Filing Compare · EL PASO NATURAL GAS CO LLC

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________

Form 10-K

(Mark One)

R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2009
	For the fiscal year ended December 31, 2010 OR
	OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to

Commission File Number 1-2700

El Paso Natural Gas Company

(Exact Name of Registrant as Specified in Its Charter)

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

Telephone Number: (713) 420-2600

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

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

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

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 £No R

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 R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £

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. R

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

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

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

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

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

Common Stock, par value $1 per share. Shares outstanding on ~~March~~February 125, ~~2010~~2011: 1,000

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

Documents Incorporated by Reference: None

EL PASO NATURAL GAS COMPANY

TABLE OF CONTENTS

	Caption	Page
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	5
Item 1B.	Unresolved Staff Comments	1314
Item 2.	Properties	1314
Item 3.	Legal Proceedings	1314
Item 4.	~~Submission~~(Removed ofand ~~Matters to a Vote of Security Holders~~Reserved)	*14
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	1314
Item 6.	Selected Financial Data	*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1415
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	2120
Item 8.	Financial Statements and Supplementary Data	2221
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	44
Item 9A.	Controls and Procedures	44
Item 9A(T).	Controls and Procedures	44
Item 9B.	Other Information	44
	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	45
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	46
	Signatures	47

____________

*	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 ~~MDth~~LNG = ~~thousand~~liquefied ~~dekatherms~~natural gas BBtu = billion British thermal units MMcf = million cubic feet Bcf = billion cubic feet ~~Tonne = metric ton LNG = liquefied natural gas~~

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~~the company”, we are describing El Paso Natural Gas Company and/or our subsidiaries.

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PART I

ITEM 1. BUSINESS

Overview and Strategy

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

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

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

•	providing outstanding customer service;

•	developing new growth projects in our market and supply areas;

•	maintaining the integrity and ensuring the safety of our pipeline systems and other assets;

•	successfully recontracting expiring contracts for transportation capacity; and

• focusing on increasing utilization, efficiency and ~~synergies~~cost ~~across~~control in our ~~systems~~operations.

The El Paso Natural Gas (EPNG) System. The EPNG system consists of approximately 10,200 miles of pipeline with a winter sustainable west-flow capacity of 4,850 MMcf/d and east-end deliverability of 800 MMcf/d. During ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008, average throughput was 3,~~937~~356 BBtu/d, 4 3,~~379~~937 BBtu/d and 4,~~189~~379 BBtu/d. This system delivers natural gas from the San Juan, Permian, and Anadarko basins ~~and via interconnections in the Rocky Mountains~~ 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 500 miles of pipeline with an east to west flow design capacity of approximately 400 MMcf/d. During ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008, average throughput was ~~379~~421 BBtu/d, ~~349~~379 BBtu/d and ~~458~~ 349 BBtu/d. Mojave’s ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008 throughput includes ~~334~~382 BBtu/d, ~~306~~ 334 BBtu/d and ~~431~~306 BBtu/d of volumes transported ~~volume~~on ~~for~~behalf of the EPNG system. The Mojave system connects with other pipeline systems including, (i) the EPNG system near Cadiz, California, (ii) the EPNG and Transwestern Pipeline Company, LLC (Transwestern) systems at Topock, Arizona and to(iii) the Kern River Gas Transmission Company system in California. This system also extends to customers in the vicinity of Bakersfield, California.

Storage Facility. We In addition to our pipeline systems, we utilize our Washington Ranch underground storage facility located in New Mexico~~, which~~ ~~has~~to upmanage toour ~~approximately~~transportation 44needs ~~Bcf~~and ofto ~~underground~~offer ~~working~~interruptible ~~natural~~storage ~~gas~~services. This storage ~~capacity,~~ facility has up to ~~manage~~approximately ~~our~~44 ~~transportation~~Bcf ~~needs~~of ~~and~~underground toworking ~~offer~~natural ~~interruptible~~gas storage ~~services~~ capacity.

Markets and Competition

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

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~~Markets~~ The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as shales, is rapidly increasing. This shift will affect the supply patterns, the flows and ~~Competition~~the rates that can be charged on pipeline systems. The impact will vary among pipelines according to the location and the number of competitors attached to these new supply sources.

~~Our~~Exports ~~customers consist~~to ofMexico ~~natural~~are ~~gas~~increasing ~~distribution~~ and ~~industrial~~expected ~~companies,~~to ~~electric generation~~increase ~~companies,~~further ~~natural~~over ~~gas~~time ~~producers,~~as ~~other~~demand ~~natural~~growth ~~gas~~exceeds ~~pipelines,~~production ~~and natural~~growth ~~gas~~in ~~marketing~~that ~~and trading companies~~country. The Weincrease ~~provide transportation and storage services~~ in ~~both~~demand ~~our~~for ~~natural~~ gas ~~supply~~ and ~~market~~transportation ~~areas.~~caused ~~Our~~by ~~pipeline systems~~the ~~connect~~trends ~~with~~in ~~multiple~~Mexico ~~pipelines~~could ~~that~~be ~~provide~~partially ~~our~~offset ~~customers~~by ~~with~~imports ~~access to~~of ~~diverse~~LNG. Imports ~~sources~~ of ~~supply,~~LNG ~~including~~have ~~supply~~fluctuated ~~from~~in ~~unconventional~~the ~~sources,~~past ~~and various~~in ~~natural~~response to changing gas ~~markets.~~prices ~~The~~within ~~natural~~North ~~gas~~America, ~~industry~~Europe isand ~~undergoing~~Asia. LNG aterminals ~~major shift~~and inother ~~supply~~regasification ~~sources. Production~~facilities ~~from~~can ~~conventional~~serve ~~sources~~as isalternate ~~declining while~~sources ~~production~~of ~~from~~supply ~~unconventional~~for ~~sources~~pipelines, ~~such~~enhancing astheir ~~shale,~~delivery ~~tight~~capabilities ~~sands,~~ and ~~coal~~ ~~bed~~operational ~~methane,~~flexibility isand ~~rapidly~~complementing ~~increasing. This~~traditional ~~shift~~supply ~~will~~transported ~~change~~into ~~the~~market ~~supply patterns~~areas. ~~and~~However, ~~flows~~these ofLNG ~~pipelines. The~~delivery ~~impact~~systems ~~will~~may ~~vary~~also ~~among~~compete ~~pipelines according~~with tous ~~the~~for ~~proximity~~transportation of ~~the~~gas ~~new~~into ~~supply~~market ~~sources~~areas we serve.

~~Imported~~Electric ~~LNG~~power generation has been athe ~~significant~~source ~~supply~~of ~~source~~most of the growth in demand for natural gas over the ~~North~~last ~~American~~10 ~~market~~years, and this trend is expected to continue in the future. ~~LNG~~The ~~terminals and~~growth ~~other~~of ~~regasification~~natural ~~facilities~~gas ~~can~~in ~~serve~~this sector is influenced by competition with coal and increased consumption of electricity as ~~alternate~~a ~~sources~~result of ~~supply~~recent ~~for pipelines,~~economic ~~enhancing~~growth. ~~their~~Short-term ~~delivery~~market ~~capabilities~~shifts ~~and~~have ~~operational~~been ~~flexibility~~driven ~~and complementing~~by ~~traditional~~relative ~~supply~~costs ~~transported~~of ~~into~~coal-fired generation versus gas-fired generation. A long-term market ~~areas~~shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, ~~these LNG~~natural ~~delivery~~gas ~~systems~~demand ~~may~~could ~~also~~potentially ~~compete~~be ~~with~~adversely usaffected ~~for~~by ~~transportation~~laws ofmandating ~~gas~~or ~~into market~~encouraging ~~areas~~renewable wepower ~~serve~~sources.

~~Electric~~The ~~power generation~~EPNG ~~has~~system ~~been~~faces acompetition ~~growing~~in ~~demand~~the ~~sector~~west ofand ~~the~~southwest ~~natural~~from ~~gas~~other ~~market.~~existing ~~The growth~~pipelines, offrom ~~natural~~California ~~gas-fired~~storage ~~electric~~facilities, ~~power~~and ~~benefits~~from ~~the~~alternative ~~natural~~energy ~~gas~~sources ~~industry~~that ~~by creating~~are ~~more~~used ~~demand~~to ~~for~~generate ~~natural~~electricity ~~gas. This~~such ~~potential~~as ~~benefit~~hydroelectric ~~is offset~~power, innuclear ~~varying degrees~~energy, ~~by increased generation efficiency~~wind, ~~the more effective use of surplus electric capacity~~solar, ~~increased~~coal ~~natural gas prices~~ and ~~the use and availability of other~~ fuel ~~sources for power generation~~oil. InWe ~~addition,~~also ~~in several~~face ~~regions~~competition offrom ~~the~~gas ~~country,~~imported ~~new~~into ~~additions~~California infrom ~~electric~~Canada ~~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~~an ~~firm~~LNG ~~transportation~~facility ~~contracts~~located ~~with~~in ~~natural~~northern ~~gas pipelines~~Mexico.

WeThe ~~provide transportation~~Mojave ~~services~~system tofaces ~~the~~competition ~~southwestern~~from ~~U.S.~~other ~~and~~existing topipelines ~~the~~and ~~Mexican~~alternative ~~border through~~energy ~~connections~~sources tothat ~~other~~are ~~pipelines.~~used ~~The~~to ~~market~~generate ~~demand~~electricity ~~for~~such ~~natural gas distribution~~ as ~~well~~hydroelectric aspower, ~~gas-fired~~nuclear ~~electric generation capacity has experienced considerable growth in these areas in recent years. Historically~~energy, ~~California customers have been the largest holders of capacity on our EPNG system. Currently~~wind, ~~California and Arizona customers account for the majority of transportation on the EPNG system~~solar, ~~followed~~coal ~~by Texas~~ and ~~New~~fuel ~~Mexico~~oil. ~~The~~We ~~EPNG system~~ also ~~delivers~~face ~~natural~~competition ~~gas~~from toan ~~the~~LNG ~~U.S./Mexico~~facility ~~Border~~located ~~serving customers~~ in ~~Chihuahua,~~ ~~Sonora,~~northern ~~and Baja California, which are located in~~ Mexico.

~~Growth~~For of the natural gas market has been adversely affected by the current economic slowdown in the U.S. and global economies. The decline in economic activity reduced industrial demand for natural gas and electricity, which affected natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. We expect the demand and growth for natural gas to return as the economy recovers. Natural gas has a ~~favorable competitive~~further ~~position~~discussion as an electric generation fuel because it is a clean and abundant fuel with lower capital requirements compared with other alternatives. The lower demand and the credit restrictions on investments in the recent past may slow development of ~~supply~~factors ~~projects.~~impacting ~~While~~ our ~~pipelines~~markets ~~could experience some level of reduced throughput~~ and ~~revenues~~competition, ~~or slower~~see ~~development~~Item ~~of expansion projects as a result of these factors~~1A, ~~each generates~~Risk ~~a significant (greater than 80 percent) portion of their revenues through fixed monthly reservation or demand charges on long-term contracts at rates stipulated under our tariffs or in our contracts~~Factors.

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

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

Historically, California customers have been the largest holders of capacity on our EPNG system. Currently, California and Arizona customers account for the majority of transportation on the EPNG system, followed by Texas and New Mexico. The Mojave system is largely contracted to EPNG which utilizes the capacity to provide service to EPNG’s customers. The EPNG system also delivers natural gas to the U.S./Mexico border serving customers in Chihuahua, Sonora, and Baja California, which are located in Mexico.

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The ~~EPNG~~following ~~system faces~~table ~~competition~~details inour ~~the~~customer ~~west~~ and ~~southwest~~contract ~~from~~information ~~other~~for ~~existing~~each ~~and~~of ~~proposed pipelines,~~our ~~from~~pipeline ~~California~~systems ~~storage~~as ~~facilities~~of December 31, ~~and~~2010. ~~from~~Firm ~~alternative~~customers ~~energy sources~~reserve ~~that~~capacity on our pipeline systems and storage facility and are ~~used~~obligated to ~~generate~~pay ~~electricity~~a ~~such~~monthly asreservation ~~hydroelectric~~or ~~power, nuclear~~demand ~~energy~~charge, ~~wind,~~regardless ~~solar~~of the amount of natural gas they transport or store, ~~coal~~for ~~and~~the ~~fuel~~term ~~oil~~of their contracts. WeInterruptible ~~also~~customers ~~face~~are ~~competition~~customers ~~from LNG~~without ~~facilities~~reserved ~~located~~capacity inthat ~~northern~~pay ~~Mexico~~usage charges based on the volume of gas they transport, store, inject or withdraw.

The Mojave system faces competition from other existing and proposed pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. We also face competition from LNG facilities located in northern Mexico.

Pipeline System	Customer Information	Contract Information
EPNG	Approximately 150 firm and interruptible customers.	Approximately 200 firm transportation contracts. Weighted average remaining contract term of approximately three years.

	Major Customers:
	Southern California Gas Company (SoCal)
	(782 BBtu/d)	Expire in 2011-2014.

	ConocoPhillips Company
	(527 BBtu/d)	Expire in 2011-2012.

	Southwest Gas Corporation
	(485 BBtu/d)	Expire in 2011-2018.

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

	Major Customer:
	EPNG
	(510 BBtu/d)	Expires in 2015.

The following table details our customer and contract information for each of our pipeline systems as of December 31, 2009. Firm customers reserve capacity on our pipeline systems and storage facility and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.

Pipeline System	Customer Information	Contract Information
EPNG	Approximately 160 firm and interruptible customers.	Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately three years.
	Major Customers:
	Sempra Energy and Subsidiaries, including Southern California Gas Company (SoCal)
	(374 BBtu/d)	Expires in 2010.
	(334 BBtu/d)	Expires in 2011.
	( 12 BBtu/d)	Expires in 2014.
	ConocoPhillips Company
	(350 BBtu/d)	Expires in 2010.
	( 35 BBtu/d)	Expires in 2011.
	(392 BBtu/d)	Expires in 2012.
	Southwest Gas Corporation
	(412 BBtu/d)	Expires in 2011.
	( 75 BBtu/d)	Expires in 2015.
Mojave	Approximately 10 firm and interruptible customers.	Approximately three firm transportation contracts. Weighted average remaining contract term of approximately six years.
	Major Customer:
	EPNG
	(312 BBtu/d)	Expires in 2015.

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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 atariffs ~~tariff~~ approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of ~~service~~ services to our customers. The 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. Generally, the FERC’s authority also extends to:

•

rates and charges for natural gas transportation and storage;

•

certification and construction of new facilities;

•

extension or abandonment of services and facilities;

•

maintenance of accounts and records;

•

relationships between pipelines and certain affiliates;

•

terms and conditions of service;

•

depreciation and amortization policies;

•

acquisition and disposition of facilities; and

•

initiation and discontinuation of services.

Our interstate pipeline systems are also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our systems are in material compliance with the applicable regulations.3

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Environmental

A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 67, and is incorporated herein by reference.

Employees

As of February 2321, ~~2010~~ 2011, we had approximately ~~560~~530 full-time employees, none of whom are subject to a collective bargaining arrangement.

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ITEM 1A. RISK FACTORS

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

~~THE PRIVATE~~This ~~SECURITIES~~report ~~LITIGATION~~contains ~~REFORM~~forward-looking ~~ACT~~statements OFwithin the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. 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 of our forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.

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

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

Risks Related to Our Business

~~Our~~The success of our business depends on many factors beyond our control.

The ~~financial~~ results of our ~~transportation~~business ~~and~~are ~~storage~~impacted ~~operations~~in ~~are~~the ~~impacted~~long term by the volumes of natural gas we transport or store and the prices we are able to charge for ~~doing~~ sothese services. The ~~volume~~volumes ~~of natural gas~~ we ~~are able to~~ transport and store ~~depends~~ depend on the actions of third parties, ~~and~~that isare based on factors beyond our control. ~~This~~Such ~~includes~~ factors include events that negatively impact our customers’ demand ~~and~~for ~~producers’~~natural ~~supply,~~gas ~~including factors~~and ~~that~~could ~~negatively~~expose ~~impact~~ our ~~customers’~~pipelines ~~need~~to ~~for~~the ~~natural~~risk ~~gas~~that ~~from~~we ~~us,~~will ~~as well~~not asbe ~~the~~able ~~continued~~to ~~availability~~renew ofcontracts ~~natural~~at ~~gas~~expiration ~~production~~or ~~and~~that ~~reserves connected~~we will be required to discount our ~~pipeline~~rates ~~system~~significantly upon renewal. ~~Further,~~We ~~the~~are ~~following~~also ~~factors, most~~highly ofdependent ~~which~~on ~~are~~our ~~also~~customers ~~beyond~~and downstream pipelines to attach new and increased loads on their systems in order to grow our ~~control~~business. Further, ~~may~~state ~~unfavorably~~agencies ~~impact~~that regulate our ~~ability~~local ~~to maintain~~distribution orcompany ~~increase~~customers ~~current~~could ~~throughput,~~impose orrequirements tothat ~~remarket~~could ~~unsubscribed~~impact ~~capacity~~demand on for our ~~pipeline systems:~~services.

•The ~~service~~volume ~~area~~of ~~competition;~~gas that we transport and store also depends on the availability of natural gas supplies that are attached to our pipeline systems, including the need for producers to continue to develop additional gas supplies to offset the natural decline from existing wells connected to our systems. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our systems. There have been major shifts in supply basins over the last few years, and declining production from conventional sources of supplies. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our systems.

•Furthermore, ~~price~~our ~~competition;~~ability to deliver gas to our shippers is dependent upon their ability to purchase and deliver gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the gas delivered by our shippers at the receipt points into our system is less than the gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand. For example, during February of 2011, our south system experienced operational difficulties for various reasons, primarily due to the shippers’ taking more gas from the system than they had purchased and delivered into receipt points on our pipeline. Various state and federal agencies are reviewing the causes of such outages and it is uncertain what actions, if any, that the agencies will recommend upon completion of their reviews.

•The ~~expiration~~agencies orthat ~~turn~~regulate ~~back~~us ofand ~~significant~~our ~~contracts;~~customers could affect our profitability.

•Our ~~changes~~pipeline inbusiness ~~regulation~~is ~~and~~extensively ~~action~~regulated by the FERC, the U.S. Department of Transportation, the Department of Interior, the U.S. Department of Homeland Security and various state and local regulatory ~~bodies;~~agencies whose actions have the potential to adversely affect our profitability. The FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipelines (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. In 2010, we filed a rate case that will establish new rates in 2011. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, our profitability is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before we can file and obtain rate increases.

• weather conditions that impact natural gas throughput and storage levels;

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

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

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

• decreased natural gas demand due to various factors, including economic recession (as further discussed below), availability of alternate energy sources and increases in prices;

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•Our ~~legislative,~~existing ~~regulatory~~rates ormay ~~judicial~~also ~~actions,~~be ~~such~~challenged asby ~~mandatory~~complaint. ~~renewable~~The ~~portfolio~~FERC ~~standards~~commenced ~~and~~several ~~greenhouse~~proceedings ~~gas~~in ~~(GHG)~~2009 ~~regulations~~ and~~/or~~ ~~legislation~~2010 ~~that~~against ~~could~~unaffiliated ~~result~~pipeline insystems ~~(i)~~to ~~changes~~reduce in the ~~demand~~rates ~~for~~they ~~natural~~were ~~gas~~charging ~~and~~their ~~oil,~~customers. ~~(ii)~~There ~~changes~~is ina ~~the~~risk ~~availability~~that ofthe FERC or ~~demand~~our ~~for~~customers ~~alternative~~could ~~energy~~file ~~sources~~similar ~~such~~complaints ason ~~hydroelectric~~us and ~~nuclear~~that ~~power,~~a ~~wind~~successful ~~and~~complaint ~~solar~~against ~~energy~~our ~~and/or~~rates ~~(iii)~~could ~~changes~~have inan adverse impact on us. For a discussion of our recent rate case filed with the ~~demand~~FERC, ~~for~~see ~~less~~Part ~~carbon~~II, ~~intensive~~Item ~~energy~~8, ~~sources;~~Financial Statements and Supplementary Data, Note 7.

•Certain ~~availability~~of ~~and~~our ~~cost~~transportation services are subject to ~~fund~~negotiated ~~ongoing~~rate ~~maintenance~~contracts ~~and~~that ~~growth~~may ~~projects,~~not ~~especially~~allow inus ~~periods~~to recover our costs of ~~prolonged~~providing ~~economic~~the ~~decline;~~services.

•Under ~~opposition~~FERC policy, interstate pipelines and their customers may execute contracts at a negotiated rate which may be above or below the FERC regulated recourse rate for that service. These negotiated rate contracts are generally not subject to ~~energy~~adjustment ~~infrastructure~~for ~~development~~increased costs which could occur due to inflation, ~~especially~~increases in ~~environmentally~~the ~~sensitive~~cost ~~areas;~~of capital or taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, representing the difference between recourse rates and negotiated rates could result in either losses or lower rates of return in providing such services.

•Our ~~adverse~~revenues ~~general~~are ~~economic~~generated ~~conditions~~under ~~including~~contracts ~~prolonged recessionary periods~~ that ~~might~~must ~~negatively~~be ~~impact~~renegotiated ~~natural gas demand and the capital markets;~~periodically.

•Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For example, basis differentials between receipt and delivery points on our pipeline systems could decrease over time and thereby negatively impact our ability to ~~achieve~~renew ~~targeted~~contracts ~~annual~~at ~~operating~~rates that were previously in place. Our ability to extend and ~~administrative~~replace ~~expenses~~contracts ~~primarily~~could be adversely affected by ~~reducing~~factors ~~internal~~we ~~costs~~cannot ~~and~~control, ~~improving~~as ~~efficiencies~~discussed ~~from~~above. ~~leveraging~~In aaddition, ~~consolidated~~changes ~~supply~~in ~~chain~~state ~~organization;~~regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.

•The ~~expiration~~expansion orof ~~renewal~~our ofpipeline ~~existing~~systems ~~interests~~by inconstructing ~~real~~new ~~property~~facilities ~~including~~subjects ~~real~~us ~~property~~to onconstruction ~~Native~~and ~~American~~other ~~lands;~~risks ~~and~~that may adversely affect us.

•We ~~unfavorable~~frequently ~~movements~~expand inthe ~~natural~~capacity ~~gas~~of ~~prices~~our inexisting ~~certain~~pipeline ~~supply~~ and ~~demand~~storage ~~areas~~facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

A• ~~substantial portion~~our ofability ~~our~~to ~~revenues~~obtain ~~are~~necessary ~~generated~~approvals and permits from ~~firm~~the ~~transportation~~FERC ~~contracts~~and other regulatory agencies on a timely basis that ~~must~~ beare ~~renegotiated~~on ~~periodically.~~terms that are acceptable to us, including the potential negative impact of delays and increased costs caused by general opposition to energy infrastructure development, especially in environmentally, culturally sensitive and more heavily populated areas;

~~Our~~• ~~revenues~~the ~~are generated~~ability ~~under~~to ~~transportation~~access ~~and~~sufficient ~~storage~~capital ~~contracts~~at ~~which~~reasonable ~~expire~~rates ~~periodically and must be renegotiated, extended or replaced. If we are unable~~ to ~~extend~~fund ~~or replace~~expansion ~~these contracts when they expire or renegotiate contract terms as favorable as the existing contracts~~projects, weespecially ~~could suffer a material reduction~~ in ~~our revenues,~~periods ~~earnings and cash flows. For additional information on the expiration~~ of ~~our~~prolonged ~~contract~~economic ~~portfolio,~~decline ~~see~~when Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we ~~cannot control as discussed in more detail above. In addition, changes in state regulation of local distribution companies~~ may ~~cause~~be usunable to ~~negotiate short-term~~access ~~contracts~~the orcapital ~~turn back our capacity when our contracts expire.~~markets;

~~For~~• ~~additional information~~the onavailability ~~our~~of ~~revenues~~skilled ~~from our major customers~~labor, ~~see Part II~~equipment, ~~Item 8, Financial Statements~~ and ~~Supplementary~~materials ~~Data,~~to ~~Note~~complete 8.expansion ~~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.~~projects;

~~We are~~• ~~exposed~~potential tochanges ~~the~~in ~~credit~~federal, ~~risk~~state ~~of our customers~~ and ~~our~~local ~~credit~~statutes, ~~risk~~regulations, ~~management may~~and ~~not be adequate to protect against such risk.~~orders;

We• ~~are~~impediments ~~subject~~on ~~to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by~~ our ~~customers,~~ability ~~including default risk associated with adverse economic conditions. Our credit procedures and policies may not be adequate~~ to ~~fully~~ ~~eliminate~~acquire ~~customer~~rights-of-way ~~credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons~~ or ~~otherwise. If~~ ~~our existing~~land orrights ~~future~~on ~~customers~~terms ~~fail~~that ~~to pay and/or perform and we~~ are ~~unable~~acceptable to ~~remarket~~ the capacity, our business, the results of our operations and our financial condition could be adversely affected. We may not be able to effectively remarket capacity during and after insolvency proceedings involving a shipper.us;

•

our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel), labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact the return on our investments or could result in financial impairments;

•	our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;

•

the failure of suppliers and contractors to meet their performance and warranty obligations; and

•

the lack of transportation, storage or throughput commitments.

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~~Fluctuations~~Any ~~in energy~~of ~~commodity~~these ~~prices~~risks could ~~adversely~~prevent ~~affect~~a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its negative impact upon natural gas demand may result in either slower development in the potential for future expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our ~~business~~expected investment return.

~~Revenues~~We ~~generated by our transportation and storage contracts~~ depend on ~~volumes~~certain ~~and~~key ~~rates,~~customers ~~both~~for ~~of which~~a ~~can~~significant beportion ~~affected by the price~~ of ~~natural~~our ~~gas.~~revenues ~~Increased~~and ~~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~~any ~~base. The success~~ of ~~our~~these ~~transmission and~~key ~~storage~~customers operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our systems, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines. A decline in energy prices could ~~cause~~result ~~a decrease~~ in ~~these development activities and could cause~~ a ~~decrease~~decline in ~~the volume of reserves available for transportation and storage through~~ our ~~systems~~revenues.

~~Pricing~~We ~~volatility may,~~rely inon ~~some~~a ~~cases,~~limited ~~impact~~number ~~the value~~ of ~~under~~customers orfor ~~over~~a ~~recoveries~~significant portion of ~~retained natural~~our ~~gas,~~revenues. asFor ~~well~~the asyear ~~imbalances~~ended December 31, ~~cashouts~~2010, ~~and~~ConocoPhillips ~~system encroachments. We~~Company, ~~obtain~~Southern ~~in-kind~~California ~~fuel~~Gas ~~reimbursements~~Company ~~from~~and ~~shippers~~Southwest ~~in accordance~~Gas ~~with~~Corporation ~~the~~accounted ~~pipeline’s~~for ~~tariff~~approximately or15 ~~applicable~~percent, ~~contract terms. We~~14 ~~revalue~~percent ~~our~~and ~~natural~~12 ~~gas~~percent, ~~imbalances~~respectively ~~and~~of ~~other~~our ~~gas~~operating ~~owed~~revenues. toThe ~~or from~~loss ~~shippers~~of toany anmaterial ~~index~~portion ~~price~~of ~~and~~the ~~periodically~~contracted ~~settle~~volumes of these ~~obligations~~customers, ~~in cash~~as ~~pursuant~~a toresult ~~the~~of ~~pipeline’s~~competition, ~~tariff~~creditworthiness, ~~regulatory~~inability ~~approval~~to negotiate extensions, or ~~each~~replacements ~~balancing contract. Currently~~of contracts or otherwise, ~~our~~could ~~tariff~~have ~~provides~~a ~~that~~material ~~the~~adverse ~~difference~~effect ~~between the~~on ~~quantity~~us. For ofadditional ~~fuel~~information ~~retained~~on ~~and~~our ~~fuel~~revenues ~~used~~from inthese ~~operations~~customers, ~~will~~see bePart ~~flowed-through or~~II, ~~charged~~Item to8, ~~shippers~~Financial Statements and Supplementary Data, Note 9.

IfThe ~~natural~~costs ~~gas prices~~to inmaintain, ~~the~~repair ~~supply~~and ~~basins~~replace ~~connected to~~ our pipeline systems ~~are higher than prices in other natural gas producing regions, our ability to compete with other transporters~~ may beexceed ~~negatively impacted on a short-term basis, as well as with respect to~~ our ~~long-term~~expected ~~recontracting activities~~levels. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Consequently, a significant prolonged downturn in natural gas prices could have a material adverse effect on our financial condition, results of operations and liquidity. Fluctuations in energy prices are caused by a number of factors, including:

•Much ~~regional,~~of ~~domestic~~our ~~and~~pipeline ~~international~~infrastructure ~~supply~~was originally constructed many years ago. The age of these assets may result in them being more costly to maintain and ~~demand~~repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or other incidents due to factors outside of our control (including ~~changes~~due to third party excavation near our pipelines, unexpected degradation of our pipelines, as well as design, construction or manufacturing defects) that could result in ~~supply~~personal injury or property damages. Much of our pipeline systems are located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and ~~demand~~a ~~due~~loss of revenues. Although we are targeted to ~~general~~complete ~~economic~~our ~~conditions~~pipeline integrity program which includes the development and ~~weather;~~use of in-line inspection tools in high consequence areas by its required completion date at the end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipelines. In addition, as indicated above there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future.

•We ~~availability~~do ~~and~~not ~~adequacy~~own all of ~~gathering,~~the ~~processing~~land ~~and~~on ~~transportation~~which our pipelines and facilities; are located, which could disrupt our operations.

•We ~~energy~~do ~~legislation~~not own all of the land on which our pipelines and ~~regulation~~facilities are located. We are subject to the risk that we do not have valid rights-of-way, ~~including~~that ~~potential~~such ~~changes~~rights-of-way ~~associated~~may lapse or terminate, our facilities may not be properly located within the boundaries of such rights-of-way or the landowners otherwise interfere with ~~GHG~~our ~~emissions~~operations. Our ~~and~~loss ~~renewable~~of ~~portfolio~~or ~~standards;~~interference with these rights could have a material adverse effect on us.

•There ~~federal~~are ~~and~~accounting ~~state~~principles ~~taxes,~~that ifare ~~any,~~unique onto ~~the~~regulated ~~transportation~~interstate ~~and~~pipeline ~~storage~~assets ofthat ~~natural~~could ~~gas;~~materially impact our recorded earnings.

•Accounting ~~the~~policies ~~price~~for FERC regulated pipelines are in certain instances different from U.S. generally accepted accounting principles (GAAP) for nonregulated entities. For example, FERC accounting policies permit certain regulatory assets to be recorded on our balance sheet that would not typically be recorded for nonregulated entities. In determining whether to account for regulatory assets on each of our pipelines, we consider various factors including regulatory changes and ~~availability~~the impact of ~~supplies~~competition to determine the probability of ~~alternative~~recovery ~~energy~~of ~~sources;~~these ~~and~~assets. Currently, we have regulatory assets recorded on our balance sheet. If we determine that future recovery is no longer probable, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as other income on our income statement. To the extent that one of our expansion projects is not fully subscribed when it goes into service, we may experience a reduction in our earnings once the pipeline is placed into service.

• the level of imports, including the potential impact of political unrest among countries producing oil and LNG, as well as the ability of certain foreign countries to maintain natural gas and oil prices, production and export controls.

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

Our business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services and sets authorized rates of return. In June 2008, we filed a rate case with the FERC as required under the settlement of our previous rate case. The filing proposed an increase in base tariff rates on our EPNG system. In August 2008, the FERC issued an order accepting the proposed rates effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of our proposals in the technical conference proceeding. The FERC has appointed an administrative law judge to preside over a hearing if we are unable to reach a negotiated settlement with our customers on the remaining issues. Settlement negotiations are continuing; however the hearing has been postponed until May 2010. The outcome of the settlement discussions or the hearing is not currently determinable.

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We periodically file with the FERC to adjust the rates charged to our customers. In establishing those rates, the FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The ~~FERC~~supply ~~then~~and ~~assigns~~demand afor ~~rate~~natural ~~of return~~gas oncould ~~equity~~be ~~within~~adversely ~~that~~affected ~~range to reflect specific risks of that pipeline when compared to the proxy group companies. Depending on the specific risks faced~~ by usmany ~~and~~factors ~~the~~outside ~~companies included in the proxy group, the FERC may establish rates that are not acceptable to us and have a negative impact on our cash flows, profitability and results~~ of ~~operations. In addition, pursuant to laws and regulations,~~ our ~~existing~~control ~~rates~~which may be challenged by complaint. The FERC commenced several complaint proceedings in 2009 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could ~~file similar~~negatively ~~complaints~~affect ~~on our pipeline systems and that a successful complaint against our rates could have an adverse impact on our cash flows and results of operations~~us.

~~Also,~~Our ~~increased regulatory~~success ~~requirements~~depends ~~relating~~on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. For example, we are not significantly impacted in the ~~integrity~~short-term by reductions in the supply or demand for natural gas since we recover most of our ~~pipelines~~revenues ~~requires additional~~from ~~spending~~reservation charges under longer-term contracts that are not dependent on the supply and demand of natural gas in ~~order~~the toshort-term. However, ~~maintain~~our ~~compliance~~business ~~with~~can ~~these~~be ~~requirements~~negatively impacted by sustained downturns in supply and demand for natural gas. ~~Any additional~~One ~~requirements~~of the major factors that ~~are~~will ~~enacted~~impact ~~could~~natural ~~significantly~~gas ~~increase~~demand will be the ~~amount~~ potential growth of ~~these~~natural ~~expenditures.~~gas ~~Further~~in the power generation market, ~~state~~particularly ~~agencies~~driven ~~that~~by ~~regulate~~the ~~our~~speed ~~local distribution~~and ~~company~~level ~~customers~~of ~~could~~existing ~~impose~~coal-fired ~~requirements~~power generation that ~~could~~is ~~impact~~ replaced with natural gas-fired power generation. In addition, the supply and demand for natural gas for our ~~services.~~business will depend on many other factors outside of our control, which include, among others:

~~Environmental compliance~~• ~~and~~adverse ~~remediation~~changes ~~costs~~in ~~and~~global ~~the~~economic ~~costs~~conditions, ofincluding ~~environmental~~changes ~~liabilities~~that ~~could exceed~~negatively ~~our~~impact ~~estimates.~~general demand for power generation and industrial loads for natural gas;

~~Our~~• ~~operations~~adverse ~~are subject~~changes ~~to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result~~ in ~~significant~~geopolitical ~~costs to install and maintain pollution controls~~factors, ~~fines~~including ~~and~~unexpected penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation or clean up of contaminated properties (some of which have been designated as Superfund sites by the U. S. Environmental Protection Agency (EPA) under the Comprehensive Environmental Responsewars, ~~Compensation~~terrorist ~~and~~activities Liability Act), as well as damage claims arising out of the contamination of properties or impact on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and ~~timing~~others ofacts ~~all future expenditures related to environmental matters and we could be required to set aside additional amounts which could significantly impact our future consolidated results~~ of ~~operations, financial position or cash flows. See Part II, Item 8, Financial Statements and Supplementary Data, Note 6.~~aggression;

In• ~~estimating~~technological ~~our environmental~~advancements ~~liabilities,~~that wemay ~~face~~drive ~~uncertainties~~further ~~that~~increases ~~include:~~in production from natural gas shales;

• ~~estimating~~competition ~~pollution~~from ~~control~~imported LNG and ~~clean~~alternate ~~up costs, including sites where preliminary site investigation or assessments have been completed~~fuels;

• ~~discovering~~increased ~~new~~prices ~~sites~~of ornatural ~~additional~~gas ~~information~~that atcould ~~existing~~negatively ~~sites~~impact demand;

• ~~forecasting~~increased ~~cash~~costs ~~flow timing~~ to ~~implement~~transport ~~proposed~~natural ~~pollution control and cleanup costs~~gas;

• ~~receiving~~adoption ~~regulatory~~of ~~approval~~various ~~for~~energy ~~remediation~~efficiency ~~programs~~and conservation measures; and

• ~~quantifying~~perceptions ~~liability~~of ~~under~~customers ~~environmental~~on ~~laws~~the ~~that~~availability ~~may impose joint~~ and ~~several~~price ~~liability~~volatility onof ~~potentially~~natural ~~responsible~~gas ~~parties~~prices ~~and~~over ~~managing~~the ~~allocation responsibilities;~~longer-term.

•The ~~evaluating~~price ~~and~~for ~~understanding~~natural ~~environmental~~gas ~~laws~~could ~~and~~be ~~regulations,~~adversely ~~including~~affected ~~their~~by ~~interpretation~~many ~~and~~factors ~~enforcement;~~outside of our control which could negatively affect us.

•Natural ~~interpreting~~gas ~~whether~~prices ~~various~~historically ~~maintenance~~have ~~activities~~been ~~performed~~volatile and are likely to continue to be volatile in the ~~past~~future, especially given current global geopolitical and ~~currently~~economic ~~being~~conditions. ~~performed~~There ~~required~~is ~~pre-construction~~a ~~permits~~risk ~~pursuant~~that commodity prices will remain depressed for sustained periods, especially in relation to natural gas prices which are at relatively low levels at this time. The degree to which our business is impacted by lower commodity prices varies. For example, we are not as significantly impacted in the ~~Clean~~short-term ~~Air~~by ~~Act;~~changes ~~and~~in natural gas prices. However, we can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas, including reductions in our ability to renew transportation contracts on favorable terms, as well as to construct new pipeline infrastructure. The price for natural gas is subject to a variety of additional factors that are outside of our control, which include, among others:

• ~~changing~~changes ~~environmental~~in ~~laws~~regional and ~~regulations~~domestic ~~that~~supply ~~may~~and ~~increase our costs.~~demand;

•

changes in basis differentials among different supply basins that can negatively impact our ability to compete with supplies from other basins, including our ability to maintain transportation revenues and renew transportation contracts in supply basins that are not as competitive with other alternatives;

•	changes in the costs of transporting natural gas;

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

•	the price and availability of supplies of alternative energy sources; and

•	the amount of capacity available to transport natural gas.

Our business is subject to competition from third parties which could negatively affect us.

The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies in the transportation and storage of natural gas. We also compete with suppliers of alternate sources of energy, including electricity, coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes growing competition in many of the markets that we serve, including Transwestern’s pipeline into Phoenix. There have also been various proposals over time to construct LNG terminals along the east and west coasts that could also negatively impact the demand and the transportation rates that our pipeline systems could charge to the extent the LNG terminals were constructed. For example, our EPNG system experienced a loss of demand when an LNG terminal was completed south of the Mexico – California border.

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InOur ~~addition to~~operations ~~potentially~~are ~~increasing~~subject the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards, emission standards with regard to ~~our~~operational ~~reciprocating~~hazards ~~internal combustion engines on our pipeline systems, GHG reporting~~ and ~~potential~~uninsured ~~mandatory~~risks ~~GHG~~which ~~emissions~~could ~~reductions.~~negatively ~~Future environmental~~affect ~~compliance costs relating to GHGs associated with our operations are not yet clear~~us. ~~For a further discussion on GHGs, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies.~~

~~Although~~Our itoperations ~~is uncertain~~are ~~what~~subject ~~impact~~to ~~legislative~~a number of inherent risks including fires, ~~regulatory~~earthquakes, ~~and~~adverse ~~judicial~~weather ~~actions~~conditions ~~might~~(such ~~have on~~as usextreme ~~until~~cold ~~further~~or ~~definition~~heat, istornadoes, ~~provided~~lightning inand ~~those~~flooding) ~~forums,~~and ~~there~~other isnatural adisasters; ~~risk~~terrorist ~~that such~~activity ~~future~~or ~~measures~~acts ~~could~~of ~~result~~aggression; inthe ~~changes~~collision toof ~~our~~equipment ~~operations~~of ~~and~~third toparties ~~the consumption~~on ~~and~~our ~~demand~~infrastructure ~~for~~(such ~~natural~~as ~~gas.~~damage ~~Changes~~caused to our ~~operations~~underground ~~could~~pipelines ~~include increased~~by ~~costs~~third toparty ~~(i)~~excavation ~~operate~~or ~~and~~construction); ~~maintain~~explosions, ~~our~~pipeline ~~facilities~~failures, ~~(ii)~~mechanical ~~install~~and ~~new emission~~process ~~controls~~safety onfailures, events causing our facilities, ~~(iii)~~to ~~construct~~operate ~~new~~below ~~facilities,~~expected ~~(iv) acquire~~levels ~~allowances~~of capacity or ~~pay~~efficiency; ~~taxes~~uncontrollable ~~related to~~flows ~~our GHG~~of ~~and~~natural ~~other emissions~~gas, ~~and~~release ~~(v)~~of ~~administer~~pollution ~~and~~or ~~manage~~contaminants aninto ~~emissions~~the ~~program~~environment ~~for GHG~~(including discharges of toxic gases or substances) and other ~~emissions~~environmental hazards. ~~Changes~~Each inof ~~regulations,~~these ~~including~~risks ~~adopting~~could ~~new standards~~result ~~for~~in ~~emission~~(a) ~~controls~~damage ~~from~~or ~~certain~~destruction of our facilities, ~~could~~(b) ~~also result~~damages inand ~~delays~~injuries into ~~obtaining~~persons ~~required~~and ~~permits~~property ~~to construct~~ or ~~operate~~(c) ~~our facilities. While~~business weinterruptions ~~may~~while bedamaged ~~able~~energy toinfrastructure ~~include~~is ~~some~~repaired or ~~all~~replaced, each of ~~the~~which ~~costs associated~~could ~~with~~cause ~~our~~us ~~environmental~~to ~~liabilities~~suffer ~~and~~substantial ~~environmental~~losses. ~~compliance~~In ~~in the~~addition, ~~rates~~although ~~charged~~the bypotential ~~our~~effects ~~pipelines~~of ~~and~~climate inchange ~~the~~on ~~prices~~our atoperations ~~which~~(such weas ~~sell natural gas~~flooding, ~~our~~etc.) ~~ability~~are touncertain ~~recover~~at ~~such~~this ~~costs~~time, ischanges ~~uncertain~~in ~~and~~climate ~~may~~patterns ~~depend~~as ona ~~events beyond~~result ~~our~~of ~~control~~global ~~including~~emissions ~~the outcome~~ of ~~future~~greenhouse ~~rate~~gas ~~proceedings~~(GHG) ~~before~~could ~~the FERC~~have ~~and~~a ~~the~~negative ~~provisions~~impact ofupon ~~any~~our ~~final~~operations ~~regulations~~in ~~and~~the ~~legislation~~future.

~~Our~~While ~~operations~~ we maintain insurance against some of these risks in amounts that we believe are ~~subject~~reasonable, toour ~~operational~~insurance ~~hazards~~coverages have material deductibles, self-insurance levels, limits on our maximum recovery and ~~uninsured~~do not cover all risks. For example, we do not carry or are unable to obtain insurance coverage on terms that we find acceptable for certain exposures including, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption, named windstorm exposures, and in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.

~~Our~~We ~~operations~~ are subject to ~~the~~a ~~inherent~~complex ~~risks~~set ~~normally associated with pipeline operations, including pipeline failures, explosions, pollution, release~~ of ~~toxic~~laws ~~substances, fires, adverse weather conditions (such as flooding), terrorist activity or acts of aggression,~~ and ~~other~~regulations ~~hazards.~~that ~~Each~~regulate ofthe ~~these~~energy ~~risks~~industry ~~could~~for ~~result~~which inwe ~~damage~~have to or ~~destruction~~incur ofsubstantial ~~our~~compliance ~~facilities or damages or injuries to persons~~ and ~~property causing~~remediation ~~us to suffer substantial losses~~costs. In addition, although the potential effects of climate change on our operations (such as flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of GHG could have a negative impact on our operations in the future.

~~While~~Our weoperations ~~maintain insurance~~are ~~against~~subject ~~many~~to ofa ~~these~~complex ~~risks~~set toof ~~the~~federal, ~~extent~~state and inlocal ~~amounts~~laws and regulations that ~~we believe~~tend ~~are~~to ~~reasonable,~~change ~~our~~from ~~insurance~~time ~~coverages~~to ~~have~~time ~~material~~and ~~deductibles~~generally ~~as well~~are asbecoming ~~limits~~increasingly onmore ~~our~~stringent. In ~~maximum~~addition ~~recovery~~to laws and regulations affecting our business, there are various laws and doregulations ~~not~~that ~~cover~~regulate ~~all~~various ~~risks.~~market ~~There~~practices ~~is also~~in the ~~risk~~industry, including antitrust laws and laws that ~~our~~prohibit ~~coverages~~fraud ~~will~~and ~~change~~manipulation ~~over~~in ~~time~~the markets in ~~light~~which we operate. The authority of ~~increased premiums~~the orFederal ~~changes~~Trading inCommission and the ~~terms~~FERC to impose penalties for violations of laws or regulations has generally increased over the ~~insurance~~last ~~coverages~~few years. In addition, our business is subject to laws and regulations that ~~could~~govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in ~~our~~ ~~decision~~significant costs to ~~either~~install ~~terminate~~and ~~certain~~maintain ~~coverages~~pollution controls, ~~increase~~and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our ~~deductibles~~operations. We are often obligated to obtain permits or ~~decrease~~ approvals in our ~~maximum~~operations ~~recoveries~~from various federal, state and local authorities, which permits and approvals can be denied or delayed. In addition, ~~there~~we isare aexposed ~~risk~~to fines and penalties to the extent that ~~our~~ ~~insurers~~we ~~may~~fail ~~default~~to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on ~~their~~our ~~coverage~~operations. These regulations often impose remediation obligations. Asassociated awith ~~result~~the investigation or clean-up of contaminated properties, ~~our~~as ~~results~~ well as damage claims arising out of ~~operations~~the contamination of properties or impact on natural resources. Finally, ~~cash~~many ~~flows~~of our assets are located and operate on federal, state, local or ~~financial~~tribal ~~condition~~lands ~~could~~and beare ~~adversely~~typically ~~affected~~regulated ~~if a~~by ~~significant~~one ~~event~~or ~~occurs~~more federal, state or local agencies. For example, we operate assets that isare ~~not~~located ~~fully~~on ~~covered~~federal lands , which are regulated by ~~insurance~~the Department of the Interior, particularly by the Bureau of Land Management (BLM). We also have operations on Native American tribal lands, which are regulated by the Department of the Interior, particularly by the Bureau of Indian Affairs, as well as local tribal authorities. Operations on these properties are often subject to additional regulations and compliance obligations, which can delay our access to such lands and impose additional compliance costs.

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

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

• our ability to obtain necessary approvals and permits by the FERC and other regulatory agencies on a timely basis and on terms that are acceptable to us, including the potential impact of delays and increased costs caused by certain environmental and landowner groups with interests along the route of our pipelines;

• the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;

• the availability of skilled labor, equipment, and materials to complete expansion projects;

• potential changes in federal, state and local statutes, regulations and orders, such as environmental requirements, including climate change requirements, that delay or prevent a project from proceeding or increase the anticipated cost of the project;

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•The ~~impediments~~laws onand ~~our~~regulations ~~ability~~(and tothe ~~acquire~~interpretations ~~rights-of-way~~thereof) orthat ~~land~~are ~~rights~~applicable or to ~~commence~~our ~~and~~business ~~complete~~could ~~construction~~materially onchange ain ~~timely~~the ~~basis~~future orand onincrease ~~terms~~the ~~that~~cost ~~are~~of ~~acceptable~~our tooperations or otherwise negatively impact us;.

•The ~~our~~regulatory ~~ability~~framework toaffecting ~~construct~~our ~~projects~~business ~~within~~is ~~anticipated~~frequently ~~costs~~subject to change, ~~including~~with the risk that weeither new laws and regulations may ~~incur~~be ~~cost~~enacted ~~overruns~~or ~~resulting~~existing ~~from~~laws ~~inflation~~and regulation may be amended. Such new or ~~increased~~amended ~~costs~~laws ofand ~~equipment,~~regulations ~~materials,~~can ~~labor,~~materially ~~contractor~~affect ~~productivity~~our operations and our financial results. In this regard, ~~delays~~there inhave ~~construction~~been orproposals ~~other~~to ~~factors~~implement ~~beyond~~or ~~our~~amend ~~control~~federal, ~~that~~state, welocal ~~may~~and ~~not~~tribal belaws ~~able~~and toregulations ~~recover~~that ~~from~~could negatively impact our ~~customers~~business, which ~~may~~includes beamong ~~material;~~others:

• Climate Change and other Emissions. There have been various legislative and regulatory proposals at the ~~lack~~federal ofand ~~future~~state ~~growth~~levels into address climate change and to regulate GHG emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have already adopted regulations to regulate GHG emissions. Although natural gas as a fuel supply for power generation has the least GHG emissions of any fossil fuel, it is uncertain at this time what impact the existing and~~/or~~ proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted, including the level of any emission standards; the amount and costs of allowances, offsets and credits granted; and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject us to regulation prior to 2016. There have also been various legislative and regulatory proposals at the federal and state levels to address various emissions from coal-fired power plants. Although such proposals will generally favor the use of natural gas fired power plants over coal-fired power plants, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been other various environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs. For example, the EPA has proposed more stringent ozone standards, as well as implemented more stringent emission standards with regard to certain combustion engines on our pipeline systems. It is uncertain what impact new environmental regulations might have on us until further definition is provided in the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by requiring us to monitor emissions, install additional equipment to reduce carbon emissions and possibly to purchase emission credits, as well as potentially delay the receipt of permits and other regulatory approvals. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipelines, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.

• Renewable / Conservation Legislation. There have been various legislative and regulatory proposals at the ~~lack~~federal ofand ~~transportation,~~state ~~storage~~levels orto ~~throughput~~provide ~~commitments~~incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.

~~Any~~• ofPipeline ~~these~~Safety. ~~risks could~~Various ~~prevent~~legislative aand ~~project~~regulatory ~~from~~reforms ~~proceeding,~~associated ~~delay~~with ~~its~~pipeline ~~completion~~safety orand ~~increase~~integrity ~~its anticipated~~issues ~~costs.~~have ~~There~~been isrecently ~~also~~proposed, ~~the~~including ~~risk~~reforms that ~~the~~would ~~downturn~~require inincreased ~~the~~periodic ~~economy~~inspections, ~~and its~~installation ~~negative~~of ~~impact~~additional ~~upon~~valves ~~natural~~and ~~gas~~other ~~demand~~equipment ~~may~~on ~~result~~our inpipelines ~~either~~and ~~slower development~~subjecting inadditional ~~our~~pipelines ~~expansion~~(including ~~projects~~gathering orand ~~adjustments~~intrastate inpipeline ~~the~~facilities) ~~contractual commitments~~to ~~supporting~~more ~~such~~stringent ~~projects~~regulation. AsIt ais ~~result~~uncertain what reforms, ~~new~~if ~~facilities~~any, ~~may~~will be ~~delayed or~~adopted weand ~~may~~what ~~not~~impact ~~achieve~~they ~~our~~might ~~expected~~ultimately ~~investment~~have ~~return,~~on ~~which could adversely affect~~ our ~~results of~~ operations, ~~cash flows~~ or financial ~~position~~results.

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

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

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

We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. The global economy is experiencing a recession and the financial markets have experienced extreme volatility and instability. In response, over the last year El Paso announced certain actions designed to reduce its need to access such financial markets, including reductions in the capital programs of certain of its operating subsidiaries and the sale of several non-core assets.

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

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We are ~~subject~~exposed to ~~financing~~the credit risk of our counterparties and ~~interest~~our ~~rate~~credit ~~risks~~risk management may not be adequate to protect against such risk.

We are subject to the risk that our counterparties fail to make payments to us within the time required under our contracts. Our ~~future~~current ~~success, financial~~largest ~~condition~~exposures ~~and~~are ~~liquidity~~associated ~~could~~with beshippers ~~adversely~~under ~~affected~~long-term ~~based~~transportation contracts on our ~~ability~~ topipeline ~~access~~systems. ~~capital~~Our ~~markets~~credit procedures and ~~obtain~~policies ~~financing~~may atnot ~~cost~~be ~~effective~~adequate ~~rates. This~~to isfully ~~dependent~~eliminate oncounterparty acredit ~~number~~risk. ofIn ~~factors~~addition, in ~~addition~~certain tosituations, ~~general~~we ~~economic conditions~~may ~~discussed~~assume ~~above,~~certain ~~many~~additional ofcredit ~~which~~risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we ~~cannot~~could ~~control~~be adversely affected. For example, ~~including~~we ~~changes in:~~may not be able to effectively remarket capacity or enter into new contracts at similar terms during and after insolvency proceedings involving a customer.

•We ~~our~~are exposed to the credit ~~ratings;~~and performance risk of our key contractors and suppliers.

•As ~~the~~an ~~structured~~owner of energy infrastructure facilities with significant capital expenditures, we rely on contractors for certain construction and ~~commercial~~we ~~financial~~rely ~~markets;~~on suppliers for key materials, supplies and services, including steel mills and pipe and tubular manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each which could adversely impact us.

•Our ~~market~~business ~~perceptions~~requires the retention and recruitment of usa orskilled workforce and the ~~natural~~loss ~~gas~~of ~~and~~employees ~~energy~~could ~~industry;~~result in the failure to implement our business plans.

•Our ~~tax~~business ~~rates~~requires ~~due~~the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. We compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible, which have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain our current employees, (b) successfully complete our knowledge transfer and/or (c) recruit new ~~tax~~employees ~~laws;~~of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

•We ~~market~~have ~~prices~~certain ~~for~~contingent ~~hydrocarbon~~liabilities ~~products~~that could exceed our estimates.

We have certain contingent liabilities associated with litigation, regulatory and environmental matters. In this regard, although we have greatly reduced our litigation, regulatory and environmental exposures over the last several years, we continue to have contingent liabilities (see Part II, Item 8, Financial Statements and Supplementary Data, Note 7). Although we believe that we have established appropriate reserves for our litigation, regulatory and environmental matters, we could be required to accrue additional amounts in the future and these amounts could be material.

We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these retained liabilities, including a reduction in historical knowledge of the assets and business that is required to effectively manage these liabilities or defend any associated litigation or regulatory proceedings.

We are subject to interest rate risks.

Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future.

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Risks Related to Our Affiliation with El Paso

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

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.

• 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.

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

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 with a stable outlook by Moody’s Investor Service, BB- with a stable outlook by Standard & Poor’s and BB+ with a stable outlook by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. ~~El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s.~~ There is a risk that these credit ratings may be adversely affected in the future as credit rating agencies ~~continue~~review totheir general credit requirements as well as review our and El Paso’s leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital ~~and collateral requirements~~.

El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated note receivable. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

If El Paso is unable to renew its revolving credit facility that expires in November 2012, then it could negatively impact us.

We are a party to El Paso’s $1.5 billion credit agreement. We are only liable, however for our borrowings under the credit agreement, which were zero at December 31, 2010. El Paso’s credit agreement is due to expire November of 2012. Prior to maturity, El Paso plans to renew or extend this credit facility. The amount of credit capacity El Paso is able to obtain and the cost of such credit could have a negative impact on our liquidity position and financial results. In addition, the financial covenants set forth in any new facility may be more restrictive than the current facility and could reduce our financial and operating flexibility.

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

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

A default under El Paso’s $1.5 billion credit agreement by any party could accelerate our future borrowings, if any, under the credit agreement and our long-term debt, which could adversely affect our liquidity position.

~~We are a party to El Paso’s $1.5 billion credit agreement. We are only liable, however, for our borrowings under the credit agreement, which were zero at December 31, 2009.~~ Under the credit agreement, a default by El Paso, or any other borrower could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

Furthermore, the indentures governing some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. Therefore, if we borrow $25 million or more under El Paso’s $1.5 billion credit agreement and such borrowings are accelerated for any reason, including the default of another party under the credit agreement, our long-term debt that contains these provisions could also be accelerated. ~~The~~and, ~~acceleration~~in ofturn, ~~our long-term debt could also~~ adversely affect our liquidity position and, in turn, our financial condition.

12We may be subject to a change of control if an event of default occurs under El Paso’s credit agreement.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

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

ITEM 2. PROPERTIES

A description of our properties is included in Item 1, Business, and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

A description of our material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 67, and is incorporated herein by reference.

ITEM 4. ~~SUBMISSION~~(REMOVED OFAND ~~MATTERS TO A VOTE OF SECURITY HOLDERS~~RESERVED)

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

PART II

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

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

We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. During ~~both~~2010 ~~2009~~ and ~~2008~~ 2009, we utilized $75 million, net of a $50 million cash contribution from our parent, and $200 million of our note receivable from the cash management program to pay dividends to our parent. No common stock dividends were declared or paid in 2008.

ITEM 6. SELECTED FINANCIAL DATA

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

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

The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors.

Overview

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

Type	~~Description~~	~~Percent of Total Revenues in 2009~~Description	Percent of 2010 Revenues
Reservation	Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems and storage facility. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.	87Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems and storage facility. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.	89
Usage and Other	Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.	13Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.	11

The ~~Federal Energy Regulatory Commission (~~FERC) regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather. OnIn ~~October 1~~addition, ~~2009, we received an order from the FERC directing us to remove the cost and revenue component of~~ our ~~fuel recovery mechanism. Our compliance filing, to remove the cost and revenue component, was approved in the fourth quarter of 2009. Due to this order, our~~ future earnings may be impacted by both positive and negative fluctuations in gas prices related to the revaluation of our fuel under or over recoveries, imbalances and system encroachments. Our ~~tariff~~tariffs ~~continues~~continue to provide that the difference between the quantity of fuel retained and fuel used in operations and lost and unaccounted for will be flowed-through or charged to shippers. These fuel trackers remove the impact of over or under collecting fuel and lost and unaccounted for gas from our operational gas costs.

14We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

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~~We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues.~~ Our ~~ability to extend our~~ existing ~~customer~~ contracts orexpire ~~remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment~~ at ~~the~~various ~~federal,~~times ~~state~~ and ~~local~~in ~~levels and~~varying ~~the~~amounts ~~market~~of ~~supply~~throughput ~~and demand factors at the relevant dates these contracts are extended or expire~~capacity. The ~~duration~~weighted ofaverage ~~new~~remaining orcontract ~~renegotiated~~term ~~contracts~~for ~~will~~our ~~be affected~~active bycontracts ~~current~~is ~~prices,~~approximately ~~competitive~~three ~~conditions~~years ~~and~~as ~~judgments~~of ~~concerning future~~December ~~market~~31, ~~trends and volatility~~2010. Below ~~Subject~~are tothe ~~regulatory~~contract ~~requirements,~~expiration ~~we attempt~~portfolio toand ~~recontract or remarket our capacity at~~ the ~~maximum~~associated ~~rates~~revenue ~~allowed under~~expirations for our ~~tariffs, although at times, we enter into~~ firm transportation contracts atas ~~amounts~~of ~~that~~December ~~are~~31, ~~less~~2010, ~~than~~including ~~these maximum allowable~~those ~~rates~~with toterms ~~remain~~beginning ~~competitive.~~in We2011 ~~refer~~or ~~to the difference between the maximum rates allowed under our tariff and the contractual rate we charge as discounts~~later.

Our existing contracts mature at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately three years as of December 31, 2009. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2009, including those with terms beginning in 2010 or later.

	Contracted Capacity		Percent of Contracted Capacity		Reservation Revenue		Percent of Reservation Revenue
	(BBtu/d) (1)				(In millions)
2011		2,099		41	$	126		28
2012		889		18		110		25
2013		707		14		63		14
2014		257		5		16		4
2015		330		6		53		12
2016 and beyond		808		16		77		17
Total		5,090		100	$	445		100

	Contracted Capacity		Percent of Total Contracted Capacity		Reservation Revenue		Percent of Total Reservation Revenue
	(BBtu/d (1))				(In millions)
2010		2,125		39	$	85		20
2011		1,300		24		133		32
2012		665		12		76		19
2013		269		5		25		6
2014		222		4		13		3
2015 and beyond		848		16		85		20
Total		5,429		100	$	417		100

____________

(1)	Excludes EPNG contracted capacity on the Mojave system.

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Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business. We believe EBIT is useful to investors to provide them with the same measure used by El Paso ~~Corporation~~ ~~(El Paso)~~ to evaluate our performance. and so that investors may evaluate our operating results without regard to our financing methods. We define EBIT as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. ~~We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods.~~ EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, ~~2009~~2010 compared with ~~2008~~2009.

Operating Results:

	2009			2008
	2010			2009
	(In millions,
	except for volumes)
Operating revenues	$	~~593~~517		$	~~590~~593
Operating expenses		(~~314~~313	)		(~~333~~314	)
Operating income		~~279~~204			~~257~~279
Other income, net		23			52
EBIT		~~281~~207			~~262~~281
Interest and debt expense		(9392	)		(9093	)
Affiliated interest income, net		1915			4619
Income tax expense		(7947	)		(8379	)
Net income	$	~~128~~83		$	~~135~~128
Throughput volumes (BBtu/d)(1)		3,~~982~~395			43,~~422~~982

____________

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

EBIT Analysis:

	Revenue			Expense			Other			Total
	Favorable/(Unfavorable)
	(In millions)
Reservation and other services revenues	$	11(76	)	$	—		$	—		$	11(76	)
Enron bankruptcy settlement		(8	)		(2	)		—			(10	)
Operational gas and revaluations		—			(4	)		—			(4	)
Operational gas and revaluations		—			4			—			4
Operating and general and administrative expenses		—			12			—			12
Operating and general and administrative expenses		—			5			—			5
Other (1)		—			(7	)		1			(6	)
Asset impairments		—			14			—			14
Total impact on EBIT	$	(76	)	$	1			1		$	(74	)
Other (1)		—			(2	)		(3	)		(5	)
Total impact on EBIT	$	3		$	19		$	(3	)	$	19

____________

(1)	Consists of individually insignificant items.

Reservation and Other Services Revenues. Our reservation and other services revenues were higher for the year ended December 31, 2009 compared to 2008, primarily due to an increase of approximately $15 million in reservation charges for capacity on our EPNG system resulting from higher contracted capacity to primary delivery points in California and an increase in EPNG’s tariff rates effective January 1, 2009, subject to refund, offset by a decrease of approximately $4 million in usage revenue primarily due to decreased throughput. We may or may not be able to sustain higher levels of contracted capacity by our customers in the future.

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~~During~~Reservation ~~2009,~~and ~~our throughput~~Other ~~volumes~~Services ~~decreased~~Revenues. For ~~compared~~the ~~with~~year ~~2008. This~~ended ~~was~~December ~~due~~31, ~~in part~~2010, throughput on our EPNG system was down 15 percent compared to a2009 ~~decrease~~due into lower natural gas and electric generation demand ~~due~~resulting tofrom weak macroeconomic conditions in the southwestern U.S., asincreased ~~well~~competition ~~as the introduction~~ in ~~April~~our ~~2009~~California ofand ~~a new interstate natural gas pipeline with approximately 500 MDth/d of capacity serving the greater Phoenix,~~ Arizona ~~area.~~market ~~Additionally~~areas, ~~although~~ aincluding ~~reduction~~increased inactivity ~~throughput~~from onan ~~our~~LNG ~~system is not material to our short-term financial results due to a substantial portion of our revenues being based on firm reservation charges under long-term contracts~~facility, itand ~~can be an indication of~~ the ~~risks~~nonrenewal ~~we may face when seeking to recontract or renew any~~ of ~~our~~ ~~existing~~expiring ~~firm transportation~~ contracts inas ~~the~~a ~~future.~~result Ifof ~~these~~reduced ~~macroeconomic conditions continue, it could negatively impact~~ basis differentials ~~over~~which ~~the longer~~unfavorably ~~term~~impacted ~~and~~ our ~~ability~~EBIT toby ~~renew~~$76 ~~firm transportation contracts that are expiring on our system or our ability to renew such contracts at current rates~~million. If, however, we determine there is a significant change in our cost of providing service or billing determinants, we have the option to file a future rate case with the FERC to recover our prudently incurred costs.

~~Enron~~Although ~~Bankruptcy~~approximately ~~Settlement. During~~89 ~~2008~~percent of our 2010 revenues are derived from reservation charges, lower throughput can affect our short-term results or be an indication of the risks we ~~recorded~~may ~~income~~face when seeking to recontract or renew any of ~~approximately~~our ~~$10~~existing ~~million~~firm transportation contracts. Continuing negative economic impacts on demand, ~~net~~as well as adverse shifting sources of ~~amounts~~ ~~owed~~supply, could negatively impact basis differentials and our ability to renew firm transportation contracts that are expiring on our system or our ability to renew such contracts at current rates. Additionally, we may be required to further discount certain ~~customers~~transportation asrates ain ~~result~~order ofto ~~settlements~~renew ~~received~~certain ~~from~~firm ~~the Enron~~transportation ~~bankruptcy~~contracts should these conditions continue.

~~Operational~~If ~~Gas~~we ~~and Revaluations. On~~determine ~~October~~there 1,is ~~2009,~~sufficient wechange ~~received~~in anour ~~order~~revenues, ~~from the~~costs ~~FERC~~or ~~directing~~billing usdeterminants, towe ~~remove~~have the ~~cost~~option ~~and~~to ~~revenue~~file ~~component~~a rate ofcase ~~our~~with ~~fuel recovery~~the ~~mechanism~~FERC onto ~~our~~provide ~~EPNG~~an ~~system. Our~~opportunity ~~compliance filing~~ to ~~remove~~ ~~the~~recover ~~cost~~our ~~and~~prudently ~~revenue~~incurred ~~component was approved in the fourth quarter of 2009~~costs. In ~~Due~~September ~~to this order~~2010, ~~our~~we ~~future~~filed ~~earnings~~a rate ~~may~~case bewith ~~impacted~~the ~~positively~~FERC ~~or negatively~~proposing ~~depending~~an onincrease ~~fluctuations~~ in ~~gas~~base ~~prices~~tariff ~~related~~rates todue, ~~the~~in ~~revaluation~~part, ~~of our~~to ~~under~~a orchange ~~over~~in ~~recoveries,~~our ~~imbalances~~billing ~~and system encroachments~~determinants. ~~Our~~The ~~tariff~~change ~~continues~~in togas ~~provide~~flows, ~~that~~contractual ~~the~~commitments ~~difference between~~and the ~~quantity~~outcome of ~~fuel~~our ~~retained~~rate ~~and~~case ~~fuel~~can ~~used~~impact inthe ~~operations~~financial ~~and~~performance ~~lost~~of ~~and unaccounted~~our ~~for~~pipeline. For ~~will~~additional beinformation ~~flowed-through~~regarding orour ~~charged~~rate tocases ~~shippers~~see “Regulatory Matters” discussed below.

~~Operating~~Gas ~~and~~Not ~~General~~Used ~~and Administrative~~in ~~Expenses~~Operations. In ~~During~~October 2009, we received an order from the ~~year~~FERC ~~ended~~directing ~~December~~us ~~31,~~to ~~2009,~~remove ~~our operating~~the cost and ~~general~~revenue components of the fuel tracker on our EPNG system. Our compliance filing to remove the cost and ~~administrative~~revenue ~~expenses~~component ~~were~~was ~~lower~~approved ~~primarily~~in asthe fourth quarter of 2009 and we recorded a ~~result~~ favorable adjustment to reflect the impact of ~~decreased~~unwinding ~~repair~~these ~~and~~components ~~maintenance~~of ~~expenses~~our fuel tracker.

~~Asset~~Operating ~~Impairments~~and General and Administrative Expenses. ~~During 2008~~For the year ended December 31, we2010, ~~recorded~~our ~~impairments~~operating ofand general and administrative expenses were lower than in 2009 by approximately $1412 million primarily due to ~~declining~~lower ~~real estate~~payroll, ~~values~~benefits ~~related~~and tocontractor ~~our~~costs ~~Arizona~~partially ~~storage~~offset ~~projects,~~by ~~which~~higher weallocated ~~are~~costs nofrom ~~longer developing~~our affiliates related to our shared pipeline services.

~~EPNG~~ Regulatory ~~Matters. In~~ June 2008, we filed a rate case with the FERC as required under the settlement of our previous rate case. The filing proposed an increase in base tariff rates on our EPNG system, which would increase revenue by $83 million annually over previously effective tariff rates. In August 2008, the FERC issued an order accepting the proposed rates effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of our proposals in the technical conference proceeding. The FERC has appointed an administrative law judge to preside over a hearing if we are unable to reach a negotiated settlement with our customers on the remaining issues. Settlement negotiations are continuing; however the hearing has been postponed until May 2010. The outcome of the settlement discussions or the hearing is not currently determinable.Matters

~~Interest~~ EPNG Rate Case. In April 2010, the FERC approved an uncontested partial offer of settlement which increased our base tariff rates effective January 1, 2009. As part of the settlement we made refunds of approximately $76 million, plus interest, in 2010. The settlement resolved all but four issues in the proceeding. In January 2011, the Presiding Administrative Law Judge issued her decision that for the most part found against us on the four issues. We will appeal those decisions to the FERC and ~~Debt~~may ~~Expense~~also seek review of any of the FERC’s decisions to the U.S. Court of Appeals. Although the final outcome is not currently determinable, we believe our accruals established for this matter are adequate.

~~Interest~~In ~~and~~September ~~debt expense~~2010, ~~for~~we ~~the~~filed ~~year~~a ~~ended~~new ~~December~~rate ~~31,~~case ~~2009,~~with ~~was~~the $3FERC ~~million~~proposing ~~higher~~an ~~than~~increase in ~~2008 primarily~~base ~~due~~tariff torates ~~interest~~as ~~recorded~~permitted inunder ~~2009~~the ~~for~~settlement ~~EPNG’s~~of the previous rate ~~refund~~case. These ~~provision related~~new tobase ~~its~~tariff ~~rate~~rates ~~case~~would increase revenue by approximately $107 million annually over previously effective ~~January~~tariff rates. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, ~~2009~~2011, subject to refund, the outcome of a hearing and ~~lower~~other ~~capitalized interest~~proceedings. At onthis ~~allowance~~time, ~~for~~the ~~funds~~outcome ~~used~~of ~~during~~this ~~construction~~matter ~~due~~is tonot ~~lower~~currently ~~capital expenditures~~determinable.

In October 2010, we filed with the FERC to permanently abandon two compressor stations and temporarily idle seven compressor stations along our south mainline system in 2011. This was done to better align our capacity to the current lower level of contract demand resulting from, in part, the weakened economic conditions along this line. Our intent is to bring the idled facilities back into service over the next several years as market demand improves. In our 2011 rate case, we did not seek to earn a return on the original investment in the idled facilities. We will continue to incur related operating costs and depreciation expense until the compressor stations are idled once approved by the FERC. The impact of both the permanent abandonment and the idling of the seven compressor stations to our pre-tax income would be approximately $15 million annually. These filings have been protested by certain interveners and the result is uncertain at this time.

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Mojave Rate Case. In August 2010, we filed a petition with the FERC to (i) amend our filing requirement previously approved by the FERC and (ii) approve an uncontested rate case settlement that, among other things, would establish new base transportation rates. Under the terms of the agreement, we may not file a new rate case to be effective any earlier than September 1, 2012, but must file a rate case to be effective no later than September 1, 2014. The FERC approved this settlement in October 2010 with an effective date of December 1, 2010.

Although these rate cases are intended to address significant factors leading to the loss in revenues or increased costs, they will not eliminate all ongoing business risks.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, ~~2009~~2010, was $274 million lower than in ~~2008~~ 2009 primarily due to lower average short-term interest rates on average advances to El Paso under its cash management program. The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:

	2009			2008
	2010			2009
	(In billions, except for rates)
Average advance due from El Paso	$	1.10		$	1.1
Average short-term interest rate		1.75	%		41.47	%

Income Taxes

Our effective tax rate of 36 percent and 38 percent for the years ended December 31, ~~2009~~2010 and ~~2008~~2009 was higher than the statutory rate of 35 percent in both periods due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 2.

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Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program. ~~During~~At ~~2009~~December 31, 2010, we ~~utilized~~ ~~$200~~had ~~million~~a ~~of our~~ note receivable from ~~the~~El ~~cash~~Paso ~~management~~of ~~program~~approximately ~~to pay~~$0.8 ~~dividends to our parent~~billion. AtWe ~~December~~do ~~31, 2009,~~not weintend ~~had~~to asettle ~~note receivable~~any ~~from~~amounts ~~El Paso~~owed ofunder ~~approximately~~this ~~$1.0~~note ~~billion~~within ofthe ~~which approximately~~next ~~$103~~twelve ~~million~~months ~~was~~and therefore, classified it as non-current ~~based~~ on ~~the~~our ~~net~~balance ~~amount~~sheet. During 2010, we ~~anticipate~~ ~~using~~utilized in$75 million of our note receivable from the ~~next~~cash ~~twelve~~management ~~months~~program, ~~considering~~net ~~available~~of a $50 million cash ~~sources and~~contribution ~~needs.~~from our parent, to pay a dividend to our parent. See Item 8, Financial Statements and Supplementary Data, Note 10 11, for a further discussion of El Paso’s cash management program. In August 2010, we repaid approximately $54 million cash of our 7.625% notes that matured. Our primary uses of cash are for working capital, capital expenditures and debt service requirements. For the year ended December 31, 2010 compared with 2009, our operating cash flows decreased by approximately $260 million primarily due to lower reservation revenues, payments of rate refunds and income taxes. Our cash capital expenditures for the year ended December 31, ~~2009~~2010 and those planned for ~~2010~~2011 are listed below.

	2009		Expected 2010
	2010		Expected 2011
	(In millions)
Maintenance	$	~~112~~80	$	~~113~~94
Expansion/Other		4		7
Expansion		—		2
Total	$	~~116~~80	$	~~120~~96

Our ~~2010~~ expected 2011 maintenance capital expenditures relate to maintaining and improving the integrity of our pipeline, complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. Our expansion ~~and other~~ capital expenditures primarily relate to expanding the capacity and services of our pipeline systems.

Although ~~recent~~ financial market conditions have ~~shown signs of improvement~~improved, continued volatility in ~~2010 and beyond in~~ the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is ~~largely~~partially mitigated by a revenue base that is significantly comprised of long-term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program. ~~As of December 31, 2009, El Paso had approximately $1.8 billion of available liquidity, including approximately $1.3 billion of capacity available to it under various committed credit facilities.~~ In addition to the cash management program above, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, ~~2009~~2010, El Paso had approximately $0.89 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. While we do not anticipate a need to directly access the financial markets in ~~2010~~2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.

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

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Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 6,7 which is incorporated herein by reference.

Climate Change and Energy Legislation and Regulation. There are various legislative and regulatory measures relating to climate change and energy policies that have been proposed and, if enacted, will likely impact our business.

Climate Change Legislation and Regulation. Measures to address climate change and greenhouse gas (GHG) emissions are in various phases of discussions or implementation at international, federal, regional and state levels. Over 50 countries, including the U.S. have submitted formal pledges to cut or limit their emissions in response to the United Nations-sponsored Copenhagen Accord. It is reasonably likely that federal legislation requiring GHG controls will be enacted within the next few years in the United States. Although it is uncertain what legislation will ultimately be enacted, it is our belief that cap-and-trade or other market-based legislation that sets a price on carbon emissions will increase demand for natural gas, particularly in the power sector. We believe this increased demand will occur due to substantially less carbon emissions associated with the use of natural gas compared with alternate fuel sources for power generation, including coal and oil-fired power generation. However, the actual impact on demand will depend on the legislative provisions that are ultimately adopted, including the level of emission caps, allowances granted, offset programs established, cost of emission credits and incentives provided to other fossil fuels and lower carbon technologies like nuclear, carbon capture sequestration and renewable energy sources.

It is also reasonably likely that any federal legislation enacted would increase our cost of environmental compliance by requiring us to install additional equipment to reduce carbon emissions from our larger facilities as well as to potentially purchase emission allowances. Based on 2008 operational data we reported to the California Climate Action Registry (CCAR), our operations in the United States emitted approximately 3.6 million tonnes of carbon dioxide equivalent emissions during 2008. We believe that approximately 3.2 million tonnes of the GHG emissions that we reported to CCAR would be subject to regulations under the climate change legislation that passed in the U.S. House of Representatives (the House) in June 2009. Of these amounts that would be subject to regulation, we believe that approximately 59 percent would be subject to the cap-and-trade rules contained in the proposed legislation and the remainder would be subject to performance standards. As proposed by the House, the portion of our GHG emissions that would be subject to cap-and-trade rules could require us to purchase allowances or offset credits and the portion of our GHG emissions that would be subject to performance standards could require us to install additional equipment or initiate new work practice standards to reduce emission levels at many of our facilities. The costs of purchasing emission allowances or offset credits and installing additional equipment or changing work practices would likely be material. Increases in costs of our suppliers to comply with such cap-and-trade rules and performance standards, such as the electricity we purchase in our operations, could also be material and would likely increase our cost of operations. Although we believe that many of these costs should be recoverable in the rates we charge our customers, recovery is still uncertain at this time. A climate change bill was also voted upon favorably by the Senate Committee on Energy and Public Works (the Committee) in November 2009 and has been ordered to be reported out of the Committee. Any final bill passed out of the U.S. Senate will likely see further substantial changes, and we cannot yet predict the form it may take, the timing of when any legislation will be enacted or implemented or how it may impact our operations if ultimately enacted.

The Environmental Protection Agency (EPA) finalized regulations to monitor and report GHG emissions on an annual basis. The EPA also proposed new regulations to regulate GHGs under the Clean Air Act, which the EPA has indicated could be finalized as early as March 2010. The effective date and substantive requirements of any EPA final rule is subject to interpretation and possible legal challenges. In addition, it is uncertain whether federal legislation might be enacted that either delays the implementation of any climate change regulations of the EPA or adopts a different statutory structure for regulating GHGs than is provided for pursuant to the Clean Air Act. Therefore, the potential impact on our operations remains uncertain.

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InITEM ~~addition, in March 2009, the EPA proposed a rule impacting emissions from reciprocating internal combustion engines, which would require us to install emission controls on our pipeline systems~~7A. It isQUANTITATIVE ~~expected~~AND ~~that~~QUALITATIVE ~~the~~DISCLOSURES ~~rule~~ABOUT ~~will~~MARKET be finalized in August 2010. As proposed, engines subject to the regulations would have to be in compliance by August 2013. Based upon that timeframe, we would expect that we would commence incurring expenditures in late 2010, with the majority of the work and expenditures incurred in 2011 and 2012. If the regulations are adopted as proposed, we would expect to incur approximately $9 million in capital expenditures over the period from 2010 to 2013.RISK

~~Legislative~~We ~~and regulatory~~are ~~efforts~~exposed ~~are~~to ~~underway~~the inrisk ~~various~~of ~~states~~changing ~~and~~interest ~~regions~~rates. ~~These rules~~ ~~once~~At ~~finalized~~December ~~may~~31, ~~impose additional costs on our operations and permitting our facilities~~2010, ~~which~~we ~~could~~had ~~include~~an ~~costs~~interest tobearing ~~purchase~~note ~~offset~~receivable ~~credits or~~from ~~emission~~El ~~allowances,~~Paso toof ~~retrofit~~approximately ~~or install equipment or to change existing work practice standards~~$0. In8 ~~addition~~billion, ~~various~~with ~~lawsuits~~a ~~have~~variable ~~been filed~~interest ~~seeking~~rate toof ~~force~~1.5% ~~further~~that ~~regulation~~is ofdue ~~GHG~~upon ~~emissions,~~demand. asWhile ~~well~~we asare ~~to require~~exposed ~~specific companies~~ to ~~reduce~~changes ~~GHG~~in ~~emissions~~interest ~~from~~income ~~their~~based ~~operations. Enactment~~on ofchanges ~~additional~~to ~~regulations by~~ the ~~federal~~variable orinterest ~~state governments~~rate, asthe ~~well as~~fair ~~lawsuits,~~value ~~could~~of ~~result~~this innote ~~delays~~receivable ~~and~~approximates ~~have~~the ~~negative~~carrying ~~impacts~~value ondue ~~our ability~~ to ~~obtain~~ ~~permits~~the ~~and~~note ~~other~~being ~~regulatory~~due ~~approvals~~on ~~with~~demand ~~regard to existing~~ and ~~new facilities,~~the ~~could~~market-based ~~impact~~nature ~~our costs~~ of ~~operations, as well as require us to install new equipment to control emissions from our facilities,~~ the ~~costs~~interest ~~of which would likely be material~~rate.

~~Energy Legislation. In~~The ~~conjunction~~table ~~with~~below ~~these~~shows climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint”. These proposals would establish renewable energy and efficiency standards at both the ~~federal~~carrying ~~and state level~~value, ~~some of which would require a material increase of renewable sources, such as wind and solar power generation, over~~ the ~~next~~related ~~several~~weighted-average ~~decades. There~~effective ~~have also~~interest ~~been~~rates ~~proposals~~on toour ~~increase~~non-affiliated ~~the~~fixed ~~development~~rate ~~of nuclear power and commercialize carbon capture and sequestration especially at coal~~long-~~fired facilities. Other~~term ~~proposals~~debt ~~would~~securities ~~establish incentives for energy efficiency~~ and ~~conservation. Although~~the itestimated isfair ~~reasonably~~value ~~likely that many~~ of these ~~proposals~~securities ~~will~~based beon ~~enacted~~quoted ~~over~~market ~~the~~prices ~~next~~for ~~few years, we cannot predict~~ the ~~form~~same ~~of any laws and regulations that might be enacted, the timing of their implementation,~~ or ~~the~~similar ~~precise impact on our operations or demand for natural gas~~issues. ~~However, such proposals if enacted could negatively impact natural gas demand over the longer term.~~

	December 31, 2010
	Expected Fiscal Year of Maturity of Carrying Amounts									December 31, 2009
		2011-2015	Thereafter			Total		Fair Value		Carrying Amount		Fair Value
	(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate	$	—	$	1,113		$	1,113	$	1,258	$	1,167	$	1,300
Average effective interest rate				7.5	%

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New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2009, the new accounting standards issued but not yet adopted by us did not have any impact on our financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, 2009, we had an interest bearing note receivable from El Paso of approximately $1.0 billion, with a variable interest rate of 1.5% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

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

	December 31, 2009
	Expected Fiscal Year of Maturity of Carrying Amounts										December 31, 2008
	2010			2014 and Thereafter			Total		Fair Value		Carrying Amount		Fair Value
	(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate	$	54		$	1,113		$	1,167	$	1,300	$	1,166	$	1,021
Average effective interest rate		7.8	%		7.5	%

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

• ~~Pertain~~pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• ~~Provide~~provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

• ~~Provide~~provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, ~~2009~~2010. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, ~~2009~~ 2010.

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Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated balance sheets of El Paso Natural Gas Company (the Company) as of December 31, ~~2009~~2010 and ~~2008~~2009, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, ~~2009~~2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, ~~2009~~2010. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of El Paso Natural Gas Company at December 31, ~~2009~~2010 and ~~2008~~2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2009~~2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2008, the Company adopted the provisions of an accounting standard update related to the measurement date and changed the measurement date of its postretirement benefit plan.

/s/ Ernst & Young LLP

Houston, Texas

~~March 1~~February 28, ~~2010~~ 2011

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EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Year Ended December 31,
	2009			2008			2007
	2010			2009			2008
Operating revenues	$	~~593~~517		$	~~590~~593		$	~~557~~590
Operating expenses
Operation and maintenance		~~202~~193			~~213~~202			~~201~~213
Depreciation and amortization		8388			8083			8280
Loss on long-lived assets		—			14—			914
Taxes, other than income taxes		2932			2629			2726
		314			333			319
		313			314			333
Operating income		~~279~~204			~~257~~279			~~238~~257
Other income, net		23			52			45
Interest and debt expense		(9392	)		(9093	)		(9890	)
Affiliated interest income, net		1915			4619			7146
Income before income taxes		~~207~~130			~~218~~207			~~215~~218
Income tax expense		7947			8379			83
Net income	$	~~128~~83		$	~~135~~128		$	~~132~~135

See accompanying notes.

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EL PASO NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except for share amounts)

	December 31,
	2009		2008
	2010		2009
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts and notes receivable
Accounts and note receivable
Customer, net of allowance of $2 in 2009 and 2008		56		66
Customer, net of allowance of $2 in 2010 and 2009		4		56
Affiliates		~~111~~6		6111
Other		320		63
Materials and supplies		4748		4347
Deferred income taxes		359		1235
Prepaids		15		15
Other		11		811
Total current assets		~~278~~113		~~156~~278
Property, plant and equipment, at cost		3,~~899~~970		3,~~804~~899
Less accumulated depreciation and amortization		1,~~409~~484		1,~~365~~409
Total property, plant and equipment, net		2,~~490~~486		2,~~439~~490
Other assets
Note receivable from affiliate		~~886~~836		~~986~~886
Other		110		~~103~~110
		996		1,089
		946		996
Total assets	$	3,~~764~~545	$	3,~~684~~764
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	8382	$	4883
Affiliates		4225		2142
Other		1411		1814
Current maturities of long-term debt		54—		—54
Taxes payable		~~103~~28		79103
Accrued interest		2118		2021
Accrued liabilities		8224		982
Regulatory liabilities		17		33
Other		27		47
Other		30		31
Total current liabilities		215		446
Total current liabilities		446		259
Long-term debt, less current maturities		1,113		1,113
Long-term debt, less current maturities.		1,113		1,166
Other liabilities
Deferred income taxes		408		~~389~~408
Other		7175		7271
		479		461
		483		479
Commitments and contingencies (Note 6)
Commitments and contingencies (Note 7)
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		~~458~~466		~~530~~458
Total stockholder’s equity		1,~~726~~734		1,~~798~~726
Total liabilities and stockholder’s equity	$	3,~~764~~545	$	3,~~684~~764

See accompanying notes.

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EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2009			2008			2007
	2010			2009			2008
Cash flows from operating activities
Net income	$	~~128~~83		$	~~135~~128		$	~~132~~135
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		8388			8083			8280
Deferred income tax expense (benefit)		(326	)		14(3	)		3714
Loss on long-lived assets		—			14—			914
Other non-cash income items		(622	)		12(6	)		812
Asset and liability changes
Accounts receivable		1050			310			93
Accounts payable		55			(65	)		65
Change in deferred purchase price from accounts receivable sales		(13	)		—			—
Taxes payable		12			24			(27	)
Accounts payable		(21	)		55			(65	)
Other current assets		(4	)		(13	)		(5	)
Taxes payable		(66	)		12			24
Other current liabilities		80			(13	)		(88	)
Other current assets		(2	)		(4	)		(13	)
Non-current assets		(55	)		56			(66	)
Other current liabilities		(103	)		80			(13	)
Non-current liabilities		8			8			(31	)
Non-current assets		(18	)		(55	)		56
Net cash provided by operating activities		308			255			125
Non-current liabilities		5			8			8
Net cash provided by operating activities		51			308			255
Cash flows from investing activities
Capital expenditures		(~~116~~80	)		(~~186~~116	)		(~~120~~186	)
Net change in note receivable from affiliate		(3152	)		~~127~~(3	)		~~(43~~127	)
Proceeds from disposal of property		144			—14			—
Other		(32	)		4(3	)		24
Net cash used in investing activities		(108	)		(55	)		(161	)
Net cash provided by (used in) investing activities		78			(108	)		(55	)
Cash flows from financing activities
Dividends paid to parent		(200	)		(200	)		—
Dividends paid to parent, net of contribution		(75	)		(200	)		(200	)
Net proceeds from issuance of long-term debt		—			—			350
Payments to retire long-term debt		(54	)		—			—
Payments to retire long-term debt		—			—			(314	)
Net cash used in financing activities		(129	)		(200	)		(200	)
Net cash provided by (used in) financing activities		(200	)		(200	)		36
Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—
End of period	$	—		$	—		$	—
Supplemental cash flow information
Interest paid, net of amounts capitalized	$	87		$	88		$	88
Income tax payments		87			71			45

See accompanying notes.

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EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In millions, except for share amounts)

	Common Stock				Additional ~~Paid-in~~		~~Retained~~			~~Accumulated Other Comprehensive~~Total			~~Total Stockholder’s~~
	Shares		Amount		Paid-in Capital		Retained Earnings			~~Loss~~Stockholder’s Equity			~~Equity~~
January 1, 2007		1,000	$	—	$	1,268	$	462		$	(4	)	$	1,726
January 1, 2008		1,000	$	—	$	1,268	$	594		$	1,862
Net income								~~132~~135			135			~~132~~
Reclassification to regulatory asset (Note 7)											4			4
Dividend paid to parent								(200	)		(200	)
December 31, 2007		1,000		—		1,268		594			—			1,862
Adoption of accounting standard updates related to postretirement benefits, net of income tax of less than $1 (Note 8)								1			1
Net income								135						135
December 31, 2008		1,000		—		1,268		530			1,798
Dividend paid to parent								(200	)					(200	)
Net income								128			128
Adoption of accounting standard updates related to postretirement benefits, net of income tax of less than $1 (Note 7)								1						1
Dividend paid to parent								(200	)		(200	)
December 31, 2008		1,000		—		1,268		530			—			1,798
December 31, 2009		1,000		—		1,268		458			1,726
Net income								~~128~~83			83			~~128~~
Dividend paid to parent								(200	)					(200	)
Dividend paid to parent, net of contribution								(75	)		(75	)
December 31, 2009		1,000	$	—	$	1,268	$	458		$	—		$	1,726
December 31, 2010		1,000	$	—	$	1,268	$	466		$	1,734

See accompanying notes.

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EL PASO NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

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

We consolidate entities when we ~~either (i)~~ have the ability to control or direct the operating and financial decisions ~~and policies~~ of ~~that~~the entity or ~~(ii)~~when ~~are~~we ~~allocated~~have a ~~majority of~~significant interest in the entity’s ~~losses~~that ~~and/or~~gives ~~returns~~us ~~through~~the ~~our~~ability ~~interests~~to indirect the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an ~~entity~~ ~~and whether we are allocated a majority of the~~ entity’s ~~losses and/or returns~~ involves the use of judgment.

Use of Estimates

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

Regulated Operations

Our natural gas pipelines and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) ~~under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978~~ and ~~the Energy Policy Act of 2005. We~~ follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, 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 are expected to 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, loss on reacquired debt, taxes related to an equity return component on regulated capital projects and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

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

Materials and Supplies

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

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Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount to be delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled in cash or in-kind, subject to the terms of our tariff.

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

Property, Plant and Equipment

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

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the ~~FERC-accepted~~ depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We ~~For certain~~re-evaluate ~~general~~depreciation ~~plant~~rates ~~and~~each ~~rights-of-way,~~time we ~~depreciate~~file with the ~~asset~~FERC tofor ~~zero.~~an increase or decrease in our transportation and storage rates. The majority of our property, plant and equipment are on our El Paso Natural Gas Company (EPNG) system which has depreciation rates ranging from one percent to 2050 percent ~~and depreciable lives ranging from five to 92 years consistent with our rate settlements with the FERC~~. The depreciation rates on our Mojave Pipeline Company (Mojave) system range from two percent to 33 percent per year. ~~We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage rates.~~

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

Included in our property balances are additional acquisition costs, ~~of $152 million~~ which represent the excess ~~of allocated~~ purchase costs ~~over~~associated ~~the~~with ~~historical~~purchase ~~costs~~business ~~of the~~combinations ~~facilities.~~allocated to us. These costs are amortized on a straight-line basis ~~over a remaining life of 23 years,~~ and weare do not ~~recover~~recoverable ~~these excess costs~~ in our rates under current FERC policies. ~~At December 31, 2009 and 2008, we had unamortized additional acquisition costs of $55 million and $58 million.~~

AtWe ~~December~~capitalize ~~31, 2009~~a ~~and~~carrying ~~2008,~~cost we(an ~~had~~allowance ~~$63~~for ~~million~~funds used during construction or AFUDC) on debt and ~~$54~~equity ~~million~~funds ofrelated to the construction ~~work~~ of long-~~in-progress~~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 the average cost of debt. Interest costs capitalized are included inas ~~our~~a ~~property,~~reduction ~~plant~~to interest and ~~equipment~~debt expense on our income statements. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.

We capitalize a carrying cost (an allowance for funds used during construction) on debt and equity funds related to our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs capitalized during the years ended December 31, 2009, 2008 and 2007, were less than $1 million, $1 million and $1 million. These debt amounts are included as a reduction to interest and debt expense on our income statement. The equity portion is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized (exclusive of taxes) during the years ended December 31, 2009, 2008 and 2007, were $1 million, $3 million and $2 million. These equity amounts are included in other income on our income statement.

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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~~If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. ~~The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sale, among other factors.~~

During 2008, we recorded impairments of approximately $14 million due to declining real estate values related to our Arizona storage projects, which we are no longer developing.

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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 ratably 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. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

Environmental Costs and Other Contingencies

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

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

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

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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.

We record income taxes on a separate return basis. Pursuant to El Paso’s policy, we record current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

We are required to evaluate our tax positions for all jurisdictions and for all years where the statute of limitations has not expired and we are required to meet a more-likely-than-not threshold (i.e. a greater than 50 percent likelihood of a tax position being sustained under examination) prior to recording a tax benefit. Additionally, for tax positions meeting this more-likely-than-not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon effective settlement.29

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are initially 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 asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.

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

We are required to operate and maintain our natural gas pipeline and storage systems, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that the substantial majority of our natural gas pipelines and storage system assets have indeterminate lives. Accordingly, our asset retirement liabilities as of December 31, 2009 and 2008, were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

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Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are initially 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 asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid ~~out~~ under the plan. These contributions are invested until the benefits are paid ~~out~~ to plan participants. WeThe ~~record the~~ net benefit cost ~~related~~of to this plan is recorded in our income statement. ~~This~~and ~~net benefit cost~~ is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 78.

In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.

Effective January 1, 2008, we adopted the provisions of an accounting standard update related to the measurement date and changed the measurement date of our postretirement benefit plan from September 30 to December 31. We recorded an increase of $1 million, net of income taxes of less than $1 million, to our January 1, 2008 retained earnings balance upon the adoption of the measurement date provisions of this standard.

Effective December 31, 2009, we expanded our disclosures about postretirement benefit plan assets as a result of new disclosure requirements. See Note 7 for these expanded disclosures.

2. Income Taxes

El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. With a few exceptions, we and El Paso are no longer subject to state and local income tax examinations by tax authorities for years prior to 1999 and U.S. income tax examinations for years prior to 2007. In November 2009, the Internal Revenue Service’s examination of El Paso’s U.S. income tax returns for 2005 and 2006 was settled at the appellate level. The settlement of issues raised in this examination did not materially impact our results of operations, financial condition or liquidity. For our open tax years, we have no unrecognized tax benefits (liabilities for uncertain tax matters).

Components of Income Tax Expense. The following table reflects the components of income tax expense included in net income for each of the three years ended December 31:

	2009			2008			2007
	2010			2009			2008
	(In millions)
Current
Federal	$	7219		$	6172		$	4061
State		102			810			68
		82			69			46
		21			82			69
Deferred
Federal		(326	)		12(3	)		3212
State		—			2—			52
		(3	)		14			37
		26			(3	)		14
Total income tax expense	$	7947		$	8379		$	83

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Effective Tax Rate Reconciliation. Our income tax expense differs 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:

	2009			2008			2007
	2010			2009			2008
	(In millions, except for rates)
Income tax expense at the statutory federal rate of 35%	$	7246		$	7672		$	7576
State income taxes, net of federal income tax effect		71			7			7
Non-deductible expenses		—			—			1
Income tax expense	$	47		$	79		$	83
Income tax expense	$	79		$	83		$	83
Effective tax rate		36	%		38	%		38	%
Effective tax rate		38	%		38	%		39	%

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

	2009		2008
	2010		2009
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	~~482~~483	$	~~468~~482
Regulatory and other assets		2829		2728
Total deferred tax liability		~~510~~512		~~495~~510
Deferred tax assets
U.S. net operating loss and tax credit carryovers		77		77
Regulatory and other reserve		3312		833
Other liabilities		2724		3327
Total deferred tax asset		~~137~~113		~~118~~137
Net deferred tax liability	$	~~373~~399	$	~~377~~373

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

Tax Credits and Carryovers. As of December 31, ~~2009~~2010, we had approximately $19 million of alternative minimum tax credits that carryover indefinitely. We also have approximately $167 million of net operating loss carryovers that expire between ~~2019~~2021 and 2028. 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.

Unrecognized Tax Benefits. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. With a few exceptions, we and El Paso are no longer subject to state and local income tax examinations by tax authorities for years prior to 1999 and U.S. income tax examinations for years prior to 2007. For our open tax years, we have no unrecognized tax benefits.

3. Fair Value of Financial Instruments

At December 31, ~~2009~~ 2010 and ~~2008~~2009, the carrying amounts of cash and cash equivalents and trade receivables and payables ~~are~~represented ~~representative of their~~ fair value because of the short-term nature of these instruments. At December 31, ~~2009~~ 2010 and ~~2008~~2009, we had an interest bearing note receivable from El Paso of approximately $0.8 billion and $1.0 billion due upon demand, with a variable interest rate of 1.5% ~~and 3~~.~~2%.~~ While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:

	2009				2008
	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt, including current maturities	$	1,~~167~~113	$	1,~~300~~258	$	1,~~166~~167	$	1,~~021~~300

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4. Regulatory Assets and Liabilities

Our ~~current~~ regulatory assets ~~are included in other current assets on our balance sheets. Our non-current regulatory assets~~ and liabilities are included in other current/non-current assets and liabilities on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:

	2009		2008
	2010		2009
	(In millions)
Current regulatory assets
Deferred fuel lost and unaccounted for gas	$	7	$	5
Difference between gas retained and gas consumed in operations	$	5	$	7
Other		32		23
Total current regulatory assets		107		710
Non-current regulatory assets
Taxes on capitalized funds used during construction		2422		2224
Unamortized loss on reacquired debt		2421		2724
Postretirement benefits		86		98
Under-collected state income taxes		5		6
Other		9		9
Other		4		4
Total non-current regulatory assets		58		65
Total non-current regulatory assets		65		68
Total regulatory assets	$	65	$	75
Total regulatory assets	$	75	$	75
Current regulatory liabilities
Property and plant depreciation	$	31	$	53
Gas retained and not used in operations		5		15
Difference between gas retained and gas consumed in operations		5		5
Pipeline integrity program		—		3
Other		1		9
Other		9		10
Total current regulatory liabilities		7		17
Total current regulatory liabilities		17		33
Non-current regulatory liabilities
Property and plant depreciation		3024		3730
Postretirement benefits		1517		415
Excess deferred federal income taxes		2		2
Other		2		2
Total non-current regulatory liabilities		4743		4347
Total regulatory liabilities	$	6450	$	7664

The significant regulatory assets and liabilities include:

~~Deferred~~Difference ~~Fuel~~Between ~~Lost~~Gas Retained and ~~Unaccounted for~~ Gas Consumed in Operations. These amounts reflect the value of the volumetric difference between the gas retained ~~from our customers~~ and ~~the gas~~ consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers or ~~refunded~~returned to our customers in subsequent fuel filing periods.

Taxes on Capitalized Funds Used During Construction. ~~These~~Regulatory ~~regulatory~~ asset ~~balances~~balance ~~were~~ established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base~~. Both~~ and are recovered over the depreciable lives of the long-lived asset to which they relate.

Unamortized Loss on Reacquired Debt. ~~These~~Amount ~~amounts~~represents ~~represent~~ the deferred and unamortized portion of losses on reacquired debt ~~and~~which are ~~not included in the rate base, but are~~ recovered over the original life of the debt issue through the ~~authorized~~cost ~~rate~~ of ~~return~~service.

Postretirement Benefits. ~~These~~ Represents ~~balances represent deferred amounts related to~~ unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts ~~recoverable~~recovered in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.

Property and Plant Depreciation. Amounts represent the deferral of customer-funded amounts for costs of future asset retirements.

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5. ~~Debt~~ ~~and~~Property, ~~Credit~~Plant ~~Facilities~~and Equipment

Additional Acquisition Cost. Included in our property balances are additional acquisition costs assigned to utility plant, which represent the excess of allocated purchase costs over the historical costs of the facilities. At December 31, 2010 and 2009, additional acquisition costs assigned to utility plant was approximately $151 million and accumulated depreciation was approximately $99 million and $96 million, respectively. These additional acquisition costs are being amortized on a straight-line basis over a remaining life of 22 years, and are not recoverable in our rates under current FERC policies. Our amortization expense related to additional acquisition cost assigned to utility plant was approximately $2 million for the years ended December 31, 2010, 2009 and 2008.

Capitalized Costs During Construction. Interest costs capitalized were less than $1 million during the years ended December 31, 2010 and 2009 and $1 million during the year ended December 31, 2008. Equity amounts capitalized were $1 million, $1 million and $3 million (exclusive of taxes) during the years ended December 31, 2010, 2009 and 2008.

Construction Work-In-Progress. At December 31, 2010 and 2009, we had $36 million and $63 million of construction work-in-progress included in our property, plant and equipment.

Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipelines, 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 primarily involve 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 ever demolished or replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

We are required to operate and maintain our natural gas pipelines and storage system, 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 we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipelines and storage system assets because these assets have indeterminate lives. Our asset retirement liabilities as of December 31, 2010 and 2009, were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

6. Debt and Credit Facilities

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

	2009		2008
	2010		2009
	(In millions)
7.625% Notes due August 2010	$	54—	$	54
5.95% Notes due April 2017		355		355
8.625% Debentures due January 2022		260		260
7.50% Debentures due November 2026		200		200
8.375% Notes due June 2032		300		300
		1,169		1,169
		1,115		1,169
Less: Current maturities of long-term debt		54		—
Less: Current maturities		—		54
Unamortized discount		2		32
Total long-term debt	$	1,113	$	1,~~166~~113

~~Credit~~In ~~Facility.~~August We2010, ~~are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts~~ we ~~directly~~repaid ~~borrow. As of December 31, 2009, El Paso had~~ approximately $~~0.8~~54 ~~billion~~million of ~~capacity remaining and available to us and~~ our ~~affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us~~7.625% ~~Our~~notes ~~common~~that ~~stock and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement~~matured.

Under El Paso’s $1.5 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; and (vi) potential limitations on our ability to participate in the El Paso’s cash management program. The indentures governing some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. For the year ended December 31, 2009, we were in compliance with our debt-related covenants.33

~~6. Commitments~~Table ~~and~~of ~~Contingencies~~Contents

Credit Facility. We are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2010, El Paso had approximately $0.9 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. Our common stock and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement.

Under El Paso’s $1.5 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; and (vi) potential limitations on our ability to participate in the El Paso’s cash management program. The indentures governing some of our long-term debt contain cross-acceleration provisions, the most restrictive of which is $25 million. For the year ended December 31, 2010, we were in compliance with our debt-related covenants.

7. Commitments and Contingencies

Legal Proceedings

~~Baldonado~~Bank of America. We are a named defendant, along with Burlington Resources, Inc. (Burlington), now a subsidiary of ConocoPhillips Company, in a class action lawsuit styled Bank of America, et al. v. ~~EPNG.~~El ~~In August~~Paso ~~2000,~~Natural aGas ~~main~~and ~~transmission~~Burlington ~~line~~Resources ~~owned~~Oil and ~~operated~~Gas byCompany, usL.P., ~~ruptured~~filed atin October 2003 in the ~~crossing~~ District Court of ~~the~~Kiowa ~~Pecos~~County, ~~River~~Oklahoma ~~near~~asserting ~~Carlsbad~~royalty underpayment claims related to specified shallow wells in Oklahoma, Texas and New Mexico. ~~Individuals~~The atPlaintiffs ~~the~~assert ~~site~~ that royalties were ~~fatally~~underpaid ~~injured.~~starting Inin ~~June~~the ~~2003,~~1980s awhen ~~lawsuit~~the ~~entitled~~purchase ~~Baldonado~~price etof algas was lowered below the Natural Gas Policy Act maximum lawful prices. The vPlaintiffs have not alleged an amount of damages against any defendant. We ~~EPNG~~believe ~~was filed~~that our actions in ~~state~~the ~~court~~1980s were proper in ~~Eddy~~light ~~County,~~of ~~New~~a ~~Mexico~~declining market. We also contend that we are entitled to an indemnity from Burlington under our 1992 separation agreement for all claims related to royalty payments, onwhich ~~behalf~~Burlington denies. The Plaintiffs assert that royalties were further underpaid by Burlington as a result of 26post-production ~~firemen~~cost ~~and emergency~~deductions ~~medical~~taken ~~service~~starting ~~personnel~~in ~~who~~the ~~responded~~late to1990s. We have no liability for the ~~fire~~post-production ~~and~~claims ~~who~~as ~~allegedly have~~they ~~suffered~~pertain ~~psychological~~to ~~trauma~~periods after our separation from Burlington. This ~~After~~action awas ~~trial~~transferred ~~which~~to ~~began~~Washita County District Court in ~~October~~2004. ~~2009,~~A ~~a jury~~tentative ~~returned~~settlement areached ~~verdict~~in November 2005 was rejected by the court in ~~our~~June ~~favor~~2007. A class certification hearing occurred in ~~December~~April 2009. ~~Subsequently,~~ The ~~the firemen~~court certified a Texas and ~~emergency~~Oklahoma ~~medical~~class ~~service~~of ~~personnel~~royalty ~~agreed~~owners and stayed the claims pertaining to ~~waive~~New ~~their~~Mexico ~~right~~wells. The class certification has been appealed to ~~appeal~~ the Oklahoma Court of Appeals. The AsPlaintiffs ahave ~~result,~~proceeded with discovery of the post-production claims against Burlington. Our costs and legal exposure related to this ~~case~~lawsuit ~~was~~are ~~closed~~not currently determinable.

~~Gas~~In ~~Measurement~~addition ~~Cases.~~to Wethe ~~and a~~above ~~number~~proceeding, ofwe and our affiliates ~~were~~are named defendants in ~~actions~~numerous legal proceedings and claims that ~~generally allege~~arise ~~mismeasurement~~in the ordinary course of ~~natural~~our ~~gas~~business. ~~volumes~~For ~~and/or~~each ~~heating~~of ~~content~~these ~~resulting~~matters, in we evaluate the ~~underpayment~~merits of ~~royalties.~~the ~~The~~case ~~first~~or ~~set~~claim, ofour ~~cases~~exposure ~~was~~to ~~filed~~the inmatter, ~~1997~~possible bylegal ~~an individual~~or ~~under~~settlement strategies and the ~~False~~likelihood ~~Claims~~of ~~Act~~an ~~and~~unfavorable ~~have~~outcome. ~~been~~If ~~consolidated~~we ~~for~~determine ~~pretrial purposes~~that ~~(In~~an ~~re:~~unfavorable ~~Natural~~outcome ~~Gas Royalties~~is ~~Qui~~probable ~~Tam~~and ~~Litigation~~can be estimated, ~~U.S.~~we ~~District~~establish ~~Court~~the ~~for~~necessary accruals. While the ~~District~~outcome of ~~Wyoming).~~ ~~These~~these ~~complaints~~matters, ~~allege~~including anthose ~~industry-wide~~discussed ~~conspiracy~~above, tocannot ~~underreport~~be ~~the heating~~predicted ~~value~~with ascertainty, ~~well~~and asthere ~~the~~are ~~volumes~~still ofuncertainties related to the ~~natural~~costs ~~gas~~we ~~produced~~may ~~from~~incur, ~~federal~~ based upon our evaluation and ~~Native~~experience ~~American~~to ~~lands~~date, we believe we have established appropriate reserves for these matters. InIt ~~October~~is ~~2006~~possible, ~~the~~however, ~~U.S.~~that ~~District~~new ~~Judge~~information ~~issued~~or ~~an order~~future ~~dismissing~~developments ~~all~~could ~~claims~~require ~~against~~us ~~all~~to ~~defendants.~~reassess Inour ~~March~~potential ~~2009~~exposure related to these matters and adjust our accruals accordingly, ~~the~~and ~~Tenth Circuit~~these ~~Court~~adjustments could be material. As of ~~Appeals~~December ~~affirmed~~31, ~~the~~2010, ~~dismissals~~we ~~and~~had inapproximately ~~October~~$4 ~~2009~~million accrued, ~~the plaintiff’s~~which ~~appeal~~has tonot ~~the~~been ~~United~~reduced ~~States~~by ~~Supreme~~$4 ~~Court~~million ~~was~~of ~~denied~~related insurance receivables, for our outstanding legal proceedings.

Similar allegations were filed in a 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 seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. 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. In September 2009, the court denied the motions for class certification. The plaintiffs have filed a motion for reconsideration. Our costs and legal exposure related to this lawsuit and claims are not currently determinable.34

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Bank of America. We are a named defendant, along with Burlington Resources, Inc. (Burlington), now a subsidiary of ConocoPhillips Company, in a class action lawsuit styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, L.P., filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting royalty underpayment claims related to specified shallow wells in Oklahoma, Texas and New Mexico. The Plaintiffs assert that royalties were underpaid starting in the 1980s when the purchase price of gas was lowered below the Natural Gas Policy Act maximum lawful prices. The Plaintiffs assert that royalties were further underpaid by Burlington as a result of post-production cost deductions taken starting in the late 1990s. This action was transferred to Washita County District Court in 2004. A tentative settlement reached in November 2005 was disapproved by the court in June 2007. A class certification hearing occurred in April 2009. The court certified a Texas and Oklahoma class of royalty owners. The class certification has been appealed to the Oklahoma Court of Appeals. A companion case styled Bank of America v. El Paso Natural Gas involving similar claims made as to certain wells in Oklahoma was settled in 2006. Our costs and legal exposure related to this lawsuit are not currently determinable.

In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2009, we had accrued approximately $2 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 of the disposal or release of specified substances at current and former operating sites. At December 31, ~~2009~~2010 and ~~2008~~2009, we had accrued approximately $1916 million and $2219 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $4030 million at December 31, ~~2009~~2010. Our accrual at December 31, ~~2009~~ 2010 includes $1715 million for environmental contingencies related to properties we previously owned.

Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will ~~expend~~spend 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.

~~Comprehensive~~Superfund ~~Environmental Response,~~Matters. ~~Compensation~~Included ~~and~~in ~~Liability~~our ~~Act~~recorded ~~(CERCLA)~~environmental ~~Matters.~~liabilities Weare projects where we have received notice that we ~~could~~have bebeen designated, or ~~have been asked for information to determine whether we~~ could be designated, as a Potentially Responsible Party (PRP) ~~with respect to three active sites~~ under the ~~CERCLA~~Comprehensive orEnvironmental ~~state~~Response, ~~equivalents. We~~Compensation ~~have sought to resolve our liability as a PRP at these sites through indemnification by third parties~~ and ~~settlements,~~Liability ~~which~~Act ~~provide for payment of our allocable share of remediation costs. As of December 31~~(CERCLA), ~~2009,~~commonly weknown ~~have estimated our share of the remediation costs at these sites to be between $8 million and $14 million. Because the clean-up costs are estimates and are subject to revision~~ as ~~more information becomes available about the extent of remediation required~~Superfund, ~~and~~or instate ~~some~~equivalents ~~cases~~for wethree ~~have~~active ~~asserted a defense to any liability, our estimates could change~~sites. ~~Moreover,~~Liability ~~liability~~ under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. ~~Our~~We ~~understanding~~consider of the financial strength of other PRPs ~~has been considered, where appropriate,~~ in estimating our liabilities. Accruals for these ~~matters~~issues are included in the environmental reserve discussed above.

36For 2011, we estimate that our total remediation expenditures will be approximately $4 million, which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of $3 million in the aggregate for 2011 through 2015, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines, which are subject to regulations with which we have to be in compliance by October 2013.

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For 2010, we estimate that our total remediation expenditures will be approximately $4 million, which will be expended under government directed clean-up plans.

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

Rates and Regulatory ~~Matter~~Matters

EPNG Rate Case. In ~~June~~April ~~2008~~2010, we ~~filed a rate case with~~ the FERC asapproved ~~required~~an ~~under~~uncontested ~~the~~partial ~~settlement~~offer of ~~our previous~~settlement ~~rate~~which ~~case.~~increased ~~The~~our ~~filing~~base ~~proposed~~tariff anrates, ~~increase~~effective inJanuary ~~base~~1, ~~tariff~~2009. As ~~rates~~part onof ~~our EPNG~~the ~~system~~settlement, ~~which~~we ~~would~~made ~~increase~~refunds ~~revenue~~of byapproximately $8376 million, ~~annually~~plus ~~over previously~~interest, ~~effective~~in ~~tariff rates~~2010. The Insettlement ~~August~~resolved ~~2008,~~all ~~the~~but ~~FERC~~four ~~issued~~issues anin ~~order accepting~~ the ~~proposed~~proceeding. In ~~rates effective~~ January 12011, ~~2009, subject to refund and~~ the ~~outcome~~Presiding ofAdministrative aLaw ~~hearing~~Judge ~~and a technical conference. The FERC~~ issued anher ~~order~~decision ~~in December 2008,~~ that ~~generally~~for ~~accepted~~the most ofpart ~~our~~found ~~proposals~~against inus on the ~~technical conference~~four ~~proceeding~~issues. We ~~The~~will ~~FERC~~appeal ~~has~~those ~~appointed~~decisions anto ~~administrative~~the ~~law~~FERC ~~judge~~and ~~to preside~~may ~~over~~also aseek ~~hearing~~review ifof weany ~~are~~of ~~unable~~the toFERC’s ~~reach~~decisions ato ~~negotiated~~the ~~settlement~~U.S. ~~with our~~Court ~~customers~~of onAppeals. Although the ~~remaining~~final ~~issues.~~outcome ~~Settlement~~is ~~negotiations~~not ~~are~~currently ~~continuing; however~~determinable, ~~the~~we ~~hearing~~do ~~has~~not ~~been~~believe ~~postponed~~our ~~until~~refund ~~May~~exposure ~~2010. The~~is ~~outcome of~~material ~~the~~and ~~settlement~~we ~~discussions~~believe orour ~~the~~accruals ~~hearing~~established isfor ~~not~~this ~~currently determinable~~matter are adequate.

~~Other Matters~~In September 2010, we filed a new rate case with the FERC proposing an increase in base tariff rates as permitted under the settlement of the previous rate case. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not currently determinable.

~~Navajo Nation.~~ In ~~March~~October ~~2009~~2010, ~~representatives~~ ofwe ~~the~~filed ~~Navajo~~with ~~Nation~~the ~~and~~FERC ~~EPNG~~to ~~executed~~permanently aabandon ~~final~~two ~~agreement~~compressor ~~setting forth~~stations ~~the full terms~~ and ~~conditions~~temporarily ofidle ~~the~~seven ~~Navajo~~compressor ~~Nation’s~~stations ~~consent~~along toour ~~EPNG’s rights-of-way~~south ~~through~~mainline ~~the~~system ~~Navajo~~in ~~Nation~~2011. This ~~Under~~was ~~this~~done ~~agreement,~~to webetter ~~will~~align ~~make annual~~our ~~payments~~capacity ofto ~~approximately~~the ~~$19~~current ~~million~~lower ~~for~~level ~~our rights-~~of~~-way~~ ~~beginning~~contract ~~in 2009~~demand ~~and~~resulting ~~continuing~~from, ~~through~~in ~~2025~~part, ~~subject~~the toweakened ~~annual~~economic ~~adjustments~~conditions along this line. ~~We submitted~~Our ~~the~~intent ~~Navajo~~is ~~Nation’s~~to ~~consent~~bring ~~agreement~~the inidled ~~support~~facilities ofback ~~our~~into ~~pending application~~service toover the ~~United~~next ~~States~~several ~~Department~~years ofas ~~the~~market ~~Interior~~demand ~~(the~~improves. In ~~Department)~~our ~~for an~~2011 ~~extension~~rate ofcase, ~~the~~we ~~Department’s~~did ~~current~~not ~~rights-of-way~~seek ~~grant.~~to Weearn ~~expect~~a return on the ~~submission~~ ~~will~~original ~~result~~investment in the ~~Department’s~~idled ~~final~~facilities. We ~~processing~~will ofcontinue ~~our~~to incur ~~application. We~~related ~~have~~operating ~~filed~~costs ~~with~~and depreciation expense until the compressor stations are idled once approved by the FERC. These ~~for~~filings ~~recovery~~have ofbeen ~~payments~~protested ~~under~~by ~~rights-of-way~~certain ininterveners ~~our recent~~and ~~rate~~the ~~case~~result is uncertain at this time.

Tuba City Uranium Milling Facility. For a period of approximately ten years beginning in the mid to late 1950s, Rare Metals Corporation of America, a historical affiliate, conducted uranium mining and milling operations in the vicinity of Tuba City, Arizona, under a contract with the United States government as part of the Cold War nuclear program. The site of the Tuba City uranium mill, which is on land within the Navajo Indian Reservation, reverted to the Navajo Nation after the mill closed in 1966. The tailings at the mill site were encapsulated and a ground water remediation system was installed by the U.S. Department of Energy (DOE) under the Federal Uranium Mill Tailings Radiation Control Act of 1978. In May 2007, we filed suit against the DOE and other federal agencies requesting a judicial determination that the DOE was fully and legally responsible for any remediation of any waste associated with historical uranium production activity at two sites in the vicinity of the mill facilities near Tuba City, Arizona. In March 2009, the United States District Court for the District of Columbia issued an opinion dismissing one of our claims, for which we intend to make an appeal. Also in March 2009, following our close cooperation with the Navajo Nation in joint legislative efforts, President Obama signed the Fiscal Year 2009 Omnibus Appropriations Act, which appropriated $5 million toward the final remediation by the DOE of one of the two sites that are the subject of our lawsuit. The DOE has assigned to the Navajo Nation the obligation to remediate the site. We anticipate that the Navajo Nation will perform the remediation in the near future, and we are continuing to maintain the interim site control measures we have installed at the site.35

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Other Matter

Tuba City Uranium Milling Facility. For a period of approximately ten years beginning in the mid to late 1950s, Rare Metals Corporation of America, a historical affiliate, conducted uranium mining and milling operations in the vicinity of Tuba City, Arizona, under a contract with the United States government as part of the Cold War nuclear program. The site of the Tuba City uranium mill, which is on land within the Navajo Indian Reservation, reverted to the Navajo Nation after the mill closed in 1966. The tailings at the mill site were encapsulated and a ground water remediation system was installed by the U.S. Department of Energy (DOE) under the Federal Uranium Mill Tailings Radiation Control Act of 1978. In May 2007, we filed suit against the DOE and other federal agencies requesting a judicial determination that the DOE was fully and legally responsible for any remediation of any waste associated with historical uranium production activity at two sites in the vicinity of the mill facilities near Tuba City, Arizona. In March 2009, the United States District Court for the District of Columbia issued an opinion dismissing one of our claims, which has been affirmed by the Court of Appeals for the D.C. Circuit. Also in March 2009, following our close cooperation with the Navajo Nation in joint legislative efforts, President Obama signed the Fiscal Year 2009 Omnibus Appropriations Act, which appropriated $5 million toward the final remediation by the DOE of one of the two sites that are the subject of our lawsuit. The DOE has assigned to the Navajo Nation the obligation to remediate the site. We anticipate that the Navajo Nation will perform the remediation in the near future, and we are continuing to maintain the interim exposure control measures we have installed at the site. Additionally, the EPA and Bureau of Indian Affairs (BIA) have entered into an administrative order of consent, pursuant to which the BIA will conduct a remedial investigation/feasibility study at the second site involved in the lawsuit. Finally, the EPA is currently assessing the environmental condition of all former uranium mines on the Navajo Indian Reservation to determine the need for further environmental response activities. There are approximately 500 abandoned uranium mine sites on the Navajo Indian Reservation, 16 of which were operated by the historical affiliate.

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

Other Commitments

Capital Commitments. We have planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

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Operating Leases. We lease property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, 2010, were as follows:

Year Ending December 31,	(In millions)
2011	$	3
2012		3
2013		3
2014		3
2015		1
Thereafter		1
Total	$	14

Rental expense for the years ended December 31, 2010, 2009 and 2008 was $23 million, $21 million and $22 million and is reflected in operation and maintenance expense. Included in rental expense is approximately $20 million in each period associated with right-of-way and other arrangements, principally related to a long-term commitment which extends through 2025.

Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems.

Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of financial and performance guarantees that are not recorded in our financial statements. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. During 2010, we terminated our performance guarantees which had a maximum exposure of approximately $11 million.

8. Retirement Benefits

Pension and Retirement Savings Plan. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits Plan. We provide postretirement medical benefits for a closed group of employees who retired on or before March 1, 1986, and limited postretirement life insurance for employees who retired after January 1, 1985. As such, our obligation to accrue for other postretirement employee benefits is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We do not expect to make any contributions to our postretirement benefit plan in 2011.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability as allowed by the FERC. These amounts would otherwise be recorded in accumulated other comprehensive income for non-regulated entities.

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~~Other Commitments~~The table below provides information about our postretirement benefit plan:

Capital Commitments. At December 31, 2009, we had capital commitments of approximately $2 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.

	December 31,
	2010			2009
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation – beginning of period	$	47		$	52
Interest cost		2			3
Actuarial (gain) loss		4			(4	)
Benefits paid(1)		(3	)		(4	)
Accumulated postretirement benefit obligation – end of period	$	50		$	47
Change in plan assets:
Fair value of plan assets – beginning period	$	79		$	71
Actual return on plan assets		9			13
Benefits paid		(4	)		(5	)
Fair value of plan assets – end of period	$	84		$	79
Reconciliation of funded status:
Fair value of plan assets	$	84		$	79
Less: accumulated postretirement benefit obligation		50			47
Net asset at December 31	$	34		$	32

~~Operating Leases. We lease~~____________ ~~property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, 2009, were as follows:~~

Year Ending December 31,
	(In millions)
2010	$	3
2011		3
2012		3
Thereafter		6
Total	$	15

(1) Amounts shown net of a subsidy of approximately $1 million for each of the years ended December 31, 2010 and 2009 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

~~Rental~~Plan ~~expense~~Assets. on The primary investment objective of our ~~lease~~plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the benefit obligations ~~for~~to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the ~~years~~result ~~ended~~of ~~December~~economic ~~31,~~and ~~2009~~capital market conditions. Although actual allocations vary from time to time from our targeted allocations, ~~2008~~the target allocations of our postretirement plan’s assets are 65 percent equity and ~~2007~~35 ~~was $21~~percent ~~million~~fixed income securities. We may invest plan assets in a manner that replicates, ~~$22~~to ~~million~~the extent feasible, the Russell 3000 Index and ~~$20~~the ~~million.~~Barclays ~~These~~Capital ~~amounts~~Aggregate ~~include~~Bond ~~rent~~Index ~~allocated~~ to usachieve ~~from~~equity Eland ~~Paso~~fixed income diversification, respectively.

~~Other~~We ~~Commercial Commitments~~use various methods to determine the fair values of the assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We ~~hold~~separate ~~cancelable~~these ~~easements~~assets orinto ~~rights-~~three levels (Level 1, 2 and 3) based on our assessment of~~-way arrangements~~ ~~from~~the ~~landowners~~availability ~~permitting~~of this market data and the ~~use~~significance of ~~land~~non-observable ~~for~~data used to determine the ~~construction~~fair ~~and operation~~value of ~~our~~these ~~pipeline systems~~assets. As Weof ~~have~~December ~~executed~~31, a2010, ~~long-term~~assets ~~rights~~were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $82 million. As of December 31, 2009, assets were comprised of an exchange-~~way agreement~~traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $77 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the ~~Navajo~~price ~~Nation~~quoted for the fund in actively traded markets. Our common collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which ~~will~~are ~~result~~considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common collective trust funds where the issuer reserves the right to temporarily delay withdrawals in certain situations such as market conditions or at the issuer's discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a ~~significant~~fair ~~commitment by~~value usthat ~~upon~~may ~~approval~~not be indicative of ~~our~~net ~~pending~~realizable ~~application~~value ~~with~~or reflective of future fair values, and there have been no changes in the ~~Department~~methodologies ofused ~~Interior (see~~at ~~Navajo~~December ~~Nation above)~~31, 2010 and 2009.

Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of financial and performance guarantees that are not recorded in our financial statements. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. As of December 31, 2009, we have financial and performance guarantees with a maximum exposure of approximately $11 million, not otherwise recognized in the financial statements.

7. Retirement Benefits

Pension and Retirement Savings Plan. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on its performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $4 million from accumulated other comprehensive loss to a regulatory asset.

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~~The~~Expected ~~table~~Payment ~~below provides~~of ~~information~~Future ~~about our postretirement benefit plan~~Benefits. In ~~2008, we~~As ~~adopted the FASB’s revised measurement date provisions for other postretirement benefit plans and the information below for 2008 is presented and computed as~~ of ~~and for the fifteen months ended~~ December 31, ~~2008. For~~ ~~2009~~2010, ~~the~~we ~~information~~expect ~~is presented and computed as of and for~~ the ~~twelve~~following ~~months~~benefit ~~ended~~payments ~~December~~under ~~31,~~our ~~2009.~~plan:

	December 31, 2009			December 31, 2008
Year Ending December 31,		Expected Payments(1)
	~~(In millions)~~	(In millions)
Change in accumulated postretirement benefit obligation:
2011		$	6
Accumulated postretirement benefit obligation - beginning of period	$	52		$	62
2012			5
Interest cost		3			5
2013			5
Actuarial gain		(4	)		(8	)
2014			5
Benefits paid(1)		(4	)		(7	)
2015			5
Accumulated postretirement benefit obligation - end of period	$	47		$	52
2016 - 2020			19
Change in plan assets:
Fair value of plan assets - beginning period	$	71		$	104
Actual return on plan assets		13			(25	)
Benefits paid		(5	)		(8	)
Fair value of plan assets - end of period	$	79		$	71
Reconciliation of funded status:
Fair value of plan assets	$	79		$	71
Less: accumulated postretirement benefit obligation		47			52
Net asset at December 31	$	32		$	19

____________

(1) ~~Amounts~~Includes ~~shown net of~~ a ~~subsidy~~reduction of approximately $1 million ~~for~~in each of the years ~~ended~~2011 ~~December~~– ~~31,~~2015 ~~2009~~ and ~~2008~~approximately $3 million in aggregate for 2016 – 2020 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

~~Plan~~Actuarial ~~Assets.~~Assumptions ~~The~~and ~~primary investment~~Sensitivity ~~objective~~Analysis. ofAccumulated ~~our~~postretirement ~~plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the~~ benefit obligations ~~to retirees~~ and ~~beneficiaries.~~net ~~Investment~~benefit ~~objectives~~costs are ~~long-term~~ inbased ~~nature~~on ~~covering~~actuarial ~~typical~~estimates ~~market~~and ~~cycles~~assumptions. ~~Any~~The ~~shortfall~~following oftable ~~investment performance~~details ~~compared to investment objectives is generally~~ the ~~result~~weighted ~~of economic~~average ~~and~~actuarial ~~capital~~assumptions ~~market~~used ~~conditions. Although~~in ~~actual~~determining ~~allocations vary from time to time from~~ our ~~targeted allocations, the target allocations of our~~ postretirement plan’s ~~assets~~obligations ~~are 65 percent equity~~ and 35net ~~percent~~benefit ~~fixed income~~costs ~~securities. We~~for ~~may invest assets in a manner that replicates~~2010, to ~~the~~2009 ~~extent feasible, the Russell 3000 Index~~ and ~~the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.~~2008:

We use various methods to determine the fair values of the assets in our other postretirement benefit plans, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2009, our assets are comprised of an exchange-traded mutual fund with a fair value of $2 million and common/collective trusts with a fair value of $77 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common/collective trusts are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. We may adjust the fair value of our common/collective trusts, when necessary, for factors such as liquidity or risk of nonperformance by the issuer. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2009 and 2008.

	2010		2009		2008
	(Percent)
Assumptions related to benefit obligations at December 31:
Discount rate		4.53		5.14		5.90
Assumptions related to benefit costs for the year ended December 31:
Discount rate		5.14		5.90		6.05
Expected return on plan assets(1)		7.75		8.00		8.00

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Expected Payment of Future Benefits. As of December 31, 2009, we expect the following benefit payments under our plan:

Year Ending December 31,	Expected Payments(1)
	(In millions)
2010	$	5
2011		5
2012		5
2013		5
2014		5
2015 - 2019		19

____________

(1) Includes a reduction of approximately $1 million in each of the years 2010 – 2014 and approximately $3 million in aggregate for 2015 – 2019 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2009, 2008 and 2007:

	2009		2008		2007
	(Percent)
Assumptions related to benefit obligations at December 31, 2009 and 2008 and September 30, 2007 measurement dates:
Discount rate		5.14		5.90		6.05
Assumptions related to benefit costs at December 31:
Discount rate		5.90		6.05		5.50
Expected return on plan assets(1)		8.00		8.00		8.00

____________

(1)

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

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 87.04 percent, gradually decreasing to 5.0 percent by the year ~~2015~~2016. 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 ~~2009~~2010 or ~~2008~~2009. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31, ~~2009~~2010 and ~~2008~~2009:

	2009			2008
	2010			2009
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	3		$	3
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(3	)	$	(3	)

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

	2009			2008			2007
	2010			2009			2008
	(In millions)
Interest cost	$	32		$	43		$	4
Expected return on plan assets		(5	)		(75	)		(67	)
Amortization of net actuarial gain		—			(2—	)		—(2	)
Net benefit income	$	(23	)	$	(52	)	$	(25	)

4039

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89. Transactions with Major Customers

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

	2009(1)		2008		2007
	2010(1)		2009(1)		2008
	(In millions)
ConocoPhillips Company(2)	$	124	$	82	$	47
ConocoPhillips Company	$	78	$	124	$	82
Sempra Energy and Subsidiaries (3)		89		85		93
Southern California Gas Company		74		89		85
Southwest Gas Corporation		64		*		*

____________

(1)	Revenues reflect rates subject to refund.

~~(2)~~* InLess ~~2007, ConocoPhillips Company did not represent more~~ than 10% ~~percent~~ of ~~our~~operating revenues.

~~(3)~~10. ~~Amounts~~Accounts ~~include~~Receivable ~~revenues~~Sales ~~from Southern California Gas Company.~~Program

9In the first quarter of 2010, we entered into an accounts receivable sales program to sell accounts receivable to a third party financial institution that qualifies for sale accounting under the updated accounting standards related to financial asset transfers. ~~Supplemental~~ Under ~~Cash~~this ~~Flow~~program, ~~Information~~we sell receivables in their entirety to a third party financial institution (through a wholly-owned special purpose entity). At December 31, 2010, the third-party financial institution held $42 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. During the year ended December 31, 2010, we sold approximately $528 million of accounts receivable to the third party financial institution, for which we received approximately $335 million of cash up front and had a deferred purchase price of approximately $193 million. We received approximately $180 million of cash related to the deferred purchase price when the underlying receivables were collected during 2010. As of December 31, 2010, we had not collected approximately $13 million of deferred purchase price related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets). We recognized a loss of less than $1 million on our accounts receivable sales for the year ended December 31, 2010. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales programs as operating cash flows on our statement of cash flows.

~~The~~Under ~~following~~the ~~table contains~~accounts ~~supplemental~~receivable ~~cash~~sales ~~flow~~program, ~~information~~we service the underlying receivables for ~~each~~a fee. The fair value of this servicing agreement as well as the ~~three~~fees ~~years~~earned were not material to our financial statements for the year ended December 31:, 2010.

	2009		2008		2007
	(In millions)
Interest paid, net of capitalized interest	$	88	$	88	$	106
Income tax payments		71		45		112

The third party financial institution involved in this accounts receivable sales program acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.

~~10. Transactions with Affiliates~~40

~~Cash~~Table ~~Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs~~ of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. During both 2009 and 2008, we utilized $200 million of our notes receivable from the cash management program to pay dividends to our parent. At December 31, 2009 and 2008, we had a note receivable from El Paso of approximately $1.0 billion. We classified $103 million of this receivable as current on our balance sheet at December 31, 2009, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on this variable rate note at December 31, 2009 and 2008 was 1.5% and 3.2%.Contents

~~Income Taxes~~11. ElTransactions ~~Paso~~with files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At December 31, 2009 and 2008, we had income taxes payable of $90 million and $79 million. The majority of these balances, as well as our deferred income taxes, will become payable to El Paso. See Note 1 for a discussion of our income tax policy.Affiliates

~~Other~~Cash ~~Affiliate~~Management ~~Balances~~Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At ~~both~~ December 31, ~~2009~~2010 and ~~2008~~2009, we had ~~contractual~~a ~~deposits~~note receivable from ~~our~~El ~~affiliates~~ Paso of approximately $0.8 ~~million~~billion ~~included~~and in$1.0 ~~other~~billion. ~~current~~At ~~liabilities~~December 31, 2010, we have classified this note receivable as noncurrent on our balance ~~sheets~~ sheet as we do not anticipate using it in the next twelve months considering our available cash sources and needs. The interest rate on this variable rate note at December 31, 2010 and 2009 was 1.5%. During 2010 and 2009, we utilized $75 million, net of a $50 million cash contribution from our parent, and $200 million of our note receivable from the cash management program to pay dividends to our parent.

Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At December 31, 2010 and 2009, we had income taxes payable of $24 million and $90 million. The majority of these balances, as well as our deferred income taxes, will become payable to El Paso. See Note 1 for a discussion of our income tax policy.

Other Affiliate Balances. At both December 31, 2010 and 2009, we had contractual deposits from our affiliates of $9 million and $8 million included in other current liabilities on our balance sheets.

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

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

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

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~~The~~12. ~~following~~Supplemental ~~table shows~~Selected ~~overall~~Quarterly ~~revenues~~Financial ~~and~~Information ~~charges from our affiliates for each of the three years ended December 31:~~(Unaudited)

11. Supplemental Selected Quarterly Financial Information (Unaudited)

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

	Quarters Ended
	March 31		June 30		September 30		December 31~~(1)~~		Total
	(In millions)
2010
Operating revenues	$	145	$	126	$	122	$	124	$	517
Operating income		72		49		43		40		204
Net income		32		19		15		17		83
2009
Operating revenues	$	157	$	144	$	145	$	147	$	593
Operating income		81		67		66		65		279
Net income		40		30		30		28		128
2008
Operating revenues	$	141	$	152	$	145	$	152	$	590
Operating income		60		74		61		62		257
Net income		33		40		31		31		135

____________

(1) Includes asset impairments of $14 million due to declining real estate values for 2008 related to our Arizona storage projects, which we are no longer developing.

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SCHEDULE II

EL PASO NATURAL GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008

(In millions)

Description	Balance at Beginning of Period		Charged to Costs and Expenses			Deductions			Balance at End of Period
2010
Allowance for doubtful accounts	$	2	$	—		$	—		$	2
Legal reserves		2		5			(3	)		4
Environmental reserves		19		(1	)		(2	)		16
Regulatory reserves(1)		74		21			(76	)		19
2009
Allowance for doubtful accounts	$	2	$	—		$	—		$	2
Legal reserves		6		4			(8	)		2
Environmental reserves		22		1			(4	)		19
Regulatory reserves		—		74	(1)		—			74
Regulatory reserves(1)		—		74			—			74
2008
Allowance for doubtful accounts	$	4	$	(2	)	$	—		$	2
Legal reserves		4		8			(6	)		6
Environmental reserves		25		1			(4	)		22
Regulatory reserves		10		—			(10	)		—
2007
Allowance for doubtful accounts	$	5	$	(1	)	$	—		$	4
Legal reserves		16		4			(16	)		4
Environmental reserves		24		6			(5	)		25
Regulatory reserves		65		60			(115	)		10

____________

(1) See ~~Note~~Financial 6Statements toand ~~the~~Supplementary ~~financial~~Data ~~statements~~Note 7 for EPNG’s rate case discussion.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, ~~2009~~ 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the ~~SEC~~U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and ~~Chief Financial Officer~~CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and ~~our~~CFO ~~Chief Financial Officer~~ concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a – 15(e) and 15d – 15(e)) were effective as of December 31, ~~2009~~2010. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of ~~2009~~2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM9A(T). CONTROLS AND PROCEDURES

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

ITEM 9B. OTHER INFORMATION

None.

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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, ~~2009~~2010 and ~~2008~~2009 of $~~796~~982,000 and $~~751~~796,000, respectively, were primarily for professional services rendered by Ernst & Young LLP and for the audits of the consolidated financial statements of El Paso Natural Gas Company and its subsidiaries as well as the review of documents filed with the SEC and related ~~consent~~consents.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, ~~2009~~2010 and ~~2008~~ 2009.

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 ~~2010~~2011 Annual Meeting of Stockholders.

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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
Report of Independent Registered Public Accounting Firm	2322
Consolidated Statements of Income	2423
Consolidated Balance Sheets	2524
Consolidated Statements of Cash Flows	2625
Consolidated Statements of Stockholder’s Equity	2726
Notes to Consolidated Financial Statements	2827
2. Financial statement schedules
Schedule II — Valuation and Qualifying Accounts	43

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.

The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•	may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•	may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

Undertaking

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

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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 ~~1st~~ 28th day of ~~March~~February ~~2010~~2011.

EL PASO NATURAL GAS COMPANY ~~Date~~ By: /s/ James J. Cleary James J. Cleary President

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

Signature	~~Title~~	~~Date~~Title	Date
/s/ James J. Cleary	~~President and Director~~	~~March~~President 1,and ~~2010~~Director	February 28, 2011
James J. Cleary	~~(Principal Executive Officer)~~	(Principal Executive Officer)
/s/ John R. Sult	~~Senior Vice President and~~	~~March~~Executive 1,Vice ~~2010~~President and Chief Financial Officer	February 28, 2011
John R. Sult	~~Chief Financial Officer (Principal Financial Officer)~~	(Principal Financial Officer)
/s/ Rosa P. Jackson	~~Vice President and Controller~~	~~March~~Vice 1,President ~~2010~~and Controller	February 28, 2011
Rosa P. Jackson	~~(Principal Accounting Officer)~~	(Principal Accounting Officer)
/s/ James C. Yardley	~~Chairman of the Board~~	~~March~~Chairman 1,of ~~2010~~the Board and Director	February 28, 2011
James C. Yardley
/s/ Daniel B. Martin	~~Senior Vice President and Director~~	~~March 1, 2010~~Director	February 28, 2011
Daniel B. Martin
/s/ Thomas L. Price	Vice President and Director	March 1, 2010
/s/ Robert L. Perez		Director	February 28, 2011
Thomas L. Price
Robert L. Perez

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EL PASO NATURAL GAS COMPANY

EXHIBIT INDEX

December 31, ~~2009~~2010

Each exhibit identified below is filed as 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 (incorporated by reference to Exhibit 3.A to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
3.B	By-laws dated June 2, 2008 (incorporated by reference to Exhibit 3.B to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
*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.
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 (incorporated by reference to Exhibit 4.A to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
*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.
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 (incorporated by reference to Exhibit 4.B to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
4.C	Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee (incorporated by reference to Exhibit 4.C to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
4.D	First Supplemental Indenture dated as of June 10, 2002 between El Paso Natural Gas Company and Wilmington Trust Company (as successor in interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee, to indenture dated November 13, 1996 (incorporated by reference to Exhibit 4.D to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
4.E	Second Supplemental Indenture dated as of April 4, 2007 between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee, to indenture dated November 13, 1996 (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
4.F	First Supplemental Indenture dated as of April 4, 2007 between El Paso Natural Gas Company and Wilmington Trust Company, as trustee, to indenture dated as of July 23, 2003 (incorporated by reference to Exhibit 4.C to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
4.G	Form of 5.95% Senior Note due 2017 (included in Exhibit 4.E).
10.A	Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.A to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
10.B	Third Amendment and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (incorporated by reference to Exhibit 4.A to our Annual Report for the year ended December 31, 2009, filed with the SEC on March 1, 2010).

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*10.A	Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent.
10.C	Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (incorporated by reference to Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007.)
*10.B	Third Amendment and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank.
10.C	Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007.)
10.D	Registration Rights Agreement, dated as of April 4, 2007, among El Paso Natural Gas Company and Deutsche Bank Securities Inc., Citigroup Global Markets Inc., ABN AMRO Incorporated, Goldman, Sachs & Co, Greenwich Capital Markets, Inc., J.P. Morgan Securities Inc. and SG Americas Securities, LLC (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
*12	Ratio of Earnings to Fixed Charges.
21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
*23	Consent of Independent Registered Public Accounting Firm Ernst & Young LLP.
*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.

(In millions)

Operation and maintenance expenses

Reimbursements of operating expenses