classified it as non-current on our balance sheets. The interest rate on our note at December 31, 2008 and 2007 was 3.2% and 6.5%.

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, 2008 and 2007, we had income taxes payable of $79 million and $54 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, 2008 and 2007, we had contractual deposits from our affiliates of $8 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 within the ordinary course of 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), our affiliate, associated with our pipeline services. We also allocate costs to Colorado Interstate Gas Company, our affiliate, 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:

	2008		2007		2006
	(In millions)
Revenues from affiliates	$	17	$	19	$	17
Operation and maintenance expenses from affiliates		56		53		52
Reimbursements of operating expenses charged to affiliates		21		17		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(1)		Total
	(In millions)
2008
Operating revenues	$	141	$	152	$	145	$	152	$	590
Operating income		60		74		61		62		257
Net income		33		40		31		31		135

2007
Operating revenues	$	145	$	136	$	136	$	140	$	557
Operating income		70		56		54		58		238
Net income		39		31		30		32		132

____________

(1)

Includes asset impairments of $14 million due to declining real estate values for 2008 related to our Arizona storage projects, which we are no longer developing and $9 million for 2007 related to our East Valley Line lateral pursuant to a FERC order on our accounting treatment for the planned sale of certain transmission facilities.

SCHEDULE II

EL PASO NATURAL GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2008, 2007 and 2006

(In millions)

Description	Balance at Beginning of Period		Charged to Costs and Expenses			Deductions			Balance at End of Period
2008
Allowance for doubtful accounts	$	4	$	(2	)	$	—		$	2
Legal reserves		4		8			(6	)		6
Environmental reserves		25		1			(4	)		22
Regulatory reserves		10		—			(10	)		—

2007
Allowance for doubtful accounts	$	5	$	(1	)	$	—		$	4
Legal reserves		16		4			(16	)		4
Environmental reserves		24		6			(5	)		25
Regulatory reserves		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		—		65			—			65

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2008, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our President and Chief Financial Officer have concluded that our disclosure controls and procedures are effective at a reasonable level of assurance at December 31, 2008. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9A(T).

CONTROLS AND PROCEDURES

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report. See Item 8, Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control over Financial Reporting.

ITEM 9B.

OTHER INFORMATION

None.

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;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2008 and 2007 of $751,000 and $863,000, respectively, were primarily for professional services rendered by Ernst & Young LLP and for the audits of the consolidated financial statements of El Paso Natural Gas Company and its subsidiaries, the review of documents filed with the Securities and Exchange Commission, consents, and the issuance of comfort letters.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2008 and 2007.

Policy for Approval of Audit and Non-Audit Fees

We are an indirect wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2009 Annual Meeting of Stockholders.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

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

1. Financial statements

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

		Page
	Reports of Independent Registered Public Accounting Firms	21
	Consolidated Statements of Income	22
	Consolidated Balance Sheets	23
	Consolidated Statements of Cash Flows	24
	Consolidated Statements of Stockholder’s Equity	25
	Notes to Consolidated Financial Statements	26

	2. Financial statement schedules

	Schedule II — Valuation and Qualifying Accounts	42

All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.

3. Exhibits

The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

Undertaking

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 2nd day of March 2009.

	EL PASO NATURAL GAS COMPANY


	By:	/s/ James J. Cleary
		James J. Cleary
		President

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

	Signature		Title		Date

/s/ James J. Cleary		President and Director		March 2, 2009
James J. Cleary		(Principal Executive Officer)

/s/ John R. Sult		Senior Vice President, Chief Financial		March 2, 2009
John R. Sult		Officer and Controller (Principal Accounting and Financial Officer)

/s/ James C. Yardley		Chairman of the Board		March 2, 2009
James C. Yardley

/s/ Daniel B. Martin		Senior Vice President and		March 2, 2009
Daniel B. Martin		Director

/s/ Thomas L. Price		Vice President and Director		March 2, 2009
Thomas L. Price

EL PASO NATURAL GAS COMPANY

EXHIBIT INDEX

December 31, 2008

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

Exhibit Number		Description

*3.A	Restated Certificate of Incorporation dated April 8, 2003.

*3.B	By-laws dated June 2, 2008.

4.A	Indenture dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.), as Trustee, (Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 29, 2005).

4.B	Indenture dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee, (Exhibit 4.B to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 29, 2005).

*4.C	Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee.

*4.D	First Supplemental Indenture dated as of June 10, 2002 between El Paso Natural Gas Company and Wilmington Trust Company (as successor in interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee, to indenture dated November 13, 1996.

4.E	Second Supplemental Indenture dated as of April 4, 2007 between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee, to indenture dated November 13, 1996 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on April 9, 2007).

4.F	First Supplemental Indenture dated as of April 4, 2007 between El Paso Natural Gas Company and Wilmington Trust Company, as trustee, to indenture dated as of July 23, 2003 (Exhibit 4.C to our Current Report on Form 8-K filed with the SEC on April 9, 2007).

4.G	Form of 5.95% Senior Note due 2017 (included in Exhibit 4.E).

10.A	Amended and Restated Credit Agreement dated as of July 31, 2006, among El Paso Corporation, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent. (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on August 2, 2006.)

10.A.1	Amendment No. 1 dated as of January 19, 2007 to the Amended and Restated Credit Agreement dated as of July 31, 2006 among El Paso Corporation, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (Exhibit 10.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007).

10.B	Amended and Restated Security Agreement dated as of July 31, 2006, among El Paso Corporation, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Guarantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank. (Exhibit 10.B to our Current Report on Form 8-K filed with the SEC on August 2, 2006.)

10.C	Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent. (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on November 21, 2007.)

Exhibit Number		Description

10.D	Third Amendment and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank. (Exhibit 10.B to our Current Report on Form 8-K filed with the SEC on November 21, 2007).

10.E	Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007.)

10.F	Registration Rights Agreement, dated as of April 4, 2007, among El Paso Natural Gas Company and Deutsche Bank Securities Inc., Citigroup Global Markets Inc., ABN AMRO Incorporated, Goldman, Sachs & Co, Greenwich Capital Markets, Inc., J.P. Morgan Securities Inc. and SG Americas Securities, LLC (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on April 9, 2007).

21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

*31.A	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.A	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.