epng200910k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________
 
Form 10-K

(Mark One)

R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
For the fiscal year ended December 31, 2009
   
 
OR
   
£
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 R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yes £No R
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

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

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

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

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

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

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

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

Common Stock, par value $1 per share. Shares outstanding on March 1, 2010: 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 
 
   
 
   
 
   
 
   
 
____________

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

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

 
/d
=
per day
MDth
=
thousand dekatherms
 
BBtu
=
billion British  thermal units
MMcf
=
million cubic feet
 
Bcf
=
billion cubic feet
Tonne
=
metric ton
 
LNG
=
liquefied natural gas
     

When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

When we refer to “us”, “we”, “our”, “ours”, or “EPNG”, we are describing El Paso Natural Gas Company and/or our subsidiaries.





PART I

ITEM 1. BUSINESS

Overview and Strategy

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

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

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

•  
providing outstanding customer service;

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

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

•  
successfully recontracting expiring contracts for transportation capacity; and

•  
focusing on efficiency and synergies across our systems.

The EPNG System. The EPNG system consists of approximately 10,200 miles of pipeline with a winter sustainable west-flow capacity of 4,850 MMcf/d and east-end deliverability of 800 MMcf/d. During 2009, 2008 and 2007, average throughput was 3,937 BBtu/d, 4,379 BBtu/d and 4,189 BBtu/d. This system delivers natural gas from the San Juan, Permian, Anadarko basins and via interconnections in the Rocky Mountains to markets in California, Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.

The Mojave Pipeline Company (Mojave) System.  The Mojave system consists of approximately 500 miles of pipeline with an east to west flow design capacity of approximately 400 MMcf/d. During 2009, 2008 and 2007, average throughput was 379 BBtu/d, 349 BBtu/d and 458 BBtu/d. Mojave’s 2009, 2008 and 2007 throughput includes 334 BBtu/d, 306 BBtu/d and 431 BBtu/d transported volume for the EPNG system. The Mojave system connects with the EPNG system near Cadiz, California, the EPNG and Transwestern systems at Topock, Arizona and to the Kern River Gas Transmission Company system in California. This system also extends to customers in the vicinity of Bakersfield, California.

Storage Facility.  We utilize our Washington Ranch underground storage facility located in New Mexico, which has up to approximately 44 Bcf of underground working natural gas storage capacity, to manage our transportation needs and to offer interruptible storage services.


1


Markets and Competition

Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline systems connect with multiple pipelines that provide our customers with access to diverse sources of supply, including supply from unconventional sources, and various natural gas markets. The natural gas industry is undergoing a major shift in supply sources.  Production from conventional sources is declining while production from unconventional sources, such as shale, tight sands, and coal bed methane, is rapidly increasing. This shift will change the supply patterns and flows of pipelines.  The impact will vary among pipelines according to the proximity of the new supply sources.

Imported LNG has been a significant supply source for the North American market. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems may also compete with us for transportation of gas into market areas we serve.

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

We provide transportation services to the southwestern U.S. and to the Mexican border through connections to other pipelines. The market demand for natural gas distribution as well as gas-fired electric generation capacity has experienced considerable growth in these areas in recent years. Historically, California customers have been the largest holders of capacity on our EPNG system. Currently, California and Arizona customers account for the majority of transportation on the EPNG system, 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.

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

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

2

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

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

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


3


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

 
rates and charges for natural gas transportation and storage;

 
certification and construction of new facilities;

 
extension or abandonment of services and facilities;

 
maintenance of accounts and records;

 
relationships between pipelines and certain affiliates;

 
terms and conditions of service;

 
depreciation and amortization policies;

 
acquisition and disposition of facilities; and

 
initiation and discontinuation of services.

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

Environmental

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

Employees

As of February 23, 2010, we had approximately 560 full-time employees, none of whom are subject to a collective bargaining arrangement.

4


ITEM 1A. RISK FACTORS

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

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

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

Risks Related to Our Business

Our success depends on factors beyond our control.

The financial results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volume of natural gas we are able to transport and store depends on the actions of third parties, and is beyond our control. This includes factors that impact our customers’ demand and producers’ supply, including factors that negatively impact our customers’ need for natural gas from us, as well as the continued availability of natural gas production and reserves connected to our pipeline system.  Further, the following factors, most of which are also beyond our control, may unfavorably impact our ability to maintain or increase current throughput, or to remarket unsubscribed capacity on our pipeline systems:

 
service area competition;

 
price competition;

 
expiration or turn back of significant contracts;

 
changes in regulation and action of regulatory bodies;

 
weather conditions that impact natural gas throughput and storage levels;

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

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

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

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


5


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

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

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

 
adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets;

 
our ability to achieve targeted annual operating and administrative expenses primarily by reducing internal costs and improving efficiencies from leveraging a consolidated supply chain organization;
 
 
expiration or renewal of existing interests in real property including real property on Native American lands; and

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

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

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

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

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

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


6


Fluctuations in energy commodity prices could adversely affect our business.

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

Pricing volatility may, in some cases, impact the value of under or over recoveries of retained natural gas, as well as imbalances, cashouts and system encroachments.  We obtain in-kind fuel reimbursements from shippers in accordance with the pipeline’s tariff or applicable contract terms.  We revalue our natural gas imbalances and other gas owed to or from shippers to an index price and periodically settle these obligations in cash pursuant to the pipeline’s tariff, regulatory approval or each balancing contract.  Currently, our tariff provides that the difference between the quantity of fuel retained and fuel used in operations will be flowed-through or charged to shippers.

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

 
regional, domestic and international supply and demand, including changes in supply and demand due to general economic conditions and weather;

 
availability and adequacy of gathering, processing and transportation facilities;

 
energy legislation and regulation, including potential changes associated with GHG emissions and renewable portfolio standards;

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

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

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

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

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

7

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

Also, increased regulatory requirements relating to the integrity of our pipelines requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.

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

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

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

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

 
discovering new sites or additional information at existing sites;
 
 
forecasting cash flow timing to implement proposed pollution control and cleanup costs;
 
 
receiving regulatory approval for remediation programs;

 
quantifying liability under environmental laws that may impose joint and several liability on potentially responsible parties and managing allocation responsibilities;

 
evaluating and understanding environmental laws and regulations, including their interpretation and enforcement;
 
 
interpreting whether various maintenance activities performed in the past and currently being performed required pre-construction permits pursuant to the Clean Air Act; and
 
 
changing environmental laws and regulations that may increase our costs.

8

 
 In addition to potentially increasing the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards, emission standards with regard to our reciprocating internal combustion engines on our pipeline systems, GHG reporting and potential mandatory GHG emissions reductions. Future environmental compliance costs relating to GHGs associated with our operations are not yet clear. For a further discussion on GHGs, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies.
 
Although it is uncertain what impact legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances or pay taxes related to our GHG and other emissions, and (v) administer and manage an emissions program for GHG and other emissions. Changes in regulations, including adopting new standards for emission controls from certain of our facilities, could also result in delays in obtaining required permits to construct or operate our facilities.  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 and in the prices at which we sell natural gas, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.

Our operations are subject to operational hazards and uninsured risks.

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

While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles as well as limits on our maximum recovery, and do not cover all risks. There is also the risk that our coverages will change over time in light of increased premiums or changes in the terms of the insurance coverages that could result in our decision to either terminate certain coverages, increase our deductibles or decrease our maximum recoveries.  In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

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

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

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

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

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

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

 
9

 
 
impediments on our ability to acquire rights-of-way or land rights or to commence and complete construction on a timely basis or on terms that are acceptable to us;

 
our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials, labor, contractor productivity, delays in construction or other factors beyond our control, that we may not be able to recover from our customers which may be material;

 
the lack of future growth in natural gas supply and/or demand; and

 
the lack of transportation, storage or throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or we may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

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

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

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

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

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


10


We are subject to financing and interest rate risks.

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

 
our credit ratings;

 
the structured and commercial financial markets;
 
 
market perceptions of us or the natural gas and energy industry;
 
 
tax rates due to new tax laws; and
 
 
market prices for hydrocarbon products.

Risks Related to Our Affiliation with El Paso

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

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. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as credit rating agencies continue to review our and El Paso’s leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital and collateral requirements.
 

 
11

 
El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated note receivable. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 10.

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

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

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

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

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



12


ITEM 1B. UNRESOLVED STAFF COMMENTS

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

ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

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

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

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

PART II

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

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

We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors.  During both 2009 and 2008, we utilized $200 million of our note receivable from the cash management program to pay dividends to our parent.

ITEM 6. SELECTED FINANCIAL DATA

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


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

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

Overview

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

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

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



14


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. We refer to the difference between the maximum rates allowed under our tariff and the contractual rate we charge as discounts.

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

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

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

15

Results of Operations

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

Operating Results:
 
 
2009
   
2008
 
   
(In millions,
 
   
except for volumes)
 
Operating revenues
  $ 593     $ 590  
Operating expenses
    (314 )     (333 )
Operating income
    279       257  
Other income, net
    2       5  
EBIT
    281       262  
Interest and debt expense
    (93 )     (90 )
Affiliated interest income, net
    19       46  
Income tax expense
    (79 )     (83 )
Net income
  $ 128     $ 135  
Throughput volumes (BBtu/d)(1)
    3,982       4,422  
____________

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

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

(1)
Consists of individually insignificant items.

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

 
16

 
    During 2009, our throughput volumes decreased compared with 2008.  This was due, in part, to a decrease in natural gas and electric generation demand due to weak macroeconomic conditions in the southwestern U.S., as well as the introduction in April 2009 of a new interstate natural gas pipeline with approximately 500 MDth/d of capacity serving the greater Phoenix, Arizona area. Additionally, although a reduction in throughput on our system is not material to our short-term financial results due to a substantial portion of our revenues being based on firm reservation charges under long-term contracts, it can be an indication of the risks we may face when seeking to recontract or renew any of our existing firm transportation contracts in the future. If these macroeconomic conditions continue, it could negatively impact basis differentials over the longer term and our ability to renew firm transportation contracts that are expiring on our system or our ability to renew such contracts at current rates.  If, however, we determine there is a significant change in our cost of providing service or billing determinants, we have the option to file a future rate case with the FERC to recover our prudently incurred costs.
 
Enron Bankruptcy Settlement. During 2008, we recorded income of approximately $10 million, net of amounts owed to certain customers as a result of settlements received from the Enron bankruptcy.

Operational Gas and Revaluations.  On October 1, 2009, we received an order from the FERC directing us to remove the cost and revenue component of our fuel recovery mechanism on our EPNG system.  Our compliance filing to remove the cost and revenue component was approved in the fourth quarter of 2009. Due to this order, our future earnings may be impacted positively or negatively depending on fluctuations in gas prices related to the revaluation of our under or over recoveries, imbalances and system encroachments.  Our tariff continues 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.

Operating and General and Administrative Expenses. During the year ended December 31, 2009, our operating and general and administrative expenses were lower primarily as a result of decreased repair and maintenance expenses.

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

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

Interest and Debt Expense

Interest and debt expense for the year ended December 31, 2009, was $3 million higher than in 2008 primarily due to interest recorded in 2009 for EPNG’s rate refund provision related to its rate case effective January 1, 2009, and lower capitalized interest on allowance for funds used during construction due to lower capital expenditures.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, 2009, was $27 million lower than in 2008 primarily due to lower average short-term interest rates on average advances to El Paso under its cash management program. The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:

   
2009
   
2008
 
   
(In billions, except for rates)
 
Average advance due from El Paso
  $ 1.1     $ 1.1  
Average short-term interest rate
    1.7 %     4.4 %

Income Taxes

Our effective tax rate of 38 percent for the years ended December 31, 2009 and 2008 was higher than the statutory rate of 35 percent in both periods due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 2.
17

 
Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program.  During 2009, we utilized $200 million of our note receivable from the cash management program to pay dividends to our parent.  At December 31, 2009, we had a note receivable from El Paso of approximately $1.0 billion of which approximately $103 million was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. See Item 8, Financial Statements and Supplementary Data, Note 10, for a further discussion of El Paso’s cash management program. Our primary uses of cash are for working capital, capital expenditures and debt service requirements.  Our cash capital expenditures for the year ended December 31, 2009 and those planned for 2010 are listed below.

   
2009
   
Expected
2010
 
   
(In millions)
 
Maintenance
  $ 112     $ 113  
Expansion/Other
    4       7  
Total
  $ 116     $ 120  

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

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

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program.  As of December 31, 2009, El Paso had approximately $1.8 billion of available liquidity, including approximately $1.3 billion of capacity available to it under various committed credit facilities. In addition to the cash management program above, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2009, El Paso had approximately $0.8 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us.  While we do not anticipate a need to directly access the financial markets in 2010 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.

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




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Commitments and Contingencies

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

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

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

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

The Environmental Protection Agency (EPA) finalized regulations to monitor and report GHG emissions on an annual basis.  The EPA also proposed new regulations to regulate GHGs under the Clean Air Act, which the EPA has indicated could be finalized as early as March 2010.  The effective date and substantive requirements of any EPA final rule is subject to interpretation and possible legal challenges.  In addition, it is uncertain whether federal legislation might be enacted that either delays the implementation of any climate change regulations of the EPA or adopts a different statutory structure for regulating GHGs than is provided for pursuant to the Clean Air Act.  Therefore, the potential impact on our operations remains uncertain.
 
 
19

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

Legislative and regulatory efforts are underway in various states and regions.  These rules once finalized may impose additional costs on our operations and permitting our facilities, which could include costs to purchase offset credits or emission allowances, to retrofit or install equipment or to change existing work practice standards.  In addition, various lawsuits have been filed seeking to force further regulation of GHG emissions, as well as to require specific companies to reduce GHG emissions from their operations. Enactment of additional regulations by the federal or state governments, as well as lawsuits, could result in delays and have negative impacts on our ability to obtain permits and other regulatory approvals with regard to existing and new facilities, could impact our costs of operations, as well as require us to install new equipment to control emissions from our facilities, the costs of which would likely be material.

Energy Legislation.  In conjunction with these climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint”.  These proposals would establish renewable energy and efficiency standards at both the federal and state level, some of which would require a material increase of renewable sources, such as wind and solar power generation, over the next several decades.  There have also been proposals to increase the development of nuclear power and commercialize carbon capture and sequestration especially at coal-fired facilities.  Other proposals would establish incentives for energy efficiency and conservation.  Although it is reasonably likely that many of these proposals will be enacted over the next few years, we cannot predict the form of any laws and regulations that might be enacted, the timing of their implementation, or the precise impact on our operations or demand for natural gas.  However, such proposals if enacted could negatively impact natural gas demand over the longer term.


20


New Accounting Pronouncements Issued But Not Yet Adopted

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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









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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

 
Pertain 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, 2009. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2009.


22


Report of Independent Registered Public Accounting Firm

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

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

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

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

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

                                               /s/ Ernst & Young LLP

Houston, Texas
March 1, 2010



23


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

 
 
Year Ended December 31,
 
 
 
2009
   
2008
   
2007
 
Operating revenues
  $ 593     $ 590     $ 557  
Operating expenses
                       
Operation and maintenance
    202       213       201  
Depreciation and amortization
    83       80       82  
Loss on long-lived assets
          14       9  
Taxes, other than income taxes
    29       26       27  
      314       333       319  
Operating income
    279       257       238  
Other income, net
    2       5       4  
Interest and debt expense
    (93 )     (90 )     (98 )
Affiliated interest income, net
    19       46       71  
Income before income taxes
    207       218       215  
Income tax expense
    79       83       83  
Net income
  $ 128     $ 135     $ 132  

See accompanying notes.


24


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

 
 
December 31,
 
 
 
2009
   
2008
 
ASSETS
           
Current assets
           
Cash and cash equivalents
  $     $  
Accounts and notes receivable
               
Customer, net of allowance of $2 in 2009 and 2008
    56       66  
Affiliates
    111       6  
Other
    3       6  
Materials and supplies
    47       43  
Deferred income taxes
    35       12  
Prepaids
    15       15  
Other
    11       8  
Total current assets
    278       156  
Property, plant and equipment, at cost
    3,899       3,804  
Less accumulated depreciation and amortization
    1,409       1,365  
Total property, plant and equipment, net
    2,490       2,439  
Other assets
               
Note receivable from affiliate
    886       986  
Other
    110       103  
      996       1,089  
Total assets
  $ 3,764     $ 3,684  
                 
LIABILITIES AND STOCKHOLDER’S EQUITY
               
Current liabilities
               
Accounts payable
               
Trade
  $ 83     $ 48  
Affiliates
    42       21  
Other
    14       18  
Current maturities of long-term debt
    54        
Taxes payable
    103       79  
Accrued interest
    21       20  
Accrued liabilities
    82       9  
Regulatory liabilities
    17       33  
Other
    30       31  
Total current liabilities
    446       259  
Long-term debt, less current maturities.
    1,113       1,166  
Other liabilities
               
Deferred income taxes
    408       389  
Other
    71       72  
      479       461  
Commitments and contingencies (Note 6)
               
Stockholder’s equity
               
Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding
           
Additional paid-in capital
    1,268       1,268  
Retained earnings
    458       530  
Total stockholder’s equity
    1,726       1,798  
Total liabilities and stockholder’s equity
  $ 3,764     $ 3,684  

See accompanying notes.


25


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

 
 
Year Ended December 31,
 
 
 
2009
   
2008
   
2007
 
Cash flows from operating activities
                 
Net income
  $ 128     $ 135     $ 132  
Adjustments to reconcile net income to net cash from operating activities
                       
Depreciation and amortization
    83       80       82  
Deferred income tax expense (benefit)
    (3 )     14       37  
Loss on long-lived assets
          14       9  
Other non-cash income items
    (6 )     12       8  
Asset and liability changes
                       
Accounts receivable
    10       3       9  
Accounts payable
    55       (65 )     65  
Taxes payable
    12       24       (27 )
Other current assets
    (4 )     (13 )     (5 )
Other current liabilities
    80       (13 )     (88 )
Non-current assets
    (55 )     56       (66 )
Non-current liabilities
    8       8       (31 )
Net cash provided by operating activities
    308       255       125  
                         
Cash flows from investing activities
                       
Capital expenditures
    (116 )     (186 )     (120 )
Net change in note receivable from affiliate
    (3 )     127       (43 )
Proceeds from disposal of property
    14              
Other
    (3 )     4       2  
Net cash used in investing activities
    (108 )     (55 )     (161 )
                         
Cash flows from financing activities
                       
Dividends paid to parent
    (200 )     (200 )      
Net proceeds from issuance of long-term debt
                350  
Payments to retire long-term debt
                (314 )
Net cash provided by (used in) financing activities
    (200 )     (200 )     36  
                         
Net change in cash and cash equivalents
                 
Cash and cash equivalents
                       
Beginning of period
                 
End of period
  $     $     $  

See accompanying notes.


26


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
   
Loss
   
Equity
 
January 1, 2007
    1,000     $     $ 1,268     $ 462     $ (4 )   $ 1,726  
Net income
                            132               132  
Reclassification to regulatory asset (Note 7)
                                    4       4  
December 31, 2007
    1,000             1,268       594             1,862  
Net income
                            135               135  
Dividend paid to parent
                            (200 )             (200 )
Adoption of accounting standard updates related to postretirement benefits, net of income tax of less than $1 (Note 7)
                            1               1  
December 31, 2008
    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  

See accompanying notes.


27


EL PASO NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

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

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

Use of Estimates

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

Regulated Operations

Our natural gas pipelines and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations.  Under these standards, we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, loss on reacquired debt, an equity return component on regulated capital projects and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

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

Materials and Supplies

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


28


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

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

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at 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 lives and characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. For certain general plant and rights-of-way, we depreciate the asset to zero. The majority of our property, plant and equipment are on our EPNG system which has depreciation rates ranging from one percent to 20 percent and depreciable lives ranging from five to 92 years consistent with our rate settlements with the FERC. The depreciation rates on our Mojave Pipeline Company system range from two percent to 33 percent per year. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage rates.

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

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

At December 31, 2009 and 2008, we had $63 million and $54 million of construction work-in-progress included in our property, plant and equipment.

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


29


Asset Impairments

We evaluate assets for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sale, among other factors.

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

Revenue Recognition

Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

Environmental Costs and Other Contingencies

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

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

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


30


Income Taxes

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

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

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

Accounting for Asset Retirement Obligations

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

We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We accrue a liability for legal obligations based on an estimate of the timing and amount of their settlement.

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


31


Postretirement Benefits

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

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

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

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

2. Income Taxes

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

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

 
 
2009
   
2008
   
2007
 
   
(In millions)
 
Current
                 
Federal
  $ 72     $ 61     $ 40  
State
    10       8       6  
      82       69       46  
Deferred
                       
Federal
    (3 )     12       32  
State
          2       5  
      (3 )     14       37  
Total income tax expense
  $ 79     $ 83     $ 83  


32


Effective Tax Rate Reconciliation. Our income tax expense differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:

 
 
2009
   
2008
   
2007
 
   
(In millions, except for rates)
 
Income tax expense at the statutory federal rate of 35%
  $ 72     $ 76     $ 75  
State income taxes, net of federal income tax effect
    7       7       7  
Non-deductible expenses
                1  
Income tax expense
  $ 79     $ 83     $ 83  
Effective tax rate
    38 %     38 %     39 %

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

 
 
2009
   
2008
 
   
(In millions)
 
Deferred tax liabilities
           
Property, plant and equipment
  $ 482     $ 468  
Regulatory and other assets
    28       27  
Total deferred tax liability
    510       495  
Deferred tax assets
               
U.S. net operating loss and tax credit carryovers
    77       77  
Regulatory and other reserve
    33       8  
Other liabilities
    27       33  
Total deferred tax asset
    137       118  
Net deferred tax liability
  $ 373     $ 377  

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

Tax Credits and Carryovers. As of December 31, 2009, 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 IRS regulations.

3. Fair Value of Financial Instruments

At December 31, 2009 and 2008, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term nature of these instruments. At    December 31, 2009 and 2008, we had an interest bearing note receivable from El Paso of approximately $1.0 billion due upon demand, with a variable interest rate of 1.5% and 3.2%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

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

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


33


4. Regulatory Assets and Liabilities

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

 
 
2009
   
2008
   
(In millions)
Current regulatory assets
     
Deferred fuel lost and unaccounted for gas
  $ 7     $ 5  
Other
    3       2  
Total current regulatory assets
    10       7  
Non-current regulatory assets
               
Taxes on capitalized funds used during construction
    24       22  
Unamortized loss on reacquired debt
    24       27  
Postretirement benefits
    8       9  
Under-collected state income taxes
    5       6  
Other
    4       4  
Total non-current regulatory assets
    65       68  
    Total regulatory assets
  $ 75     $ 75  
                 
Current regulatory liabilities
               
Property and plant depreciation
  $ 3     $ 5  
Gas retained and not used in operations
    5       15  
Pipeline integrity program
          3  
Other
    9       10  
Total current regulatory liabilities
    17       33  
Non-current regulatory liabilities
               
Property and plant depreciation
    30       37  
Postretirement benefits
    15       4  
Excess deferred federal income taxes
    2       2  
Total non-current regulatory liabilities
    47       43  
Total regulatory liabilities
  $ 64     $ 76  

The significant regulatory assets and liabilities include:

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

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

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

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

Property and Plant Depreciation. Amounts represent the deferral of customer-funded amounts for costs of future asset retirements.
34

 
5. Debt and Credit Facilities

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

 
 
2009
   
2008
 
   
(In millions)
 
7.625% Notes due August 2010
  $ 54     $ 54  
5.95% Notes due April 2017
    355       355  
8.625% Debentures due January 2022
    260       260  
7.50% Debentures due November 2026
    200       200  
8.375% Notes due June 2032
    300       300  
      1,169       1,169  
Less: Current maturities of long-term debt
    54        
  Unamortized discount
    2       3  
Total long-term debt
  $ 1,113     $ 1,166  

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

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

6. Commitments and Contingencies

Legal Proceedings

Baldonado et al. v. EPNG. In August 2000, a main transmission line owned and operated by us ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Individuals at the site were fatally injured. In June 2003, a lawsuit entitled Baldonado et al. v. EPNG was filed in state court in Eddy County, New Mexico, on behalf of 26 firemen and emergency medical service personnel who responded to the fire and who allegedly have suffered psychological trauma. After a trial which began in October 2009, a jury returned a verdict in our favor in December 2009. Subsequently, the firemen and emergency medical service personnel agreed to waive their right to appeal. As a result, this case was closed.

Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an order dismissing all claims against all defendants. In March 2009, the Tenth Circuit Court of Appeals affirmed the dismissals and in October 2009, the plaintiff’s appeal to the United States Supreme Court was denied.

Similar allegations were filed in a set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. The plaintiffs seek an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. In September 2009, the court denied the motions for class certification. The plaintiffs have filed a motion for reconsideration.  Our costs and legal exposure related to this lawsuit and claims are not currently determinable.
 
 
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Bank of America. We are a named defendant, along with Burlington Resources, Inc. (Burlington), now a subsidiary of ConocoPhillips Company, in a class action lawsuit styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, L.P., filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting royalty underpayment claims related to specified shallow wells in Oklahoma, Texas and New Mexico. The Plaintiffs assert that royalties were underpaid starting in the 1980s when the purchase price of gas was lowered below the Natural Gas Policy Act maximum lawful prices. The Plaintiffs assert that royalties were further underpaid by Burlington as a result of post-production cost deductions taken starting in the late 1990s. This action was transferred to Washita County District Court in 2004. A tentative settlement reached in November 2005 was disapproved by the court in June 2007. A class certification hearing occurred in April 2009.  The court certified a Texas and Oklahoma class of royalty owners.  The class certification has been appealed to the Oklahoma Court of Appeals.  A companion case styled Bank of America v. El Paso Natural Gas involving similar claims made as to certain wells in Oklahoma was settled in 2006. Our costs and legal exposure related to this lawsuit are not currently determinable.

In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2009, we had accrued approximately $2 million for our outstanding legal matters.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2009 and 2008, we had accrued approximately $19 million and $22 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $40 million at December 31, 2009. Our accrual at December 31, 2009 includes $17 million for environmental contingencies related to properties we previously owned.

Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

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

 
36

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

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

Rates and Regulatory Matter

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

Other Matters

Navajo Nation. In March 2009, representatives of the Navajo Nation and EPNG executed a final agreement setting forth the full terms and conditions of the Navajo Nation’s consent to EPNG’s rights-of-way through the Navajo Nation. Under this agreement, we will make annual payments of approximately $19 million for our rights-of-way beginning in 2009 and continuing through 2025, subject to annual adjustments.  We submitted the Navajo Nation’s consent agreement in support of our pending application to the United States Department of the Interior (the Department) for an extension of the Department’s current rights-of-way grant. We expect the submission will result in the Department’s final processing of our application. We have filed with the FERC for recovery of payments under rights-of-way in our recent rate case.

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

 
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Other Commitments

Capital Commitments. At December 31, 2009, we had capital commitments of approximately $2 million. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

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

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

Rental expense on our lease obligations for the years ended December 31, 2009, 2008 and 2007 was $21 million, $22 million and $20 million. These amounts include rent allocated to us from El Paso.

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. We have executed a long-term rights-of-way agreement with the Navajo Nation which will result in a significant commitment by us upon approval of our pending application with the Department of Interior (see Navajo Nation above).

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

7. Retirement Benefits

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

     Postretirement Benefits Plan. We provide postretirement medical benefits for a closed group of employees who retired on or before March 1, 1986, and limited postretirement life insurance for employees who retired after January 1, 1985. As such, our obligation to accrue for other postretirement employee benefits is primarily limited to the fixed population of retirees who retired on or before March 1, 1986. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We do not expect to make any contributions to our postretirement benefit plan in 2010.

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

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The table below provides information about our postretirement benefit plan.  In 2008, we adopted the FASB’s revised measurement date provisions for other postretirement benefit plans and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008.  For 2009, the information is presented and computed as of and for the twelve months ended December 31, 2009.

 
 
December 31, 2009
   
December 31,
2008
 
   
(In millions)
 
Change in accumulated postretirement benefit obligation:
           
Accumulated postretirement benefit obligation - beginning of period
  $ 52     $ 62  
Interest cost
    3       5  
Actuarial gain
    (4 )     (8 )
Benefits paid(1) 
    (4 )     (7 )
Accumulated postretirement benefit obligation - end of period
  $ 47     $ 52  
Change in plan assets:
               
Fair value of plan assets - beginning period 
  $ 71     $ 104  
Actual return on plan assets
    13       (25 )
Benefits paid
    (5 )     (8 )
Fair value of plan assets - end of period 
  $ 79     $ 71  
Reconciliation of funded status:
               
Fair value of plan assets
  $ 79     $ 71  
Less: accumulated postretirement benefit obligation
    47       52  
Net asset at December 31
  $ 32     $ 19  
____________
(1)
 
Amounts shown net of a subsidy of approximately $1 million for each of the years ended December 31, 2009 and 2008 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is 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 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, 2009, our assets are comprised of an exchange-traded mutual fund with a fair value of $2 million and common/collective trusts with a fair value of $77 million.  Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets.  Our common/collective trusts are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets.  We may adjust the fair value of our common/collective trusts, when necessary, for factors such as liquidity or risk of nonperformance by the issuer.  We do not have any assets that are considered Level 3 measurements.  The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2009 and 2008.


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

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

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

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

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

(1)
The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 8.0 percent, gradually decreasing to 5.0 percent by the year 2015. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change would not have had a significant effect on interest costs in 2009 or 2008. A one-percentage point change in assumed health care cost trends would have the following effect as of December 31, 2009 and 2008:

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

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

 
 
2009
   
2008
   
2007
 
   
(In millions)
 
Interest cost
  $ 3     $ 4     $ 4  
Expected return on plan assets
    (5 )     (7 )     (6 )
Amortization of net actuarial gain
          (2 )      
Net benefit income
  $ (2 )   $ (5 )   $ (2 )


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8. Transactions with Major Customers

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

 
 
2009(1)
   
2008
   
2007
 
   
(In millions)
 
ConocoPhillips Company(2) 
  $ 124     $ 82     $ 47  
Sempra Energy and Subsidiaries (3) 
    89       85       93  
____________

(1)
Revenues reflect rates subject to refund.
(2)
In 2007, ConocoPhillips Company did not represent more than 10 percent of our revenues.
(3)
Amounts include  revenues from Southern California Gas Company.

9. Supplemental Cash Flow Information

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

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

10. Transactions with Affiliates

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

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, 2009 and 2008, we had income taxes payable of $90 million and $79 million. The majority of these balances, as well as our deferred income taxes, will become payable to El Paso. See Note 1 for a discussion of our income tax policy.

Other Affiliate Balances. At both December 31, 2009 and 2008, we had contractual deposits from our affiliates of $8 million included in other current liabilities on our balance sheets.

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

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


41


The following table shows overall revenues and charges from our affiliates for each of the three years ended December 31:
 
   
2009 
   
2008 
   
2007
 
   
(In millions)
 
Revenues from affiliates
  $ 20     $ 17     $ 19  
Operation and maintenance expenses from affiliates
    62       56       53  
Reimbursements of operating expenses charged to affiliates
    25       21       17  

11. Supplemental Selected Quarterly Financial Information (Unaudited)

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

 
 
Quarters Ended
   
 
 
 
March 31
   
June 30
   
September 30
   
December 31(1)
   
Total
   
(In millions)
2009
                       
Operating revenues
  $ 157     $ 144     $ 145     $ 147     $ 593  
Operating income
    81       67       66       65       279  
Net income
    40       30       30       28       128  
                                         
2008
                                       
Operating revenues
  $ 141     $ 152     $ 145     $ 152     $ 590  
Operating income
    60       74       61       62       257  
Net income
    33       40       31       31       135  
                                         
____________

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


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SCHEDULE II

EL PASO NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2009, 2008 and 2007
(In millions)

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

(1)
See Note 6 to the financial statements for EPNG’s rate case discussion.


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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

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

ITEM9A(T). CONTROLS AND PROCEDURES

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

ITEM 9B. OTHER INFORMATION

None.


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PART III

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2009 and 2008 of $796,000 and $751,000, respectively, were primarily for professional services rendered by Ernst & Young LLP and for the audits of the consolidated financial statements of El Paso Natural Gas Company and its subsidiaries as well as the review of documents filed with the SEC and related consent.

All Other Fees

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

Policy for Approval of Audit and Non-Audit Fees

We are an indirect wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2010 Annual Meeting of Stockholders.


45


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
23
Consolidated Statements of Income
24
Consolidated Balance Sheets
25
Consolidated Statements of Cash Flows
26
Consolidated Statements of Stockholder’s Equity
27
Notes to Consolidated Financial Statements
28
   
2. Financial statement schedules
 
   
Schedule II — Valuation and Qualifying Accounts
43

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

3. Exhibits

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

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

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

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

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

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

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

Undertaking

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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El Paso Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 1st day of March 2010.
 
 
 
EL PASO NATURAL GAS COMPANY
 
 
       
Date
By:
/s/ James J. Cleary  
    James J. Cleary  
    President  
       
 

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

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


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EL PASO NATURAL GAS COMPANY

EXHIBIT INDEX
December 31, 2009

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(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(Exhibit 3.B to our Annual Report for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
   
*4.A
Indenture dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.), as Trustee.
   
*4.B
Indenture dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee.
   
4.C
Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee (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(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 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
   
4.F
First Supplemental Indenture dated as of April 4, 2007 between El Paso Natural Gas Company and Wilmington Trust Company, as trustee, to indenture dated as of July 23, 2003 (Exhibit 4.C to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
   
4.G
Form of 5.95% Senior Note due 2017 (included in Exhibit 4.E).
   

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*10.A
Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent.
   
*10.B
Third Amendment and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank.
   
10.C
Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007.)
   
10.D
Registration Rights Agreement, dated as of April 4, 2007, among El Paso Natural Gas Company and Deutsche Bank Securities Inc., Citigroup Global Markets Inc., ABN AMRO Incorporated, Goldman, Sachs & Co, Greenwich Capital Markets, Inc., J.P. Morgan Securities Inc. and SG Americas Securities, LLC (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on April 9, 2007).
   
*12
Ratio of Earnings to Fixed Charges.
   
21
Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
   
*23
Consent of Independent Registered Public Accounting Firm Ernst & Young LLP.
   
*31.A
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
*31.B
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
*32.A
Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
   
*32.B
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
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