Edgar Filing: EL PASO NATURAL GAS CO

Percent of Total Revenues

Description

in 2006

Reservation

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

Usage
and Other

Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) who pay charges based on the volume of gas actually transported, injected or withdrawn.

e10vk

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, 2006


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

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

Telephone Number: (713) 420-2600

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

State the aggregate market value of the voting stock held by non-affiliates of the registrant: None

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Common Stock, par value $1 per share. Shares outstanding on February 21, 2007: 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	3
Item 1A.	Risk Factors	6
Item 1B.	Unresolved Staff Comments	10
Item 2.	Properties	10
Item 3.	Legal Proceedings	10
Item 4.	Submission of Matters to a Vote of Security Holders	*

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	11
Item 6.	Selected Financial Data	*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	16
Item 8.	Financial Statements and Supplementary Data	17
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	39
Item 9A.	Controls and Procedures	39
Item 9B.	Other Information	39

	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	39

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	40
	Signatures	41
Amendment No.1 to Amended Credit Agreement
Certification of PEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of PEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


*		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

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 service to our customers. The fees or rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.

Our strategy is to protect and enhance the value of our transmission and storage business by:

	•		Successfully recontracting expiring transportation capacity;

	•		Developing storage capacity to serve our market area;

	•		Focusing on cost efficiencies, especially fuel use;

	•		Successfully completing expansion projects; and

	•		Attracting new supply and transporting natural gas to new markets.

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

The EPNG System. The EPNG system consists of approximately 10,300 miles of pipeline with a winter sustainable west-flow capacity of 4,850 MMcf/d and approximately 800 MMcf/d of east-end deliverability. During 2006, 2005 and 2004, average throughput was 4,179 BBtu/d, 4,053 BBtu/d and 4,074 BBtu/d. This system delivers natural gas from the San Juan, Permian and Anadarko basins 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 a design capacity of approximately 407 MMcf/d. During 2006, 2005 and 2004, average throughput was 461 BBtu/d (including 385 BBtu/d transported for the EPNG system), 161 BBtu/d and 161 BBtu/d. This system connects with the EPNG system near Cadiz, California, the EPNG and Transwestern systems at Topock, Arizona and the Kern River Gas Transmission Company system in California. This system also extends to customers in the vicinity of Bakersfield, California.

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

Markets and Competition

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

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

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

We provide transportation services in the southwestern U.S. and to the Mexican border through connections to other pipelines. These have recently been among the fastest growing regions in the U.S. and in Mexico; therefore, the market demand for natural gas distribution as well as gas-fired electric generation capacity has experienced considerable growth in these areas. The combined capacity of all pipeline companies serving California, our largest market, is approximately 8.5 Bcf/d and we provide approximately 39 percent of this capacity. In 2006, the demand for interstate pipeline capacity to California averaged 5.2 Bcf/d, equivalent to approximately 61 percent of the total interstate pipeline capacity serving that state. Natural gas shipped to California on our system represented approximately 29 percent of the natural gas consumed in that state in 2006.

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

The following table details our customers, contracts and competition on our pipeline systems as of December 31, 2006:


Pipeline
System	Customer Information	Contract Information	Competition
EPNG	Approximately 160 firm and	Approximately 190 firm	EPNG faces competition in the
	interruptible customers	transportation contracts. Weighted	west and southwest from other
		average remaining contract term of	existing and proposed
		approximately four years.	pipelines, from California
			storage facilities, and
			alternative energy sources that
			are used to generate
			electricity such as
			hydroelectric, nuclear, wind,
			coal and fuel oil. In addition,
			construction of facilities to
			bring LNG into California and
			northern Mexico are underway.

	Major Customers:
	Southern California Gas Company(SoCal)
	(101 BBtu/d)	Expires in 2007.
	(187 BBtu/d)	Expires in 2009.
	(561 BBtu/d)	Expire in 2010-2011.

	Southwest Gas Corporation
	(11 BBtu/d)	Expires in 2008.
	(476 BBtu/d)	Expire in 2011-2015.

Mojave	Approximately 20 firm and	Approximately six firm	Mojave faces competition from
	interruptible customers	transportation contracts. Weighted	other existing and proposed
		average remaining contract term of	pipelines and alternative
		approximately seven years.	energy sources that are used to
			generate electricity such as
			hydroelectric, nuclear, wind,
			coal and fuel oil. In addition,
			construction of facilities to
			bring LNG into California and
			northern Mexico are underway.
	Major Customers:
	Los Angeles Department of Water and Power
	(50 BBtu/d)	Expires in 2007.
	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, 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 services;

	•		depreciation and amortization policies;

	•		acquisition and disposition of facilities; and

	•		initiation and discontinuation of services.

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

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

Environmental

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

Employees

As of February 21, 2007, we had approximately 810 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. Such forward-looking statements are based on assumptions and beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur or be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

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

Risks Related to Our Business

Our success depends on factors beyond our control.

Our business is the transportation and storage of natural gas for third parties. Our results of operations are driven by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volumes of natural gas we are able to transport and store depends on the actions of those third parties, and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably impact our ability to maintain or increase current throughput, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity:

	•		service area competition;

	•		expiration or turn back of significant contracts;

	•		changes in regulation and actions of regulatory bodies;

	•		weather conditions that impact throughput and storage levels;

	•		price competition;

	•		drilling activity and availability of natural gas;

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

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

	•		availability and increased cost of capital to fund ongoing maintenance and growth projects;

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

	•		adverse general economic conditions;

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

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

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

Our revenues are generated under transportation and storage contracts that expire periodically and must be renegotiated, extended or replaced. Although we actively pursue the renegotiation, extension or replacement of these contracts, we may not be able to extend or replace these contracts when they expire or may only be able to do so on terms that are not as favorable as existing contracts. If we are unable to renew, extend or replace these contracts or if we renew them on less favorable terms, we may suffer a material reduction in our revenues and earnings.

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

Fluctuations in energy commodity prices could adversely affect our business.

Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased natural gas 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 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 natural gas available for transmission and storage through our systems. We retain a fixed percentage of natural gas transported. This retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. Pricing volatility may, in some cases, impact the value of under or over recoveries of this retained natural gas, as well as imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters and our long-term recontracting efforts may be negatively impacted. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Fluctuations in energy prices are caused by a number of factors, including:

	•		regional, domestic and international supply and demand;

	•		availability and adequacy of transportation facilities;

	•		energy legislation;

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

	•		abundance of supplies of alternative energy sources; and

	•		political unrest among oil producing countries.

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

Our 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. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services. In setting authorized rates of return in recent FERC decisions, the FERC has utilized a proxy group of companies that includes local distribution companies that are not faced with as much competition or risk as interstate pipelines. The inclusion of these lower risk companies may create downward pressure on tariff rates when subjected to review by the FERC in future rate proceedings. Shippers on other pipelines have sought reductions from the FERC for the rates charged to their customers. If our tariff rates were reduced or redesigned in a future rate proceeding, our results of operations, financial position and cash flows could be materially adversely affected.

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

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

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

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

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

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

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

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

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

Although we believe we have established appropriate reserves for our environmental liabilities, we could be required to set aside additional amounts due to these uncertainties which could significantly impact our future results of operations, cash flows or financial position. For additional information concerning our environmental matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 6.

Our operations are subject to operational hazards and uninsured risks.

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

While we maintain insurance against many of these risks to the extent and in amounts we believe are reasonable, this insurance does not cover all risks. Many of our insurance coverages have material deductibles as well as limits on our maximum recovery. 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 regulatory agencies on a timely basis and on terms that are acceptable to us;

	•		the ability to obtain continued access to sufficient capital to fund expansion projects;

	•		potential changes in federal, state and local statutes and regulations, 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 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 or labor, or other factors beyond our control, that may be material;

	•		lack of anticipated future growth in natural gas supply; and

	•		lack of transportation, storage or throughput commitments.

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

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

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

Risks Related to Our Affiliation with El Paso

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

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

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso 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 B2 by Moody’s Investor Service and B by Standard & Poor’s. The ratings assigned to our senior unsecured indebtedness are currently rated Ba1 by Moody’s Investor Service and B+ by Standard & Poor’s. We and El Paso are on a positive outlook with these agencies. Downgrades of our or El Paso’s credit ratings could increase our cost of capital and collateral requirements, and could impede our access to capital markets.

El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated 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 company payables. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 10.

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

Under El Paso’s $1.75 billion credit agreement, our common stock and the common stock of several of our affiliates 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.

A default under El Paso’s $1.75 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 $1.75 billion credit agreement. We are only liable, however, for our borrowings under the credit agreement, which were zero at December 31, 2006. Under the credit agreement, a default by El Paso, or any other borrower could result in the acceleration of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of our future borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

Furthermore, the indentures governing some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. Therefore, if we borrow $25 million or more under El Paso’s $1.75 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 businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

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

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

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

PART II

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

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

We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. No common stock dividends were declared or paid in 2006 or 2005.

ITEM 6. SELECTED FINANCIAL DATA

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

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. Factors that could cause actual results to differ include those risks and uncertainties that are discussed in Part I, Item 1A, Risk Factors.

Overview

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

Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, market conditions, regulatory actions, competition, the creditworthiness of our customers and weather. On January 1, 2006, we adopted a fuel tracker on our EPNG system related to the actual costs of fuel lost and unaccounted for and other gas balancing costs, such as encroachments against our system gas supply and imbalance cash out price adjustments, with a true-up mechanism for amounts over or under retained. We believe this fuel tracker will reduce the future financial impacts of our operational gas costs.

Our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs, although at times, we discount these rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues. The weighted average remaining contract term for our contracts is approximately four years as of December 31, 2006.

We successfully recontracted approximately 85 percent of the 1,600 BBtu/d of capacity that expired in 2006 to various customers for terms ranging from one to three years. The remaining capacity that expired in 2006 was recontracted for terms less than one year. We attempt to sell all our capacity under long-term contracts and market any remaining open position under shorter terms as market demand permits. Beginning in 2007, approximately 81 percent of our firm contracts were long-term agreements and we are continuing to remarket our available capacity to serve either existing customers, electric merchant generators, California non-core customers or new customers. At this time, we are uncertain how much of the available capacity will be recontracted, and if so, at what rates and term.

Below is the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2006, including those with terms beginning in 2007 or later.


			Percent of Total				Percent of Total
	BBtu/d⁽¹⁾		Contracted Capacity		Reservation Revenue		Reservation Revenue
					(In millions)

2007		1,055		20	$	71		15
2008		1,079		21		85		18
2009		434		8		71		15
2010		341		7		37		7
2011		1,275		25		62		13
2012 and beyond		974		19		153		32

Total		5,158		100	$	479		100


⁽¹⁾		Excludes EPNG capacity on the Mojave system.

Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business. We believe EBIT is useful to our investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes and (iii) interest and debt expense. We exclude interest and debt expense from this measure so that investors may evaluate our operating results independently from 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 flow. Below is a reconciliation of EBIT to net income for the years ended December 31:


	2006			2005
	(In millions,
	except volumes)
Operating revenues	$	588		$	497
Operating expenses		(305	)		(335	)

Operating income		283			162
Other income, net		3			8

EBIT		286			170
Interest and debt expense		(95	)		(92	)
Affiliated interest income, net		53			32
Income taxes		(92	)		(46	)

Net income	$	152		$	64

Throughput volumes (BBtu/d)⁽¹⁾		4,255			4,214


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

The following items contributed to our overall EBIT increase of $116 million for the year ended December 31, 2006 as compared to 2005:


									EBIT
	Revenue		Expense			Other			Impact
			Favorable/(Unfavorable)
			(In millions)
EPNG reservation and other services revenues	$	77	$	—		$	—		$	77
Lower litigation accruals		—		42			—			42
Enron bankruptcy settlement		14		3			—			17
Lower general and administrative expense		—		10			—			10
Higher depreciation expense		—		(18	)		—			(18	)
Higher rights-of-way expense		—		(12	)		—			(12	)
Other⁽¹⁾		—		5			(5	)		—

Total impact on EBIT	$	91	$	30		$	(5	)	$	116


⁽¹⁾		Consists of individually insignificant items.

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

EPNG Reservation and Other Services Revenues. Our reservation and other services revenues on the EPNG pipeline system were higher for the year ended December 31, 2006 compared to 2005, primarily due to the combined effect of (i) the termination, effective December 31, 2005, of reduced tariff rates to certain customers under the terms of our FERC-approved systemwide capacity allocation proceeding, (ii) an increase in tariff rates, which were effective January 1, 2006 and subject to refund, and (iii) revenues from various interruptible services provided under our tariffs.

EPNG negotiated a settlement of the rate case which was filed with the FERC in December 2006. The settlement provides benefits for both EPNG and its customers for a three-year period ending December 31, 2008. We have reserved sufficient amounts to meet EPNG’s refund obligations under this settlement. Such refunds will be payable within 120 days after approval by the FERC. Under the terms of the settlement, EPNG is required to file a new rate case to be effective January 1, 2009. For a further discussion of EPNG’s rate case, see Item 8, Financial Statements and Supplementary Data, Note 6.

We periodically file for changes in our rates subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. Mojave is required to file for new rates to be effective in March 2007. We anticipate a decrease in Mojave’s rates resulting from a variety of factors, including a decline in rate base and various changes in rate design since the last rate case, although the impact is not yet determinable.

Lower Litigation Accruals. Our litigation accruals were lower during the year ended December 31, 2006 as compared to December 31, 2005, due to amounts accrued during 2005 for our outstanding legal claims. For a further discussion of our legal matters, see Item 8, Financial Statements and Supplementary Data, Note 6.

Enron Bankruptcy Settlement. During the third quarter of 2006, we recorded income of approximately $17 million, net of amounts potentially owed to certain customers as a result of the Enron bankruptcy settlement. We may receive additional amounts in the future as settlement proceeds are released by the Bankruptcy Court. For a further discussion of this matter, see Item 8, Financial Statements and Supplementary Data, Note 6.

Lower General and Administrative Expense. During the year ended December 31, 2006, our general and administrative expenses were lower than in 2005, primarily due to a decrease in accrued benefits costs, lower insurance and lower allocated costs from El Paso.

Higher Depreciation Expense. On January 1, 2006, the effective date of EPNG’s rate case, EPNG began applying higher depreciation rates to its property, plant and equipment which, along with an increase in depreciable plant, resulted in higher depreciation expense for the year ended December 31, 2006.

Higher Rights-Of-Way Expense. EPNG’s rights-of-way expense was higher for the year ended December 31, 2006 as a result of the interim agreement reached with the Navajo Nation in January 2006. For a further discussion of this matter, see Item 8, Financial Statements and Supplementary Data, Note 6.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, 2006, was $21 million higher than in 2005 due to higher average short-term interest rates and higher average advances to El Paso under its cash management program. The average short-term interest rate increased from 4.2% in 2005 to 5.7% in 2006. In addition, the average advances due from El Paso of $779 million in 2005 increased to $947 million in 2006.

Income Taxes


	Year Ended
	December 31,
	2006			2005
	(In millions,
	except for rates)
Income taxes	$	92		$	46
Effective tax rate		38	%		42	%

Our effective tax rate for 2006 was different than the statutory rate of 35 percent primarily due to the effect of state income taxes. Our effective tax rate for 2005 was different than the statutory rate of 35 percent primarily due to the effect of state income taxes and

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

Liquidity and Capital Expenditures

Liquidity Overview

Our liquidity needs are provided by cash flows from operating activities. In addition, we participate in El Paso’s cash management program. Under El Paso’s cash management program, depending on whether we have short-term cash surpluses or requirements, we either provide cash to El Paso or El Paso provides cash to us in exchange for an affiliated note receivable or payable. We have historically provided cash advances to El Paso, and we reflect these advances as investing activities in our statement of cash flows. At December 31, 2006, we had a note receivable from El Paso of approximately $1.1 billion that is due upon demand. However, we do not anticipate settlement within the next twelve months. See Item 8, Financial Statements and Supplementary Data, Note 10, for a further discussion of El Paso’s cash management program.

In addition to the cash management program, we are eligible to borrow amounts available under El Paso’s $1.75 billion credit agreement. We are only liable for amounts we directly borrow. We had no borrowings at December 31, 2006 under the credit agreement. At December 31, 2006, there was approximately $0.6 billion of borrowing capacity available to all eligible borrowers under the $1.75 billion credit agreement. For a further discussion of this credit agreement, see Item 8, Financial Statements and Supplementary Data, Note 5. We believe that cash flows from operating activities and amounts available under El Paso’s cash management program and its $1.75 billion credit agreement, if necessary, will be adequate to meet our short-term capital requirements for our existing operations.

El Paso recently announced that it will pursue the formation of a master limited partnership in 2007 to enhance the value and financial flexibility of its pipeline assets and to provide a lower cost source of capital for new projects.

Capital Expenditures

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


	2006		2005
	(In millions)
Maintenance	$	94	$	106
Expansion/Other		49		34

Total	$	143	$	140

We have relatively high maintenance capital requirements over the next three years due, in part, to the requirements of the 2002 Pipeline Safety Act and our continued commitment to maintain and improve the total integrity of our pipeline systems. Under our current plan, we expect to spend between approximately $123 million and $128 million in each of the next three years for capital expenditures to maintain the integrity of our pipelines, to comply with clean air regulations and to ensure the safe and reliable delivery of natural gas to our customers. In addition, we have budgeted to spend between approximately $24 million and $74 million in each of the next three years to expand the capacity of our pipeline systems contingent, in part, upon customer commitments to the projects. We expect to fund these capital expenditures through a combination of internally generated funds and, if necessary, repayment by El Paso of amounts advanced to El Paso under its cash management program.

Commitments and Contingencies

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

New Accounting Pronouncements Issued But Not Yet Adopted

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk is exposure to changing interest rates. The table below shows the carrying value and related weighted average effective interest rates of our interest bearing securities by expected maturity dates and the fair value of those securities. At December 31, 2006, the fair values of our fixed rate long-term debt securities have been estimated based on quoted market prices for the same or similar issues.


	December 31, 2006										December 31, 2005
	Expected Fiscal Year of
	Maturity of Carrying Amounts
									Fair		Carrying
	2010			Thereafter			Total		Value		Amount		Fair Value
	(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate	$	352		$	759		$	1,111	$	1,273	$	1,110	$	1,220
Average effective interest rate		7.9	%		8.3	%

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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 sheet of El Paso Natural Gas Company (the Company) as of December 31, 2006, and the related consolidated statements of income, stockholder’s equity, and cash flows for the year then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a) for the year ended December 31, 2006. 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 audit.

We conducted our audit 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 audit 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 audit provides 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, 2006, and the consolidated results of its operations and its cash flows for the year then ended, 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 1, 2005, the Company adopted the Federal Energy Regulatory Commission’s accounting release related to pipeline assessment costs and effective December 31, 2006, the Company adopted the recognition provisions of Statement of Financial Accounting Standards No. 158, Employers’ 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, 2007

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of
El Paso Natural Gas Company:

In our opinion, the consolidated financial statements listed in the Index appearing under Item 15(a)(1), present fairly, in all material respects, the consolidated financial position of El Paso Natural Gas Company and its subsidiaries (the “Company”) at December 31, 2005, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2005 listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 28, 2006

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


	Year Ended December 31,
	2006			2005			2004
Operating revenues	$	588		$	497		$	508

Operating expenses
Operation and maintenance		183			232			166
Depreciation, depletion and amortization		92			74			72
Taxes, other than income taxes		30			29			28

		305			335			266

Operating income		283			162			242
Other income, net		3			8			7
Interest and debt expense		(95	)		(92	)		(92	)
Affiliated interest income, net		53			32			19

Income before income taxes		244			110			176
Income taxes		92			46			58

Net income	$	152		$	64		$	118

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)


	December 31,
	2006			2005
ASSETS
Current assets
Cash and cash equivalents	$	—		$	—
Accounts and notes receivable
Customer, net of allowance of $5 in 2006 and $18 in 2005		81			114
Affiliates		5			4
Materials and supplies		40			41
Deferred income taxes		42			14
Restricted cash		—			17
Other		6			3

Total current assets		174			193

Property, plant and equipment, at cost		3,557			3,417
Less accumulated depreciation, depletion and amortization		1,251			1,193

Total property, plant and equipment, net		2,306			2,224

Other assets
Note receivable from affiliate		1,070			872
Other		81			89

		1,151			961

Total assets	$	3,631		$	3,378


LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	59		$	84
Affiliates		17			6
Other		9			17
Taxes payable		87			27
Accrued interest		27			25
Accrued liabilities		84			50
Other		21			12

Total current liabilities		304			221

Long-term debt		1,111			1,110

Other liabilities
Deferred income taxes		405			364
Other		85			105

		490			469


Commitments and contingencies
Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding		—			—
Additional paid-in capital		1,268			1,268
Retained earnings		462			310
Accumulated other comprehensive loss		(4	)		—

Total stockholder’s equity		1,726			1,578

Total liabilities and stockholder’s equity	$	3,631		$	3,378

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)


	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities
Net income	$	152		$	64		$	118
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		92			74			72
Deferred income taxes		15			7			155
Other non-cash income items		(1	)		—			—
Asset and liabilities changes
Western Energy Settlement liability		—			—			(538	)
Accounts receivable		35			(34	)		(5	)
Accounts payable		(17	)		41			4
Taxes receivable		—			102			(102	)
Taxes payable		55			16			(93	)
Other, net		(9	)		34			(47	)

Net cash provided by (used in) operating activities		322			304			(436	)


Cash flows from investing activities
Additions to property, plant and equipment		(143	)		(141	)		(148	)
Net change in note receivable from affiliate		(198	)		(142	)		49
Net change in restricted cash		17			(17	)		443
Proceeds from the sale of assets		2			2			1
Other		—			—			(7	)

Net cash provided by (used in) investing activities		(322	)		(298	)		338


Cash flows from financing activities
Payments to retire debt		—			(7	)		—
Capital contributions		—			—			73

Net cash provided by (used in) financing activities		—			(7	)		73


Net change in cash and cash equivalents		—			(1	)		(25	)
Cash and cash equivalents
Beginning of period		—			1			26

End of period	$	—		$	—		$	1

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(In millions, except share amounts)


									Accumulated
					Additional				other			Total
	Common stock				paid-in		Retained		comprehensive			stockholder’s
	Shares		Amount		capital		earnings		loss			equity
January 1, 2004		1,000	$	—	$	1,194	$	128	$	—		$	1,322
Net income								118					118
Western Energy Settlement contribution						73							73

December 31, 2004		1,000		—		1,267		246		—			1,513
Net income								64					64
Allocated tax benefit of El Paso equity plans						1							1

December 31, 2005		1,000		—		1,268		310		—			1,578
Net income								152					152
Adoption of SFAS No. 158, net of income taxes of $3										(4	)		(4	)

December 31, 2006		1,000	$	—	$	1,268	$	462	$	(4	)	$	1,726

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 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. Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles and we include the accounts of all majority owned and controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment.

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 the financial statements. Actual results can, and often do, differ from those estimates.

Regulated Operations

Our natural gas transmission systems 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 apply the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, an equity return component on regulated capital projects and certain items included in, or expected to be included in, future rates.

Cash and Cash Equivalents

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

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

Allowance for Doubtful Accounts

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

Materials and Supplies

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

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 of natural gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up in-kind, subject to the terms of our tariff.

Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported in our balance sheet as either trade accounts payable or accounts payable to affiliates. In addition, we classify all imbalances as current as we expect to settle them within a year.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at 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, an interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items. Prior to December 1, 2005, we capitalized certain costs incurred related to our pipeline integrity programs as part of our property, plant and equipment. Beginning December 1, 2005, we began expensing certain of these costs based on FERC guidance. During the year ended December 31, 2006, we expensed approximately $7 million of pipeline integrity program costs, approximately $5 million of which was a result of the adoption of this accounting release.

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. For certain general plant and rights-of-way, we depreciate the asset to zero. The majority of our property, plant and equipment is on our EPNG system. Prior to EPNG’s rate case filed in June 2005, the range of our depreciation rates, including those for the Mojave system, varied from two percent to 33 percent per year. Using these rates, the remaining depreciable lives of our assets ranged from three to 63 years. In December 2006, we filed a proposed rate case settlement with the FERC, which included a further modification of our depreciation rates resulting in depreciation rates ranging from one to 20 percent and the depreciable lives ranging from five to 92 years for assets on our EPNG system. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation service and storage rates.

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

Included in our property balances are additional acquisition costs of $152 million which represent the excess of allocated purchase costs over the historical costs of the facilities. These costs are amortized on a straight-line basis over 36 years, and we do not recover these excess costs in our rates. At December 31, 2006 and 2005, we had unamortized additional acquisition costs of $63 million and $64 million.

At December 31, 2006 and 2005, we had approximately $89 million and $82 million of construction work in progress included in our property, plant and equipment.

We capitalize a carrying cost (an allowance for funds used during construction) on funds related to our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs on debt amounts capitalized during the years ended December 31, 2006, 2005 and 2004 were $1 million, $3 million and $3 million. These debt amounts are included as a reduction to interest and debt expense in our income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized during the years ended December 31, 2006, 2005 and 2004, were $2 million, $5 million and $4 million (exclusive of any tax related impacts). These equity amounts are included as other non-operating income on our income statement. Capitalized carrying costs for debt and equity financed construction are reflected as an increase in the cost of the asset on our balance sheet.

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 their ability to generate future cash flows on an undiscounted basis. If an impairment is indicated or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to their estimated fair value. 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 sales, among other factors.

Revenue Recognition

Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. Gas not used in operations is based on the volumes of natural gas we are allowed to retain relative to the amounts we use for operating purposes. Prior to January 1, 2006, we recognized revenue on gas not used in operations on our EPNG system when the volumes were retained under our tariff. On January 1, 2006, we adopted a fuel tracker on our EPNG system related to the actual costs of fuel, lost and unaccounted for and other gas balancing costs, such as encroachments against our system gas supply and imbalance cash out price adjustments, with a true-up mechanism for amounts over or under retained. 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 environmental liabilities at their undiscounted amounts in our balance sheet in other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period 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 lower 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.

Accounting for Asset Retirement Obligations

We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for legal obligations associated with the replacement, removal and retirement of our long-lived assets. Our asset retirement liabilities are recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the long-lived asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our income statement. Because we believe it is probable that we will recover certain of these costs through our rates, we have recorded an asset (rather than expense) associated with certain of the depreciation of the property, plant and equipment and certain of the 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 pipeline and storage system assets have indeterminate lives. Accordingly, our asset retirement liabilities as of December 31, 2006 and 2005, were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Pension and Other Postretirement Benefits

In December 2006, we adopted the 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). Under SFAS No. 158, we record an asset or liability for our pension and other postretirement benefit plans based on their funded or unfunded status. We also record deferred amounts related to unrealized gains and losses or changes in actuarial assumptions in accumulated other comprehensive income, a component of stockholder’s equity, until those gains and losses are recognized in the income statement. For a further discussion of our adoption of SFAS No. 158, see
Note 7.

Evaluation of Prior Period Misstatements in Current Financial Statements

In December 2006, we adopted the provisions of the Securities and Exchange Commission’s (SEC) Staff Accounting Bulletin (SAB) No. 108. Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how to evaluate the impact of financial statement misstatements from prior periods that have been identified in the current year. The adoption of these provisions did not have any material impact on our financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2006, the following accounting standards and interpretations had not yet been adopted by us.

Accounting for Uncertainty in Income Taxes. In July 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes. FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and all years where the statute of limitations has not expired. FIN No. 48 requires companies to meet a more likely than not threshold (i.e. greater than a 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 ultimate settlement. The cumulative effect of applying this interpretation will be recorded as an adjustment to the beginning balance of retained earnings, or other components of stockholder’s equity as appropriate, in the period of adoption. This interpretation is effective for fiscal years beginning after December 15, 2006, and we do not anticipate that it will have a material impact on our financial statements.

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which provides guidance on measuring the fair value of assets and liabilities in the financial statements. We will be required to adopt the provisions of this standard no later than in 2008, and are currently evaluating the impact, if any, that it will have on our financial statements.

Measurement Date of Other Postretirement Benefits. In December 2006, we adopted the recognition provisions of SFAS No. 158. This standard will also require us to change the measurement date of our other postretirement benefit plans from September 30, the date we currently use, to December 31 beginning in 2008. We are evaluating the impact, if any, that the measurement date provisions of this standard will have on our financial statements.

2. Income Taxes

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


	2006		2005		2004
	(In millions)
Current
Federal	$	66	$	35	$	(99	)
State		11		4		2

		77		39		(97	)


Deferred
Federal		13		5		159
State		2		2		(4	)

		15		7		155

Total income taxes	$	92	$	46	$	58

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:


	2006			2005			2004
	(In millions, except for rates)
Income taxes at the statutory federal rate of 35%	$	85		$	39		$	62
Increase (decrease)
State income taxes, net of federal income tax effect		8			4			6
State tax valuation allowance — Western Energy Settlement		—			—			(6	)
Non-deductible expenses		—			3			—
Other		(1	)		—			(4	)

Income taxes	$	92		$	46		$	58

Effective tax rate		38	%		42	%		33	%

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


	2006		2005
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	448	$	427
Employee benefits and deferred compensation obligations		20		27
Regulatory and other assets		41		45

Total deferred tax liability		509		499


Deferred tax assets
U.S. net operating loss and tax credit carryovers		80		81
Other liabilities		66		68

Total deferred tax asset		146		149

Net deferred tax liability	$	363	$	350

Tax Credits and Carryovers. As of December 31, 2006, we had approximately $18 million of alternative minimum tax credits that carryover indefinitely. We also have approximately $179 million of net operating loss carryovers that expire between 2018 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.

Valuation Allowances. During 2003, we maintained a valuation allowance on deferred tax assets related to our ability to realize state tax benefits from the deduction of the charge we took related to the Western Energy Settlement. During 2004, we evaluated this allowance and determined that these state tax benefits would be fully realized. Consequently, we reversed this valuation allowance. Net of federal taxes, this benefit totaled approximately $6 million.

3. Financial Instruments

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


	2006				2005
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(In millions)
Balance sheet financial instruments:
Long-term debt⁽¹⁾	$	1,111	$	1,273	$	1,110	$	1,220


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

As of December 31, 2006 and 2005, 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.

4. Regulatory Assets and Liabilities

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


Description	2006		2005
	(In millions)
Non-current regulatory assets
Gross-up of deferred taxes on capitalized funds used during construction	$	20	$	19
Unamortized loss on reacquired debt		16		18
Postretirement benefits		9		9
Deferred fuel variance		6		—
Under-collected state income taxes		3		7
Other		4		3

Total non-current regulatory assets⁽¹⁾	$	58	$	56


Current regulatory liabilities	$	3	$	1
Non-current regulatory liabilities
Property and plant depreciation		47		41
Imbalance cashouts		4		—
Excess deferred federal income taxes		2		2

Total regulatory liabilities⁽¹⁾	$	56	$	44


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

5. Debt and Credit Facilities

Debt

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


	2006		2005
	(In millions)
7.625% Notes due August 2010	$	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

		1,115		1,115
Less: Unamortized discount		4		5

Total long-term debt	$	1,111	$	1,110

We have the ability to call $655 million of our notes due in August 2010 and June 2032 at any time prior to their stated maturity date. If we were to exercise our option to call these notes, we would be obligated to pay principal, accrued interest and potentially a make-whole premium to redeem the debt.

Credit Facilities

In July 2006, El Paso entered into a new $1.75 billion credit agreement, consisting of a $1.25 billion three-year revolving credit facility and a $500 million five-year deposit letter of credit facility. We are an eligible borrower under the credit agreement and are only liable for amounts we directly borrow. We had no borrowings at December 31, 2006 under the credit agreement. Our common stock and the common stock of several of our affiliates are pledged as collateral under the credit agreement. At December 31, 2006, there was approximately $0.6 billion of borrowing capacity available to all eligible borrowers under the $1.75 billion credit agreement.

Under the $1.75 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), the most restrictive of which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; (vi) potential limitations on our ability to participate in the El Paso’s cash management program discussed in Note 10; and (vii) limitations on our ability to prepay debt. For the year ended December 31, 2006, we were in compliance with our debt-related covenants.

Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $25 million cross-acceleration clause.

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. In 2004, the courts twice dismissed the lawsuit. The plaintiffs have appealed that dismissal to the U.S. Court of Appeals for the Ninth Circuit. The appeal has been fully briefed. Our costs and legal exposure related to this lawsuit are not currently determinable.

Carlsbad. In August 2000, a main transmission line owned and operated by us ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. In June 2001, the U.S. Department of Transportation’s (DOT) Office of Pipeline Safety issued a Notice of Probable Violation and Proposed Civil Penalty to us. The Notice alleged violations of DOT regulations, proposed fines totaling $2.5 million and proposed corrective actions. In April 2003, the National Transportation Safety Board issued its final report on the rupture, finding that the rupture was probably caused by internal corrosion that was not detected by our corrosion control program. In December 2003, this matter was referred by the DOT to the Department of Justice (DOJ). As a result of the referral to the DOJ, the amount of the proposed fine may increase substantially from the DOT’s originally proposed fine of $2.5 million and may also involve implementation of additional operational and safety measures. Negotiations with the DOJ are continuing.

In addition, a lawsuit entitled Baldonado et al. v. EPNG was filed in June 2003, in state court in Eddy County, New Mexico, on behalf of 26 firemen and emergency medical service personnel who responded to the fire and who allegedly have suffered psychological trauma. This case was dismissed by the trial court, but was appealed to the New Mexico Court of Appeals. In June 2006, the New Mexico Court of Appeals affirmed the dismissal of the plaintiff’s claims for negligent infliction of emotional distress but reversed the dismissal of the claims for intentional infliction of emotional distress. The New Mexico Supreme Court has agreed to review the actions by the Court of Appeals. Our costs and legal exposure related to the Baldonado lawsuit are currently not determinable, however, we believe these matters will be fully covered by insurance.

Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act, which has 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 May 2005, a representative appointed by the court issued a recommendation to dismiss most of the actions. In October 2006, the U.S. District Judge issued an order dismissing all measurement 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 plaintiffs seek 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 this lawsuit and claim are not currently determinable.

Bank of America. We were a named defendant, along with Burlington Resources, Inc. (Burlington), in two class action lawsuits styled Bank of America, et al. v. El Paso Natural Gas Company, et al., and Deane W. Moore, et al. v. Burlington Northern, Inc., et al., each filed in 1997 in the District Court of Washita County, Oklahoma and subsequently consolidated by the court. The consolidated class action has been settled. Our settlement contribution was approximately $30 million plus interest, which was fully accrued and paid on August 1, 2006. A third action, styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, L.P., was filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting similar claims as to specified shallow wells in Oklahoma, Texas and New Mexico. All the claims in this action have also been settled subject to court approval, after a fairness hearing yet to be scheduled. We filed an action styled El Paso Natural Gas Company v. Burlington Resources, Inc. and Burlington Resources Oil and Gas Company, L.P. against Burlington in state court in Harris County, Texas relating to the indemnity issues between Burlington and us. That action was stayed by agreement of the parties and settled in November 2005, subject to all the underlying class settlements being finalized and approved by the court.

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

For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. As further information becomes available, or other relevant developments occur, we adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate. At December 31, 2006, we had accrued approximately $16 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, 2006, we had accrued approximately $24 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs. This accrual includes $21 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. We estimate that our exposure could be as high as $45 million. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Below is a reconciliation of our accrued liability from January 1, 2006 to December 31, 2006 (in millions):


Balance at January 1, 2006	$	29
Additions/adjustments for remediation activities		(1	)
Payments for remediation activities		(4	)

Balance at December 31, 2006	$	24

For 2007, we estimate that our total remediation expenditures will be approximately $4 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 four active sites under CERCLA or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2006, we have estimated our share of the remediation costs at these sites to be between $12 million and $16 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

State of Arizona Chromium Review. In April 2004, the State of Arizona’s Department of Environmental Quality (ADEQ) requested information from us regarding the historical use of chromium in our operations. By June 2004, we had responded fully to the request. We are currently working with the State of Arizona on this matter and in 2006, we commenced a study of our facilities in Arizona to determine if there are any issues concerning the usage of chromium. We also studied our facilities on tribal lands in Arizona and New Mexico and our facility at the El Paso Station in El Paso, Texas. Of the 12 sites that were studied, nine were found not to have chromium contamination above regulatory thresholds. Of the three remaining sites, one was already enrolled in Arizona’s Voluntary Remediation Program (VRP), one will be entered into the VRP as soon as practicable, and additional environmental studies will be conducted at the last site to determine if the environmental conditions at the site warrant entering it into the VRP as well.

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

Rates and Regulatory Matters

Rate Case. In June 2005, we filed a rate case with the FERC proposing an increase in revenues of 10.6 percent or $56 million annually over current tariff rates, new services and revisions to certain terms and conditions of existing services on our EPNG system. On January 1, 2006, the rates became effective, subject to refund. In March 2006, the FERC issued an order that generally approved our proposed new services, which were implemented on June 1, 2006. In December 2006, we filed a settlement with the FERC. The

settlement provided benefits for both us and our customers for a three year period ending December 31, 2008. Only one party in the rate case contested the settlement. The Administrative Law Judge has certified the settlement to the FERC finding that the settlement could be approved for all parties or in the alternative, that the contesting party could be severed from the settlement. We have reserved sufficient amounts to meet EPNG’s refund obligations under the settlement. Such refunds will be payable within 120 days after approval by the FERC.

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

Other Matters

Navajo Nation. Approximately 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on lands held in trust by the United States for the benefit of the Navajo Nation. Our rights-of-way on lands crossing the Navajo Nation are the subject of a pending renewal application filed in 2005 with the Department of the Interior’s Bureau of Indian Affairs. An interim agreement with the Navajo Nation expired at the end of December 2006. Negotiations on the terms of the long-term agreement are continuing. In addition, we continue to preserve other legal, regulatory and legislative alternatives, which includes continuing to pursue our application with the Department of the Interior for renewal of our rights-of-way on Navajo Nation lands. It is uncertain whether our negotiation, or other alternatives, will be successful, or if successful, what the ultimate cost will be of obtaining the rights-of-way and whether we will be able to recover these costs in our rates.

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

Enron Bankruptcy. In December 2001, Enron Corp. (Enron), and a number of its subsidiaries including Enron North America Corp. (ENA) and Enron Power Marketing, Inc., filed for Chapter 11 bankruptcy protection in the United States Bankruptcy Court for the Southern District of New York. ENA had transportation contracts on our system. The transportation contracts were rejected and our proof of claim was filed in the amount of approximately $128 million, which included $18 million for amounts due for services provided through the date the contracts were rejected and $110 million for claims arising after the date the contracts were rejected. In August 2006, the Bankruptcy Court approved a claim of $58 million that is guaranteed by Enron up to $25 million. In October 2006, we received cash of approximately $21 million and 76,000 shares of Portland General Electric Company common stock in connection with the resolution of certain claims we filed in the Enron bankruptcy proceeding. We may receive additional amounts in the future as settlement proceeds are released by the Bankruptcy Court.

Capital Commitments

At December 31, 2006, we had capital commitments of approximately $17 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

We lease property, facilities and equipment under various operating leases. Minimum future annual rental commitments on operating leases as of December 31, 2006, were as follows:


Year Ending
December 31,	(In millions)
2007	$	8
2008		2
2009		2
2010		1

Total	$	13

Our minimum future rental commitments have not been reduced by minimum sublease rentals of approximately $1 million due to us in the future under noncancelable subleases.

Included in our minimum future rental commitments above is our remaining obligation under a terminated lease agreement. Rental expense on our operating leases for each of the years ended December 31, 2006, 2005 and 2004 was $17 million, $6 million and $3 million. These amounts include our share of rent allocated to us from El Paso.

Other Commercial Commitments

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

Guarantees

We are or have been involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. As of December 31, 2006, we had approximately $11 million of financial and performance guarantees not otherwise reflected in our financial statements.

7. Retirement Benefits

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

Postretirement Benefits. We provide medical benefits for a closed group of employees who retired on or before March 1, 1986, and limited postretirement life insurance for employees who retired after January 1, 1985. As such, our obligation to accrue for other postretirement employee benefits (OPEB) is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. The medical plan is pre-funded to the extent employer contributions are recoverable through rates. To the extent actual OPEB costs differ from amounts recovered in rates, a regulatory asset or liability is recorded. We expect to make no contributions to our postretirement benefit plan in 2007.

On December 31, 2006, we adopted the provisions of SFAS No. 158, and upon adoption reflected the assets related to our postretirement benefit plan based on its funded status. The adoption of this standard decreased our other non-current assets by approximately $7 million, our other non-current deferred tax liabilities by approximately $3 million, and our accumulated other comprehensive income by approximately $4 million. We anticipate that less than $1 million of our accumulated other comprehensive loss will be recognized as a part of our net periodic benefit cost in 2007.

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


	2006			2005
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	93		$	85
Interest cost		5			4
Actuarial (gain) loss		(4	)		10
Benefits paid		(6	)		(6	)

Accumulated postretirement benefit obligation at end of period	$	88		$	93


Change in plan assets:
Fair value of plan assets at beginning period	$	90		$	77
Actual return on plan assets		9			8
Employer contributions		3			11
Benefits paid		(6	)		(6	)

Fair value of plan assets at end of period	$	96		$	90


Reconciliation of funded status:
Fair value of plan assets at September 30	$	96		$	90
Less: accumulated postretirement benefit obligation end of period		88			93

Funded status at September 30		8			(3	)
Fourth quarter contributions		—			3
Unrecognized actuarial losses ⁽¹⁾		—			15

Net asset at December 31	$	8		$	15


⁽¹⁾		Amounts were reclassified to accumulated other comprehensive income upon adoption of SFAS No. 158 in 2006.

Expected Payment of Future Benefits. As of December 31, 2006, we expect the following payments under our plans (in millions):


Year Ending
December 31,
2007	$	9
2008		9
2009		9
2010		8
2011		8
2012 -2016		37

Total	$	80

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


	2006			2005			2004
	(In millions)
Interest cost	$	5		$	4		$	6
Expected return on plan assets		(6	)		(5	)		(5	)
Amortization of net actuarial loss		1			—			2
Amortization of transition obligation		—			8			8

Net postretirement benefit cost	$	—		$	7		$	11

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations for 2006, 2005 and 2004:


	2006		2005		2004
	(Percent)
Assumptions related to benefit obligations at September 30:
Discount rate		5.50		5.25
Assumptions related to benefit costs at December 31:
Discount rate		5.25		5.75		6.00
Expected return on plan assets⁽¹⁾		8.00		7.50		7.50


⁽¹⁾		The expected return on plan assets is a pre-tax rate (before a tax rate ranging from 15 percent to 16 percent on postretirement benefits) that is primarily based on an expected risk-free investment return, adjusted for historical risk premiums and specific risk adjustments associated with our debt and equity securities. These expected returns were then weighted based on the target asset allocations of our investment portfolio.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 10.3 percent in 2006, 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 2006 or 2005. A one-percentage point change in these trends would have the following increase (decrease) on our accumulated postretirement benefit obligation as of September 30:


	2006			2005
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	6		$	7
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(5	)	$	(6	)

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


	Actual		Actual
Asset Category	2006		2005
	(Percent)
Equity securities		65		65
Debt securities		35		34
Other		—		1

Total		100		100

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

The target allocation for the invested assets is 65 percent equity and 35 percent fixed income. Other assets are held in cash for payment of benefits upon presentment. Any El Paso stock held by the plan is held indirectly through investments in mutual funds.

8. Transactions with Major Customers

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


	2006⁽¹⁾		2005		2004
	(In millions)
SoCal	$	145	$	156	$	157
Southwest Gas Corporation		66		51		51


⁽¹⁾		Revenues reflect rates subject to refund.

9. Supplemental Cash Flow Information

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


	2006		2005			2004
	(In millions)
Interest paid, net of capitalized interest	$	93	$	93		$	92
Income tax payments (refunds)		22		(93	)		98

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. We have historically provided cash to El Paso in exchange for an affiliated note receivable that is due upon demand. However, we do not anticipate settlement within the next twelve months and therefore, classified this receivable as non-current on our balance sheets. At December 31, 2006 and 2005, we had a note receivable from El Paso of approximately $1.1 billion and $872 million. The interest rate at December 31, 2006 and 2005, was 5.3% and 5.0%.

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. We had income taxes payable of $81 million and $26 million at December 31, 2006 and 2005. The majority of these balances will become payable to or receivable from El Paso. See Note 1 for a discussion of our tax accrual policy.

Other Affiliate Balances. At December 31, 2006 and 2005, we had contractual deposits with our affiliates of $7 million and $6 million, included in other current liabilities on our balance sheets.

Affiliate Revenues and Expenses. We provide natural gas transportation services to an affiliate under long-term contracts. We entered into these contracts in the normal course of business and the services are based on the same terms as non-affiliates.

El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are also allocated costs from Tennessee Gas Pipeline Company (TGP) associated with our pipeline services. We also allocate costs to Colorado Interstate Gas Company for its share of our pipeline services. The allocations from El Paso and TGP are based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll.

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


	2006		2005		2004
	(In millions)
Revenues from affiliates	$	17	$	17	$	18
Operation and maintenance expenses from affiliates		52		67		62
Reimbursements of operating expenses charged to affiliates		16		16		14

11. Supplemental Selected Quarterly Financial Information (Unaudited)

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


	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In millions)
2006
Operating revenues	$	153	$	142	$	155	$	138	$	588
Operating income		72		62		80		69		283
Net income		38		33		45		36		152

2005
Operating revenues	$	123	$	123	$	125	$	126	$	497
Operating income		47		57		19		39		162
Net income		19		27		5		13		64

SCHEDULE II

EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2006, 2005 and 2004
(In millions)


	Balance at		Charged to						Balance
	Beginning		Costs and						at End
Description	of Period		Expenses			Deductions			of Period
2006
Allowance for doubtful accounts	$	18	$	(4	)	$	(9	)	$	5
Legal reserves		45		1			(30	)		16
Environmental reserves		29		(1	)		(4	)		24
Regulatory reserves		—		65	⁽¹⁾		—			65

2005
Allowance for doubtful accounts	$	18	$	—		$	—		$	18
Legal reserves		3		42	⁽¹⁾		—			45
Environmental reserves		32		1			(4	)		29

2004
Allowance for doubtful accounts	$	18	$	—		$	—		$	18
Valuation allowance on deferred tax assets		6		—			(6	)		—
Legal reserves		541		—			(538	)⁽²⁾		3
Environmental reserves		28		7			(3	)		32
Regulatory reserves		12		—			(12	)		—


⁽¹⁾		For a discussion of these matters, see Item 8, Financial Statements and Supplementary Data, Note 6.

⁽²⁾		Relates to payments made pursuant to the Western Energy Settlement.

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

As previously reported in our Current Report on Form 8-K dated April 18, 2006, as amended on April 24 and May 8, 2006, we appointed Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2006 and dismissed PricewaterhouseCoopers LLP. During the fiscal years ended December 31, 2006 and 2005, there were no disagreements with our former accountant or reportable events as defined in Item 304(a)(1)(iv) and Item 304(a)(1)(v) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2006, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures, as defined by the Securities Exchange Act of 1934, as amended. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. 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 error 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. Based on the results of this evaluation, our President and Chief Financial Officer concluded that our disclosure controls and procedures are effective at December 31, 2006.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the fourth quarter of 2006.

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, 2006 and 2005 of $678,000 and $800,000 were for professional services rendered by Ernst & Young LLP and PricewaterhouseCoopers LLP, respectively for the audits of the consolidated financial statements of El Paso Natural Gas Company.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firms for the years ended December 31, 2006 and 2005.

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 2007 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		17
Consolidated Statements of Income		19
Consolidated Balance Sheets		20
Consolidated Statements of Cash Flows		21
Consolidated Statements of Stockholder’s Equity		22
Notes to Consolidated Financial Statements		23

2. Financial statement schedules.

Schedule II — Valuation and Qualifying Accounts

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 28^th day of February 2007.

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	February 28, 2007
James J. Cleary	(Principal Executive Officer)

/S/ JOHN R. SULT	Senior Vice President,	February 28, 2007
John R. Sult	Chief Financial Officer and Controller
	(Principal Accounting and Financial Officer)

/S/ JAMES C. YARDLEY	Chairman of the Board	February 28, 2007
James C. Yardley

/S/ DANIEL B. MARTIN	Senior Vice President and Director	February 28, 2007
Daniel B. Martin

/S/ THOMAS L. PRICE	Vice President and Director	February 28, 2007
Thomas L. Price

EL PASO NATURAL GAS COMPANY

EXHIBIT INDEX
December 31, 2006

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


Exhibit
Number		Description

3.A		Restated Certificate of Incorporation dated April 8, 2003 (Exhibit 3.A to our 2003 Second Quarter Form 10-Q).

3.B		By-laws dated June 24, 2002 (Exhibit 3.B to our 2002 Form 10-K).

4.A		Indenture dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.), as Trustee, (Exhibit 4.A to our 2004 Form 10-K).

4.B		Indenture dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee, (Exhibit 4.B to our 2004 Form 10-K).

4.C		Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee, (Exhibit 4.1 to our Form 8-K filed July 23, 2003).

10.A		Amended and Restated Credit Agreement dated as of 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.

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.)

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.