Edgar Filing: EL PASO NATURAL GAS CO

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

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

For the transition period from to

Commission File Number 1-2700

El Paso Natural Gas Company

(Exact Name of Registrant as Specified in Its Charter)


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

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

Telephone Number: (713) 420-2600

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

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

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

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 x

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 x 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 x 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. x

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):

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

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

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

Common Stock, par value $1 per share. Shares outstanding on February 23, 2012: 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		14
Item 2.	Properties		14
Item 3.	Legal Proceedings		14
Item 4.	Mine Safety Disclosures		14

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		14
Item 6.	Selected Financial Data		*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		20
Item 8.	Financial Statements and Supplementary Data		21
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		44
Item 9A.	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	LNG	= liquefied natural gas
BBtu	= billion British thermal units	MMcf	= million cubic feet
Bcf	= billion cubic feet	NGL	= natural gas liquids

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,” or “ours,” we are describing El Paso Natural Gas Company and/or our subsidiaries.

PART I

ITEM 1. BUSINESS

Overview and Strategy

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

On October 16, 2011, El Paso announced a definitive agreement with Kinder Morgan, Inc. (KMI) whereby KMI will acquire El Paso in a transaction that valued El Paso at approximately $38 billion (based on the KMI stock price at that date), including the assumption of debt. The transaction has been approved by each company’s board of directors but remains subject to the approvals of El Paso shareholders, the Federal Trade Commission (FTC) and other customary regulatory and other approvals. The approval of KMI shareholders will also be required, but a voting agreement has been executed by the majority of shareholders of KMI to support the transaction.

Our pipeline systems and our storage facility operate 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:

•

focusing on customer service;

•

developing growth projects in our market and supply areas;

•

maintaining the safety of our pipeline systems and other assets;

•

successfully recontracting expiring contracts for transportation capacity; and

•

focusing on increasing utilization, efficiency and cost control in our 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 2011, 2010 and 2009, average throughput was 3,109 BBtu/d, 3,356 BBtu/d and 3,937 BBtu/d. This system delivers natural gas from the San Juan, Permian, and Anadarko basins to markets in California, Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.

The Mojave Pipeline Company (Mojave) System. The Mojave system consists of approximately 500 miles of pipeline with an east to west flow design capacity of approximately 400 MMcf/d. During 2011, 2010 and 2009, average throughput was 377 BBtu/d, 421 BBtu/d and 379 BBtu/d. Mojave’s 2011, 2010 and 2009 throughput includes 354 BBtu/d, 382 BBtu/d and 334 BBtu/d of volumes transported on 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 (iii) the Kern River Gas Transmission Company system in California. This system also extends to customers in the vicinity of Bakersfield, California.

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

Markets and Competition

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 and various natural gas markets.

The natural gas industry has experienced a major shift from conventional supply sources to unconventional sources, such as shales. In addition, the increase in oil prices has led to increased production of natural gas found in association with the production of oil. This shift has impacted supply patterns, gas flows and 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. The Eagle Ford play in south Texas offers a growing supply source for EPNG. Due to the economic uplift from oil and NGL production in this trend, drilling activity is growing rapidly and expected to do so for the next five years.

Exports to Mexico are increasing and may increase further over time as demand growth exceeds production growth in that country. In addition to this trend in Mexico, imports of LNG to the U.S. have been declining over the last several years in response to increased U.S. shale gas production which has resulted in a decline in U.S. natural gas prices relative to gas prices in Europe and Asia. The projected gas price disparity between U.S. and European/Asian markets suggests that North America could change from a net importer of LNG to a net exporter of LNG before the end of this decade. These factors have led to increased demand for domestic U.S. supplies and related transportation services over the last several years, a trend which is likely to continue.

Electric power generation has been the source of most of the demand growth for natural gas over the last 10 years, and this trend is expected to continue. The growth of natural gas in this sector is influenced by competition with coal and economic growth. Short-term market shifts have been driven by relative electric generation costs of coal-fired plants versus gas-fired plants. A long-term market 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, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources. Industrial demand has also grown recently with the economic recovery and low natural gas price environment, and this sector offers an opportunity for continued growth. In addition, a potential new and significant demand market for North American natural gas production is for LNG exports to Europe and Asia. Several Gulf Coast projects have received approval from the U.S. Department of Energy to export LNG to global markets beginning in the second half of this decade.

The EPNG system faces competition in the west and southwest from other existing pipelines, from California storage facilities, and from alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. We also face competition from gas imported into California from Canada and from an LNG facility located in northern Mexico.

The Mojave system faces competition from other existing 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 an LNG facility located in northern Mexico.

For a further discussion of factors impacting our markets and competition, see Item 1A. Risk Factors.

Customers and Contracts

We provide natural gas services to a variety of customers, including natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing and trading companies. California and Arizona customers account for the majority of transportation on the EPNG system, followed by Texas and New Mexico. 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. The Mojave system is largely contracted to EPNG which utilizes the capacity to provide service to EPNG’s customers.

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.

The following table details our customer and contract information for each of our pipeline systems as of December 31, 2011. 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 natural gas they transport, store, inject or withdraw. For a further discussion of factors impacting our contracts, see Item 1A. Risk Factors.


Pipeline System	Customer Information	Contract Information
EPNG	Approximately 130 firm and interruptible customers.	Approximately 180 firm transportation contracts. Weighted average remaining contract term of approximately three years.

Major Customers:
ConocoPhillips Company
(492 BBtu/d)		Expire in 2012.

MGI Supply, Ltd
(350 BBtu/d)		Expires in 2012.

Southern California Gas Company
(306 BBtu/d)		Expires in 2012.
(207 BBtd/d)		Expire in 2013-2014.

Southwest Gas Corporation
(240 BBtu/d)		Expire in 2013-2018.

Mojave	Five firm and interruptible customers.	Three firm transportation contracts. Weighted average remaining contract term of approximately four years.

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

Regulatory Environment

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

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rates and charges for natural gas transportation and storage;

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certification and construction of new facilities;

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extension or abandonment of services and facilities;

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maintenance of accounts and records;

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relationships between pipelines and certain affiliates;

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terms and conditions of service;

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depreciation and amortization policies;

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acquisition and disposition of facilities; and

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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. For a further discussion of the potential impact of regulatory matters on us, see Item 1A. Risk Factors.

Environmental

A description of our environmental remediation activities is included in Part II, Item 8. Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.

Employees

As of February 20, 2012, we had approximately 525 full-time employees, none of whom are subject to a collective bargaining arrangement.

ITEM 1A. RISK FACTORS

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from 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.

Risks Related to Our Business

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

The results of our business are impacted in the long term by the volumes of natural gas we transport or store and the prices we are able to charge for these services. The volumes we transport and store depend on the actions of third parties that are based on factors beyond our control. Such factors include events that negatively impact our customers’ demand for natural gas and could expose our pipelines to the risk that we will not be able to renew contracts at expiration or that we will be required to discount our rates significantly upon renewal. We are also highly dependent on our customers and downstream pipelines to attach new and increased loads on their systems in order to grow our business. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.

The volume of natural gas that we transport and store also depends on the availability of natural gas supplies that are accessible 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, especially with regard to the development of new natural gas shale plays 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, our ability to deliver natural gas to our shippers is dependent upon their ability to purchase and deliver natural gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the natural gas delivered by our shippers at the receipt points into our systems is less than the natural gas that they take at delivery points from our systems. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand.

With the recent rapid growth of shale production in the U.S. and the subsequent drop in natural gas prices, the need and incentive to import LNG to U.S. regasification terminals have greatly diminished. Actual U.S. LNG imports are now at their lowest levels in several years. If shale gas production continues to grow as expected, imports of LNG to the U.S. will remain at minimal levels.

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

Our business is extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior, the U.S. Department of Homeland Security and various state and local regulatory agencies who have the ability to issue regulations

or enforcement orders that may 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. There is a risk that after a prescribed regulatory process 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. For a discussion of our rate cases filed with the FERC, see Part II, Item 8. Financial Statements and Supplementary Data, Note 7.

Our existing rates may also be challenged by complaint. The FERC commenced several proceedings against pipeline systems and storage facilities to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on us and that a successful complaint against our rates could have an adverse impact on us.

Certain of our transportation services are subject to negotiated rate contracts that may not allow us to recover our costs of providing the services.

Under 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 adjustment for increased costs which could occur due to inflation, increases in the cost 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 revenues are generated under contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or are terminated or if we are unable to 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 remain low over time and thereby negatively impact our ability to renew contracts at rates that were previously in place. In addition, basis differentials often remain low during periods in which the price for natural gas is low, such as we are currently experiencing. In 2012, contracts representing approximately 40 percent of our reservation revenues will expire. At this time we are uncertain how much of the expiring capacity will be recontracted, and if so, at what rates. Our ability to extend and replace contracts could be adversely affected by factors we cannot control, as discussed above. In addition, changes in state regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.

We may not succeed in an expansion of our pipeline systems.

Our ability to engage in expansion projects will be subject to, among other things, approval of our board of directors and numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Therefore, we cannot assure you that any additional expansion projects will be undertaken or, if undertaken, will be successful.

The success of expansion projects may depend on, among others, the following factors:

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other existing pipelines may provide transportation services to the area to which we are expanding;

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other entities, upon obtaining the proper regulatory approvals, may construct new competing pipelines or increase the capacity of existing competing pipelines;

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a competitor’s new or upgraded pipeline could offer transportation services that are more desirable to shippers because of costs, location, facilities or other factors;

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shippers may be unwilling to sign long-term firm transportation contracts for service which would make use of a planned expansion;

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we may be unable to obtain the requisite environmental and regulatory permits and approvals; and

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the FERC may not grant us the required certificates for our expansion projects.

We may also require additional capital to fund any expansion project. If we fail to generate sufficient funds in the future, we may have to delay or abandon potential expansion projects which could require us to write off significant development costs. Moreover, if we are unable to obtain long term firm transportation contracts for volumes that would enable us to cover the costs of any such expansion and provide us with an acceptable rate of return, we may not proceed with such expansion. Also, a potential expansion may cost more than planned to complete and such excess cost may not be recoverable. Our inability to recover any such costs or expenditures could materially adversely affect our business, financial condition, cash flows and results of operations.

We depend on certain key customers for a significant portion of our revenues and the loss of any of these key customers could result in a decline in our revenues.

We rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2011, ConocoPhillips Company, Southern California Gas Company and Southwest Gas Corporation accounted for approximately 16 percent, 12 percent and 11 percent, respectively of our operating revenues. The creditworthiness of our customers may be adversely impacted by negative effects in the economy, including low natural gas prices which can reduce liquidity and cash flows for some of our customers that produce natural gas. The loss of any material portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on us. For additional information on our revenues from these customers, see Part II, Item 8. Financial Statements and Supplementary Data, Note 9.

The costs to maintain, repair and replace our pipeline systems may exceed our expected levels.

Much of our pipeline infrastructure was originally constructed many years ago. The age of these assets may result in them being more costly to maintain and 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 due to third party excavation near our pipelines, unexpected degradation of our pipelines, erosion of soil, as well as design, construction or manufacturing defects) that could result in 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 a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and 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 or other regulatory actions associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future. We are also subject to inherent risk associated with our storage operations, including potential risk of gas losses and field degradation.

We do not own all of the land on which our pipelines and other related facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and other related facilities are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way 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 our operations. Any loss of or interference with these rights could have a material adverse effect on us.

There are accounting principles that are unique to regulated interstate pipeline assets that could materially impact our recorded earnings.

Accounting policies for FERC regulated pipelines are in certain instances different from U.S. generally accepted accounting principles (GAAP) for nonregulated entities. For example, we are permitted to record certain regulatory assets on our balance sheet that would not typically be recorded under GAAP for nonregulated entities. In determining whether to account for regulatory assets on our pipelines, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these 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 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 project is placed into service. We periodically evaluate the applicability of accounting standards

related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to evaluate our assets for impairment and write off the associated regulatory assets, which could impact our future earnings.

The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.

Our success depends 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 short-term by reductions in the supply or demand for natural gas since we recover most of our revenues from reservation charges under longer-term contracts that are not dependent on the supply and demand of natural gas in the short-term. However, our business can be negatively impacted by sustained downturns in supply and demand for natural gas. One of the major factors that will impact natural gas demand will be the potential growth of natural gas in the power generation market, particularly driven by the speed and level of which coal-fired power generation is replaced with natural gas-fired power generation. One of the major factors that have been impacting natural gas supplies has been the significant growth in unconventional sources, such as from shale plays. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:

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adverse changes in global economic conditions, including changes that negatively impact general demand for power generation and industrial loads for natural gas;

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adverse changes in geopolitical factors and unexpected wars, terrorist activities and others acts of aggression;

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adverse changes in domestic regulations that could impact the supply or demand for natural gas;

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technological advancements that may drive further increases in production from natural gas shales;

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competition from imported LNG, alternate fuels and renewable energy sources;

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increased prices of natural gas that could negatively impact demand;

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increased costs to transport natural gas;

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adoption of various energy efficiency and conservation measures; and

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perceptions of customers on the availability and price volatility of natural gas prices over the longer-term.

The price for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.

Natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices, which are at relatively low levels at this time, could remain depressed for sustained periods. The degree to which our business is impacted by lower commodity prices varies. For example, we are not significantly impacted in the short-term by changes 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 differentials between receipt and delivery points on our system and 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:

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changes in regional and domestic supply and demand;

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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 as other alternatives;

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changes in the costs of transporting natural gas;

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

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

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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 for the transportation and storage of natural gas, as well as with suppliers of alternative energy sources used to generate electricity, such as 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. In addition, our EPNG system experienced a loss of demand when an LNG terminal was completed south of the Mexico—California border.

Our operations are subject to operational hazards and uninsured risks which could negatively affect us.

Our operations are subject to a number of inherent operational hazards and uninsured risks such as:

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Adverse weather conditions, natural disasters, and/or other climate related matters—including extreme cold or heat, lightning and flooding, fires, earthquakes, tornadoes and other natural disasters. 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 greenhouse gas (GHG) could also have a negative impact upon our operations in the future.

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Acts of aggression on critical energy infrastructure—including terrorist activity or “cyber security” events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate or control our pipeline assets, our operations could be disrupted, property could be damaged and/or customer information could be stolen resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our operations to our financial applications, to our customers and to regulatory entities.

•

Other hazards—including the collision of third party equipment with our infrastructure (such as damage caused to our underground pipelines by third party excavation); explosions, pipeline failures, mechanical and process safety failures, events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards.

Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy and/or technology infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, from time to time we may not carry, or may be unable to obtain on terms that we find acceptable, insurance coverage for certain exposures including, but not limited to, certain environmental exposures (including potential environmental fines and penalties), business interruption and named windstorm 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 or that amounts for which we are insured, or that the proceeds of such insurance will not compensate us fully for our losses. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.

We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.

Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to the laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the FTC and the FERC to impose penalties for violations of laws or regulations has generally increased over the last few years. In addition, our business is subject to laws and regulations that 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 significant costs to install and maintain pollution controls, and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals (including renewals thereof) can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands, which are regulated by the U.S. Department of the Interior, particularly by the Bureau of Land Management. 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 laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operations or otherwise negatively impact us.

The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws and regulations may be enacted or existing laws and regulations may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to adopt or amend federal, state, local and tribal laws and regulations that could negatively impact our business, which includes among others:

•

Climate Change and other Emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have adopted regulations to regulate GHG emissions. It is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted; how the requirements of these regulations are implemented; 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 existing 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 and final rules at the federal and state levels to address air emissions from power plants and industrial boilers. Although such rules and proposals will generally favor the use of natural gas over other fossil fuels such as coal, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been various other 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 implemented more stringent emission standards with regard to certain natural gas operations that will affect our business. It is uncertain what impact new environmental regulations might have on us until further definition is provided by the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase air emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner. 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 federal and state levels and legislation enacted in certain states to provide 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.

•

Pipeline Safety. New federal legislation was enacted in December 2011 associated with pipeline safety and integrity issues, including changes that require installation of additional valves and other equipment on our pipelines and potential expansion of high consequence areas. The legislation requires the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration to conduct various studies, which may ultimately result in additional regulations that could negatively affect our operations.

We are exposed to the credit risk of our counterparties and our credit 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 current largest exposures are associated with shippers under long-term transportation contracts on our pipeline systems. Our credit procedures and policies may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we 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 are exposed to the credit and performance risk of our key contractors and suppliers.

As an owner of energy infrastructure facilities with significant capital expenditures, we rely on contractors for certain construction and we rely 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 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 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 employees 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 have certain contingent liabilities that could exceed our estimates.

We have certain contingent liabilities associated with litigation, regulatory and environmental matters and although we believe that we have established appropriate reserves for these matters, we could be required to accrue additional amounts in the future and these amounts could be material (see Part II, Item 8. Financial Statements and Supplementary Data, Note 7).

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 are subject to interest rate risks.

Although 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 future financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future.

Risks Related to Our Affiliation with El Paso

El Paso files reports 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.

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. There is a risk that El Paso’s or our credit ratings may be adversely affected in the future as the credit rating agencies continue to review our and El Paso’s leverage, liquidity, credit profile and potential transactions. Following the announcement of El Paso’s proposed merger with KMI, Moody’s and Fitch adjusted their view of El Paso to a negative outlook, and Moody’s adjusted their view of us to a negative outlook. 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.

Below are the ratings assigned to our and El Paso’s senior unsecured indebtedness at December 31, 2011:


	Rating Agency
	Moody’s Investor Service	Standard & Poor’s	Fitch Ratings
	Credit Rating
EPNG	Baa3⁽¹⁾	BB⁽²⁾	BBB-⁽¹⁾
El Paso	Ba3⁽²⁾	BB-⁽²⁾	BB+⁽²⁾

(1)	Investment grade^.

(2)	Non-Investment grade^.

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 any 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 our affiliated transactions, see Part II, Item 8. Financial Statements and Supplementary Data, Note 11.

A default under El Paso’s $1.25 billion revolving 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 $1.25 billion revolving credit agreement. We are only liable, however for our borrowings under the credit agreement, which were zero at December 31, 2011. 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 $1.25 billion revolving 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 and, in turn, adversely affect our liquidity position and, in turn, our financial condition. For additional information concerning El Paso’s credit facility and our long-term debt, see Part II, Item 8. Financial Statements and Supplementary Data, Note 6.

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 $1.25 billion credit agreement, our common stock and the member interest 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.

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 7, and is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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 as approved by our Board of Directors. During 2011, 2010 and 2009, we paid dividends to our parent of $103 million, $75 million, net of a $50 million cash contribution from our parent, and $200 million.

ITEM 6. SELECTED FINANCIAL DATA

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

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

Overview

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. We have included a discussion in this MD&A of our business, results of operations, liquidity and capital resources and a discussion of factors that may impact us as we operate in the future.

On October 16, 2011, El Paso announced a definitive agreement with KMI whereby KMI will acquire El Paso in a transaction that valued El Paso at approximately $38 billion (based on the KMI stock price at that date), including the assumption of debt. The transaction has been approved by each company’s board of directors but remains subject to the approvals of El Paso shareholders, the FTC and other customary regulatory and other approvals. The approval of KMI shareholders will also be required, but a voting agreement has been executed by the majority of the shareholders of KMI to support the transaction.

Our Business

Our primary business consists of the interstate transportation and storage of natural gas. We face 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 2011 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.	91

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.	9

The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. 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. In addition, 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 tariffs 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.

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

Our existing contracts mature at various times and in varying amounts of throughput capacity. We attempt to sell all of our capacity under long term contracts and market any remaining open positions under shorter term contracts as market demand permits. Currently, we face recontracting risk in our market areas. In 2012, a significant amount of contracted capacity will expire on our EPNG system. Certain customers who hold capacity on the EPNG system under contract terms of one year also hold renewal rights, and often renew their contracts on a year to year basis. We are currently remarketing the expiring capacity on our EPNG system to serve either its existing customers or to serve new customers. At this time, we are uncertain how much of the expiring capacity will be recontracted, and if so, at what rates. The weighted average remaining contract term for our active contracts is approximately three years as of December 31, 2011. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2011, including those with terms beginning in 2012 or later.


	Contracted Capacity		Percent of Contracted Capacity		Reservation Revenue		Percent of Reservation Revenue
	(BBtu/d)⁽¹⁾				(In millions)
2012		1,743		45	$	164		40
2013		673		17		72		18
2014		370		10		23		5
2015		335		9		64		16
2016		137		3		12		3
2017 and beyond		643		16		73		18

Total		3,901		100	$	408		100

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

Results of Operations

Our management uses segment earnings before interest expense and income taxes (Segment EBIT) as a measure to assess the operating results and effectiveness of our business. We believe Segment EBIT is useful to investors to provide them with the same measure used by our management to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. Segment EBIT is defined as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. Segment EBIT may not be comparable to measures used by other companies. Additionally, Segment 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 Segment EBIT to net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, 2011 compared with 2010.

Operating Results:


	2011			2010
	(In millions,
	except for volumes)
Operating revenues	$	509		$	517
Operating expenses		(329	)		(313	)

Operating income		180			204
Other income, net		2			3

Segment EBIT		182			207
Interest and debt expense		(88	)		(92	)
Affiliated interest income, net		17			15
Income tax expense		(42	)		(47	)

Net income	$	69		$	83

Throughput volumes (BBtu/d)⁽¹⁾		3,132			3,395

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

Segment EBIT Analysis:

		000000			000000			000000			000000
	Variance
	Operating Revenue			Operating Expense			Other			Total
	Favorable/(Unfavorable)
	(In millions)
Reservation and usage revenues	$	(7	)	$	—		$	—		$	(7	)
Operating and general and administrative expenses		—			(13	)		—			(13	)
Other ⁽¹⁾		(1	)		(3	)		(1	)		(5	)

Total impact on Segment EBIT	$	(8	)	$	(16	)	$	(1	)	$	(25	)

⁽¹⁾	Consists of individually insignificant items.

Reservation and Usage Revenues. For the year ended December 31, 2011, our reservation and usage revenues were $7 million lower as compared to 2010. The decline was driven by reduced demand due to high natural gas storage levels and increased hydroelectric generation in our California market, nonrenewal of certain expiring contracts, the sale of open capacity at lower prices due to lower basis differentials and lower revenues related to certain interruptible services, partially offset by higher rates effective April 1, 2011.

During 2011 our throughput decreased by 8 percent when compared to 2010. Declines in throughput can affect our short-term results or be an indication of the risks we may face when seeking to recontract or renew any of our existing firm transportation contracts. Continuing negative economic impacts on demand, as well as adverse shifting sources of 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 transportation rates in order to renew certain firm transportation contracts should these conditions continue.

Operating and General and Administrative Expenses. For the year ended December 31, 2011, our operating and general and administrative expenses were higher than in 2010 by approximately $13 million primarily due to higher payroll, benefits and contractor costs.

Regulatory Matters

EPNG Rate Cases. We periodically file for changes in our rates, which are subject to approval by the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability.

•

2010 Rate Case. In September 2010, we filed a new rate case with the FERC proposing an increase in base tariff rates which would increase revenues by approximately $100 million annually over previously effective tariff rates. 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. A hearing commenced in late October 2011 and concluded in December 2011. A decision is due in May 2012. It is uncertain whether such an increase will be achieved in the context of any settlement between us and our customers or following the outcome of the hearing in the rate case. Although the final outcome is not currently determinable, we believe our accruals established for this matter are adequate.

•

2008 Rate Case. In April 2010, the FERC approved an 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 rate proceeding. In January 2011, the Presiding Administrative Law Judge issued a decision that for the most part found against us on the four issues. We have appealed those decisions to the FERC and may 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.

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.

Other Regulatory Matters. In October 2010, we filed with the FERC to permanently abandon two compressor stations and temporarily idle nine 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 was to bring the idled facilities back into service over the next several years as market demand improves. In our 2010 rate case, we did not initially 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. In April 2011, the FERC denied our request to temporarily idle the nine compressor stations. We have appealed the FERC’s decision and the outcome is uncertain. In September 2011, the FERC issued an order approving the abandonment of the two compressor stations, which we abandoned in December 2011.

In January 2012, we filed with the FERC to permanently abandon two additional compressor stations and four compressor units on our north mainline and San Juan triangle. We requested an order by December 31, 2012.

Interest and Debt Expense

Our interest and debt expense decreased for the year ended December 31, 2011 compared to 2010 primarily due to the repayment of $54 million of our 7.625% notes that matured in August 2010.

Affiliated Interest Income, Net

The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:


	2011			2010
	(In millions, except for rates)
Average advance due from El Paso	$	889		$	1,002
Average short-term interest rate		2.0	%		1.5	%

Income Taxes

Our effective tax rates of 38 percent and 36 percent for the years ended December 31, 2011 and 2010 were higher than the statutory rate of 35 percent primarily due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8. Financial Statements and Supplementary Data, Note 2.

Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program while our primary uses of cash are for working capital and capital expenditures. At December 31, 2011, we had a note receivable from El Paso of $873 million. We do not intend to settle any amounts owed under this note within the next twelve months and therefore, classified it as non-current on our balance sheet. We periodically evaluate our operating cash flows, after consideration of our capital and other requirements, to determine potential discretionary dividends to our parent. Based on our evaluation, during 2011, we paid a dividend to our parent of $103 million.

For the year ended December 31, 2011 compared with 2010, our operating cash flows increased by $170 million primarily due to payments of rate refunds and income taxes during 2010.

Our cash capital expenditures for the year ended December 31, 2011 are listed below.


	(In millions)
Maintenance	$	87
Expansion		1

Total	$	88

Although financial market conditions have improved, continued volatility 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 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. In addition, we are eligible to borrow amounts available under El Paso’s $1.25 billion revolving credit agreement and are only liable for amounts we directly borrow. During the first half of 2011, El Paso refinanced this credit facility and its collateral restrictions under the facility were modified providing El Paso’s master limited partnership the ability to acquire up to 100 percent ownership interests in us or another El Paso subsidiary, or some combination thereof. This credit facility provides for an elimination of collateral support upon El Paso achieving investment grade status by one of the rating agencies. Additionally, our cost to borrow under the El Paso credit facility has increased to LIBOR plus 2.25 percent. As of December 31, 2011, El Paso had approximately $620 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. For a further discussion of the credit facility, see Item 8. Financial Statements and Supplementary Data, Note 6. While we do not anticipate a need to directly access the financial markets in 2012 for any of our operating activities or capital needs based on liquidity available to us, market conditions may impact our or El Paso’s ability to act opportunistically. Our future plans could also be impacted by the completion of El Paso’s announced acquisition by KMI.

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.

Commitments and Contingencies

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, 2011, we had an interest bearing note receivable from El Paso of approximately $873 million, with a variable interest rate of 2.5% 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 rate on our non-affiliated fixed rate long-term debt securities and the estimated fair value of these securities which is based on quoted market prices for the same or similar issues.


	December 31, 2011									December 31, 2010
	Expected Fiscal Year of Maturity of Carrying Amounts
	2012-2016		Thereafter			Total		Fair Value		Carrying Amount		Fair Value
	(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate	$	—	$	1,113		$	1,113	$	1,348	$	1,113	$	1,258
Average effective interest rate				7.5	%

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by 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 to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

•

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

•

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

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011. 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, 2011.

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, 2011 and 2010, and the related consolidated statements of income and comprehensive income, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, 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.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2012

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In millions)


	Year Ended December 31,
	2011			2010			2009
Operating revenues	$	509		$	517		$	593

Operating expenses
Operation and maintenance		206			193			202
Depreciation and amortization		92			88			83
Taxes, other than income taxes		31			32			29

		329			313			314

Operating income		180			204			279
Other income, net		2			3			2
Interest and debt expense		(88	)		(92	)		(93	)
Affiliated interest income, net		17			15			19

Income before income taxes		111			130			207
Income tax expense		42			47			79

Net income		69			83			128
Other comprehensive income
Unrealized actuarial gains on postretirement benefit obligations (net of income taxes of $3 in 2011)		3			—			—

Comprehensive income	$	72		$	83		$	128

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except for share amounts)


	December 31,
	2011		2010
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts and note receivable
Customer, net of allowance of $2 in 2010		3		4
Affiliates		3		6
Other		24		20
Materials and supplies		48		48
Deferred income taxes		12		9
Prepaids		16		15
Regulatory assets		8		7
Other		—		4

Total current assets		114		113

Property, plant and equipment, at cost		3,993		3,970
Less accumulated depreciation and amortization		1,525		1,484

Total property, plant and equipment, net		2,468		2,486

Other long-term assets
Note receivable from affiliate		873		836
Other		101		110

		974		946

Total assets	$	3,556	$	3,545

LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	68	$	82
Affiliates		20		25
Other		9		11
Taxes payable		35		28
Accrued interest		19		18
Accrued liabilities		29		24
Regulatory liabilities		16		7
Contractual deposits		21		15
Other		6		5

Total current liabilities		223		215

Long-term debt		1,113		1,113

Other long-term liabilities
Deferred income taxes		439		408
Other		78		75

		517		483

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		432		466
Accumulated other comprehensive income		3		—

Total stockholder’s equity		1,703		1,734

Total liabilities and stockholder’s equity	$	3,556	$	3,545

See accompanying notes.

EL PASO NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities
Net income	$	69		$	83		$	128
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		92			88			83
Deferred income tax expense (benefit)		21			26			(3	)
Other non-cash income items		13			22			(6	)
Asset and liability changes
Accounts receivable		9			50			10
Change in deferred purchase price from accounts receivable sales		(8	)		(13	)		—
Accounts payable		(20	)		(21	)		55
Income taxes payable		(3	)		(66	)		12
Other asset changes		14			(20	)		(59	)
Other liability changes		34			(98	)		88

Net cash provided by operating activities		221			51			308

Cash flows from investing activities
Capital expenditures		(88	)		(80	)		(116	)
Net change in note receivable from affiliate		(37	)		152			(3	)
Proceeds from sale of assets		—			4			14
Other		7			2			(3	)

Net cash provided by (used in) investing activities		(118	)		78			(108	)

Cash flows from financing activities
Payments to retire long-term debt		—			(54	)		—
Dividends paid to parent, net of contribution		(103	)		(75	)		(200	)

Net cash used in financing activities		(103	)		(129	)		(200	)

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	$	83		$	87		$	88
Income tax payments		23			87			71

See accompanying notes.

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 Stockholder’s
	Shares		Amount		Capital		Earnings			Income		Equity
January 1, 2009		1,000	$	—	$	1,268	$	530		$	—	$	1,798
Net income								128					128
Dividend paid to parent								(200	)				(200	)

December 31, 2009		1,000		—		1,268		458			—		1,726
Net income								83					83
Dividend paid to parent, net of contribution								(75	)				(75	)

December 31, 2010		1,000		—		1,268		466			—		1,734
Net income								69					69
Dividend paid to parent								(103	)				(103	)
Other comprehensive income											3		3

December 31, 2011		1,000	$	—	$	1,268	$	432		$	3	$	1,703

See accompanying notes.

EL PASO NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

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. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income, stockholder’s equity or cash flows from operating activities.

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity 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) and follow the Financial Accounting Standards Board’s accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded 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 may record a regulatory asset or liability include certain postretirement employee benefit plan costs, loss on reacquired debt, taxes related to an equity return component on regulated capital projects and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates. For further details of our regulatory assets and liabilities, see Note 4.

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.

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.

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 depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we file with the FERC for 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 50 percent. The depreciation rates on our Mojave Pipeline Company (Mojave) system range from two percent to 33 percent per year.

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 determined 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, which represent the excess purchase costs associated with purchase business combinations allocated to us. These costs are amortized on a straight-line basis and are not recoverable in our rates under current FERC policies.

Also included in our property balances are base gas and working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we recognize a loss in our income statement or defer the loss as a regulatory asset on our balance sheet if deemed probable of recovery through future rates charged to our customers.

We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the 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 the average cost of debt. Interest costs capitalized are included as a reduction to interest and 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.

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. 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 assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows.

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. 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 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 indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Income Taxes

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

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.

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 and estimable. 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 under the plan. These contributions are invested until the benefits are paid to plan participants. The net benefit cost of this plan is recorded in our income statement and 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.

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 in accumulated other comprehensive income, a component of stockholder’s equity, until those gains and losses are recognized in the income statement. For a further discussion of our policy with respect to our postretirement benefit plan, see Note 8.

2. Income Taxes

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:


	2011		2010		2009
	(In millions)
Current
Federal	$	19	$	19	$	72
State		2		2		10

		21		21		82


Deferred
Federal		19		26		(3	)
State		2		—		—

		21		26		(3	)

Total income tax expense	$	42	$	47	$	79

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:


	2011			2010			2009
	(In millions, except for rates)
Income tax expense at the statutory federal rate of 35%	$	39		$	46		$	72
State income taxes, net of federal income tax effect		3			1			7

Income tax expense	$	42		$	47		$	79

Effective tax rate		38	%		36	%		38	%

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


	2011		2010
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	512	$	483
Regulatory and other assets		34		29

Total deferred tax liability		546		512

Deferred tax assets
U.S. net operating loss and tax credit carryovers		77		77
Regulatory and other liabilities		42		36

Total deferred tax asset		119		113

Net deferred tax liability	$	427	$	399

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, 2011, 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 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 Internal Revenue Service 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 2001 and U.S. income tax examinations for years prior to 2007. For our open tax years, we have no unrecognized tax benefits.

3. Financial Instruments

At December 31, 2011 and 2010, the carrying amounts of cash and cash equivalents and trade receivables and payables represent fair value because of the short-term nature of these instruments. At December 31, 2011 and 2010, we had an interest bearing note receivable from El Paso of approximately $873 million and $836 million due upon demand, with a variable interest rate of 2.5% and 1.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates 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 primarily based on quoted market prices for the same or similar issues (Level 2 fair value measurement), are as follows at December 31:


	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt	$	1,113	$	1,348	$	1,113	$	1,258

4. Regulatory Assets and Liabilities

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:

		$0000.0		$0000.0
	2011		2010
	(In millions)
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	6	$	5
Other		2		2

Total current regulatory assets		8		7

Non-current regulatory assets
Taxes on capitalized funds used during construction		21		22
Unamortized loss on reacquired debt		18		21
Postretirement benefits		8		6
Other		9		9

Total non-current regulatory assets⁽¹⁾		56		58

Total regulatory assets	$	64	$	65


Current regulatory liabilities
Property and plant depreciation	$	1	$	1
Difference between gas retained and gas consumed in operations		12		5
Other		3		1

Total current regulatory liabilities		16		7

Non-current regulatory liabilities
Property and plant depreciation		25		24
Postretirement benefits		8		17
Other		2		2

Total non-current regulatory liabilities⁽¹⁾		35		43

Total regulatory liabilities	$	51	$	50

(1)	Included in other long-term assets and liabilities on our balance sheets.

The significant regulatory assets and liabilities include:

Difference Between Gas Retained and Gas Consumed in Operations. These amounts reflect the value of the volumetric difference between the gas retained and 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 returned to our customers in subsequent fuel filing periods.

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

Unamortized Loss on Reacquired Debt. Amount represents the deferred and unamortized portion of losses on reacquired debt which are recovered through the cost of service over the life of the new debt issue.

Postretirement Benefits. Represents differences in postretirement benefit costs expensed and the amounts previously recovered in rates. Prior to our 2011 rate case settlement, these balances also included unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan. As part of our rate case settlement, we no longer include these costs in our rates and during the third quarter of 2011, we reclassified $6 million (net of income taxes of $4 million) to accumulated other comprehensive income.

Property and Plant Depreciation. Represents the deferral of customer-funded amounts for costs of future asset retirements and costs previously collected in our rates for the depreciation of certain assets in excess of normal depreciation rates.

5. Property, Plant 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, 2011 and 2010, additional acquisition cost assigned to utility plant was approximately $151 million and accumulated depreciation was approximately $101 million and $99 million. These additional acquisition costs are being amortized on a straight-line basis over a remaining life of 21 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, 2011, 2010 and 2009.

Capitalized Costs During Construction. Interest costs capitalized are included as a reduction to interest and debt expense on our income statements and were less than $1 million during the years ended December 31, 2011, 2010 and 2009. Equity amounts capitalized are included in other income on our income statements and were $1 million (exclusive of taxes) during each of the years ended December 31, 2011, 2010 and 2009.

Construction Work-In-Progress. At December 31, 2011 and 2010, we had $36 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, sealing and possibly removing the facilities if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or 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 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, 2011 and 2010 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:


	2011		2010
	(In millions)
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

		1,115		1,115
Less: Unamortized discount		2		2

Total long-term debt	$	1,113	$	1,113

Credit Facility. We are eligible to borrow amounts available under El Paso’s $1.25 billion revolving credit agreement and are only liable for amounts we directly borrow. During the first half of 2011, El Paso refinanced this credit facility and its collateral restrictions were modified providing El Paso’s master limited partnership the ability to acquire up to 100 percent ownership interests in us or another El Paso subsidiary, or some combination thereof. This credit facility provides for an elimination of collateral support upon El Paso achieving investment grade status by one of the rating agencies. Additionally, our current cost to borrow under the El Paso credit facility has increased to LIBOR plus 2.25 percent. As of December 31, 2011, El Paso had approximately $620 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. Our common stock and the member interest of another El Paso subsidiary are pledged as collateral under the credit agreement.

Under El Paso’s $1.25 billion revolving 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, 2011, we were in compliance with our debt-related covenants.

7. Commitments and Contingencies

Legal Proceedings

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 have only alleged an amount of damages against our co-defendant, Burlington. We believe that our actions in the 1980s were proper in light of a 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, which Burlington denies. The Plaintiffs assert that royalties were further underpaid by Burlington as a result of post-production cost deductions taken starting in the late 1990s. We have no liability for the post-production claims as they pertain to periods after our separation from Burlington. This action was transferred to Washita County District Court in 2004. A tentative settlement reached in November 2005 was rejected 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 and stayed the claims pertaining to New Mexico wells. The class certification was upheld by the Oklahoma Court of Appeals, and a petition for review was denied by the Oklahoma Supreme Court. The Plaintiffs have proceeded with discovery of the post-production claims against Burlington. Our costs and legal exposure related to this lawsuit are not currently determinable.

State of Texas v. EPNG. On behalf of the Texas Commission on Environmental Quality, the State of Texas has filed a lawsuit against us related to allegedly unauthorized emissions of air contaminants associated with the rupture of one of our pipelines in the vicinity of Bushland, Texas in 2009. The parties have reached an agreement in principle to settle this matter which will not have a material adverse effect on our financial condition.

In addition to the above proceedings, we and our affiliates are named defendants in numerous legal proceedings and claims 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, 2011, we had less than $1 million accrued for our outstanding legal proceedings.

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, 2011 and 2010, our accrual was approximately $14 million and $16 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 $24 million at December 31, 2011. Our accrual at December 31, 2011 includes $13 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 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.

Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for three active sites. 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. We consider the financial strength of other PRPs in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

For 2012, we estimate that our total remediation expenditures will be approximately $3 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $2 million in the aggregate for 2012 through 2016, 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.

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

Rates and Regulatory Matters

EPNG Rate Cases. In April 2010, the FERC approved an 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 rate proceeding. In January 2011, the Presiding Administrative Law Judge issued a decision that for the most part found against us on the four issues. We have appealed those decisions to the FERC and may 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.

In September 2010, we filed a new rate case with the FERC proposing an increase in base tariff rates which would increase revenues by approximately $100 million annually over previously effective tariff rates. 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. A hearing commenced in late October 2011 and concluded in December 2011. A decision is due in May 2012. It is uncertain whether such an increase will be achieved in the context of any settlement between us and our customers or following the outcome of the hearing in the rate case. Although the final outcome is not currently determinable, we believe our accruals established for this matter are adequate.

Other Regulatory Matters. In October 2010, we filed with the FERC to permanently abandon two compressor stations and temporarily idle nine 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 was to bring the idled facilities back into service over the next several years as market demand improves. In our 2010 rate case, we did not initially 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. In April 2011, the FERC denied our request to temporarily idle the nine compressor stations. We have appealed the FERC’s decision and the outcome is uncertain. In September 2011, the FERC issued an order approving the abandonment of the two compressor stations, which we abandoned in December 2011.

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 for the benefit 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 assigned to the Navajo Nation the obligation to perform the final remediation of the site which was completed in August 2011. Additionally, the EPA and Bureau of Indian Affairs (BIA) have entered into an administrative order of consent, pursuant to which the BIA is conducting a remedial investigation/feasibility study at a second site involved in the lawsuit. The remedial investigation/feasibility study is expected to be completed by 2014. Additionally, the United States has filed counterclaims in the District of Columbia alleging that, to the extent we contributed to the disposal of any waste at the second site, we should bear part of the remediation costs at that site. The United States has filed a motion to dismiss our remaining claims, which motion is pending before the district court. 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. The final outcome of these legal proceedings, remediation and feasibility studies, and environmental assessments is uncertain.

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.

Operating Leases. We lease property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, 2011, were as follows:


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

Total	$	11

Rental expense on our lease obligations for the years ended December 31, 2011, 2010 and 2009 was $23 million, $23 million and $21 million and is reflected in operation and maintenance expense on our income statements. Included in our 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.

8. Retirement Benefits

Pension and Retirement Savings Plans. El Paso maintains a pension plan, the El Paso Corporation 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, under the El Paso Corporation Retiree Benefits Plan. 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 were prefunded and were recoverable under prior rate case settlements. Currently, there is no cost recovery or related funding that is required as part of our current FERC approved rates, however, we can seek to recover any funding shortfall that may be required in the future. We do not expect to make any contributions to our postretirement benefit plan in 2012, and there were no contributions made in 2011, 2010 and 2009.

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 in accumulated other comprehensive income, a component of stockholder’s equity, until those gains and losses are recognized in the income statement. Prior to the third quarter of 2011, we recorded a regulatory asset or liability for these unrecognized amounts as allowed by the FERC. During the third quarter of 2011, we reclassified $6 million (net of income taxes of $4 million) from a regulatory liability to accumulated other comprehensive income pursuant to our rate case settlement whereby these amounts are no longer included in the rates we charge our customers.

The table below provides information about our postretirement benefit plan:


	December 31,
	2011			2010
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation—beginning of period	$	50		$	47
Interest cost		2			2
Actuarial loss		1			4
Benefits paid⁽¹⁾		(2	)		(3	)

Accumulated postretirement benefit obligation—end of period	$	51		$	50

Change in plan assets:
Fair value of plan assets—beginning of period	$	84		$	79
Actual return on plan assets		3			9
Benefits paid		(3	)		(4	)

Fair value of plan assets—end of period	$	84		$	84

Reconciliation of funded status:
Fair value of plan assets	$	84		$	84
Less: accumulated postretirement benefit obligation		51			50

Net asset at December 31	$	33		$	34

(1)	Amounts shown net of a subsidy of approximately $1 million for each of the years ended December 31, 2011 and 2010 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Components of Accumulated Other Comprehensive Income. The amount recognized in accumulated other comprehensive income of $3 million at December 31, 2011, net of income taxes of $3 million, is related to unrecognized gains. We do not anticipate that any of this amount will be recognized as part of our net periodic benefit income in 2012.

Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. We may invest plan assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.

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, 2011 and 2010, assets 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. 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 trust funds 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. 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 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, 2011 and 2010.

Expected Payment of Future Benefits. As of December 31, 2011, we expect the following benefit payments under our plan:


Year Ending December 31,	Expected Payments⁽¹⁾
	(In millions)
2012	$	5
2013		5
2014		5
2015		5
2016		5
2017 - 2021		19

(1)	Includes a reduction of approximately $1 million in each of the years 2012—2016 and approximately $3 million in aggregate for 2017—2021 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.


	2011		2010		2009
	(Percent)
Assumptions related to benefit obligations at December 31:
Discount rate		4.16		4.53		5.14
Assumptions related to benefit costs for the year ended December 31:
Discount rate		4.53		5.14		5.90
Expected return on plan assets⁽¹⁾		7.75		7.75		8.00

(1)	The expected return on plan assets listed in the table above is a pre-tax rate of return based on our portfolio of investments. We utilize an after tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes at a rate of 35 percent.

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 7.3 percent, gradually decreasing to 5.0 percent by the year 2019. 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 2011 or 2010. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31:


	2011			2010
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	4		$	3
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(4	)	$	(3	)

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


	2011			2010			2009
	(In millions)
Interest cost	$	2		$	2		$	3
Expected return on plan assets		(6	)		(5	)		(5	)

Net benefit income	$	(4	)	$	(3	)	$	(2	)

9. Transactions with Major Customers

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


	2011⁽¹⁾		2010⁽¹⁾		2009⁽¹⁾
	(In millions)
ConocoPhillips Company	$	80	$	78	$	124
Southern California Gas Company		63		74		89
Southwest Gas Corporation		59		64		*

(1)	Revenues reflect rates subject to refund.

*	Less than 10% of operating revenues.

10. Accounts Receivable Sales Program

We participate in an accounts receivable sales program where we sell receivables in their entirety to a third party financial institution (through a wholly-owned special purpose entity). The sale of these accounts receivable (which are short-term assets that generally settle within 60 days) qualify for sale accounting. The third party financial institution involved in our 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.

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. The tables below contain information related to our accounts receivable sales program.


	Year Ended December 31,
	2011		2010
	(In millions)
Accounts receivable sold to the third-party financial institution⁽¹⁾	$	549	$	528
Cash received for accounts receivable sold under the program		318		335
Deferred purchase price related to accounts receivable sold		231		193
Cash received related to the deferred purchase price		223		180

(1)	During the years ended December 31, 2011 and 2010, losses recognized on the sale of accounts receivable were immaterial.


	As of December 31,
	2011		2010
	(In millions)
Accounts receivable sold and held by third-party financial institution	$	50	$	42
Uncollected deferred purchase price related to accounts receivable sold⁽¹⁾		21		13

(1)	Initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets (Level 2 fair value measurement).

The deferred purchase price related to the accounts receivable sold is reflected as other accounts receivable on our balance sheet. 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 accounts receivable sales program as operating cash flows on our statement of cash flows. Under the accounts receivable sales program, we service the underlying receivables for a fee. The fair value of this servicing agreement, as well as the fees earned, were not material to our financial statements for the years ended December 31, 2011 and 2010.

11. Transactions with Affiliates

Cash Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2011 and 2010, we had a note receivable from El Paso of $873 million and $836 million. We have classified this receivable as noncurrent on our balance sheet at December 31, 2011 as we do not anticipate using it in the next twelve months considering available cash sources and needs. The interest rate on this note is variable and was 2.5% and 1.5% at December 31, 2011 and 2010. During 2011 and 2010, we utilized $103 million and $75 million, net of a $50 million cash contribution from our parent, 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, 2011 and 2010, we had federal and state income taxes payable of $21 million and $24 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 December 31, 2011 and 2010, we had contractual deposits from our affiliates of $9 million.

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, L.L.C. (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 earnings before interest expense and income taxes, gross property and payroll.

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


	2011		2010		2009
	(In millions)
Revenues	$	20	$	19	$	20
Operation and maintenance expenses		76		72		62
Reimbursements of operating expenses		10		11		25

Supplemental Selected Quarterly Financial Information (Unaudited)

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


	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In millions)
2011
Operating revenues	$	124	$	123	$	134	$	128	$	509
Operating income		47		48		47		38		180
Net income		18		18		20		13		69
2010
Operating revenues	$	145	$	126	$	122	$	124	$	517
Operating income		72		49		43		40		204
Net income		32		19		15		17		83

SCHEDULE II

EL PASO NATURAL GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2011, 2010 and 2009

(In millions)


Description	Balance at Beginning of Period		Charged to Costs and Expenses			Deductions			Charged to Other Accounts		Balance at End of Period
2011
Allowance for doubtful accounts	$	2	$	—		$	(2	)	$	—	$	—
Legal reserves		4		4			(8	)		—		—
Environmental reserves		16		—			(2	)		—		14
Regulatory reserves⁽¹⁾		19		—			—			6		25

2010
Allowance for doubtful accounts	$	2	$	—		$	—		$	—	$	2
Legal reserves		2		5			(3	)		—		4
Environmental reserves		19		(1	)		(2	)		—		16
Regulatory reserves⁽¹⁾		74		—			(76	)		21		19

2009
Allowance for doubtful accounts	$	2	$	—		$	—		$	—	$	2
Legal reserves		6		4			(8	)		—		2
Environmental reserves		22		1			(4	)		—		19
Regulatory reserves⁽¹⁾		—		—			—			74		74

(1)	See Note 7 for a discussion of EPNG’s rate cases.

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, 2011, 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 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 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 objectives and our President and CFO 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, 2011. 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 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2011 and 2010 of $931,000 and $982,000, 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 as well as the review of documents filed with the SEC and related 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, 2011 and 2010.

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’s Annual Report on Form 10-K for the year ended December 31, 2011.

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		22
Consolidated Statements of Income and Comprehensive Income		23
Consolidated Balance Sheets		24
Consolidated Statements of Cash Flows		25
Consolidated Statements of Stockholder’s Equity		26
Notes to Consolidated Financial Statements		27

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 Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and 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.

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 27th day of February 2012.


EL PASO NATURAL GAS COMPANY

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

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


Signature	Title	Date

/s/ James J. Cleary	President and Director	February 27, 2012
James J. Cleary	(Principal Executive Officer)

/s/ John R. Sult	Executive Vice President and	February 27, 2012
John R. Sult	Chief Financial Officer (Principal Financial Officer)

/s/ Rosa P. Jackson	Vice President and Controller	February 27, 2012
Rosa P. Jackson	(Principal Accounting Officer)

/s/ James C. Yardley	Chairman of the Board and Director	February 27, 2012
James C. Yardley

/s/ Daniel B. Martin	Director	February 27, 2012
Daniel B. Martin

/s/ Thomas L. Price	Director	February 27, 2012
Thomas L. Price

EL PASO NATURAL GAS COMPANY

EXHIBIT INDEX

December 31, 2011

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 (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 (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		Fourth Amended and Restated Credit Agreement dated as of May 27, 2011, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, N.A. as Administrative Agent and Collateral Agent for the Lenders (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 3, 2011.

10.B		Fourth Amended and Restated Security Agreement dated as of May 27, 2011, among El Paso Corporation, the persons referred to therein as Pipeline Company Borrowers, the persons referred to therein as Subsidiary Grantors, and JPMorgan Chase Bank, N.A., as Collateral Agent and Depository Bank (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 3, 2011.



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.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Schema Document.

*101.CAL		XBRL Calculation Linkbase Document.

*101.DEF		XBRL Definition Linkbase Document.

*101.LAB		XBRL Labels Linkbase Document.

*101.PRE		XBRL Presentation Linkbase Document.