Edgar Filing: EL PASO CORP/DE

Percent of 2009

Description

Revenues

Reservation

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

Usage and Other

Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenues from the processing and sale of natural gas liquids and other miscellaneous sources.

e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


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

For the fiscal year ended December 31, 2009


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

For the transition period from to .

Commission File Number 1-14365

El Paso Corporation

(Exact Name of Registrant as Specified in Its Charter)


Delaware (State or Other Jurisdiction of Incorporation or Organization)		76-0568816 (I.R.S. Employer Identification No.)

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

Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
Securities registered pursuant to Section 12(b) of the Act:


		Name of Each Exchange
Title of Each Class		on which Registered
Common Stock, par value $3 per share		New York Stock Exchange

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

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

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

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

Indicate by check mark 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 þ No o.

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

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
	(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 o No þ.

State the aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant.

Aggregate market value of the voting stock (which consists solely of shares of common stock) held by non-affiliates of the registrant as of June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, computed by reference to the closing sale price of the registrant’s common stock on the New York Stock Exchange on such date: $6,471,986,386.

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 $3 per share. Shares outstanding on February 23, 2010: 701,318,796

Documents Incorporated by Reference

List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: Portions of our definitive proxy statement for the 2010 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. These will be filed no later than April 30, 2010.

EL PASO CORPORATION
TABLE OF CONTENTS


Caption		Page
PART I

Item 1.	Business		4
Item 1A.	Risk Factors		32
Item 1B.	Unresolved Staff Comments		46
Item 2.	Properties		46
Item 3.	Legal Proceedings		46

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		47
Item 6.	Selected Financial Data		50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		90
Item 8.	Financial Statements and Supplementary Data		92
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		165
Item 9A.	Controls and Procedures		165
Item 9B.	Other Information		165

PART III

Item 10.	Directors, Executive Officers and Corporate Governance		166
Item 11.	Executive Compensation		166
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		166
Item 13.	Certain Relationships and Related Transactions, and Director Independence		166
Item 14.	Principal Accountant Fees and Services		166

PART IV

Item 15.	Exhibits and Financial Statement Schedules		167
Signatures			168
EX-10.A
EX-10.F.2
EX-10.F.3
EX-10.H
EX-10.I
EX-10.J
EX-10.J.2
EX-10.R
EX-10.T.1
EX-10.V
EX-10.W
EX-12
EX-21
EX-23.A
EX-23.B
EX-23.D
EX-31.A
EX-31.B
EX-32.A
EX-32.B
EX-99.A
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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


/d	=	per day
Bbl	=	barrel
BBtu	=	billion British thermal units
Bcf	=	billion cubic feet
Bcfe	=	billion cubic feet of natural gas equivalents
KM	=	kilometer
LNG	=	liquefied natural gas
MBbls	=	thousand barrels
Mcf	=	thousand cubic feet
Mcfe	=	thousand cubic feet of natural gas equivalents
MDth	=	thousand decatherms
MMBtu	=	million British thermal units
MMcf	=	million cubic feet
MMcfe	=	million cubic feet of natural gas equivalents
GWh	=	thousand megawatt hours
GW	=	gigawatts
MW	=	megawatt
NGL	=	natural gas liquids
TBtu	=	trillion British thermal units
Tcfe	=	trillion cubic feet of natural gas equivalents

When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, 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”, “the Company”, or “El Paso”, we are describing El Paso Corporation and/or our subsidiaries.

PART I

ITEM 1. BUSINESS

Business and Strategy

We are an energy company, originally founded in 1928 in El Paso, Texas that primarily operates in the natural gas transmission and exploration and production sectors of the energy industry. Our purpose is to provide natural gas and related energy products in a safe, efficient and dependable manner.

Natural Gas Transmission. We own or have interests in North America’s largest interstate pipeline system with approximately 42,000 miles of pipe that connect North America’s major natural gas producing basins to its major consuming markets. We also provide approximately 230 Bcf of storage capacity and have an LNG receiving terminal and related facilities in Elba Island, Georgia with 933 MMcf of daily base load sendout capacity. The size, connectivity and diversity of our U.S. pipeline system provides growth opportunities through infrastructure development or large scale expansion projects and gives us the capability to adapt to the dynamics of shifting supply and demand. Our focus is to enhance the value of our transmission business by successfully executing on our backlog of committed expansion projects in the United States and developing growth projects in our market and supply areas.

Exploration and Production. Our exploration and production business focuses on the exploration for and the acquisition, development and production of natural gas, oil and NGL in the United States (U.S.), Brazil and Egypt. During 2009, in the U.S., we shifted our focus to more unconventional resources including the Haynesville Shale in northwest Louisiana and east Texas, Eagle Ford Shale in south Texas, and Altamont-Bluebell-Cedar Rim Field fractured tight sands in Utah. As of December 31, 2009, we held estimated proved natural gas and oil reserves of 2.75 Tcfe, including 0.2 Tcfe of proved natural gas and oil reserves related to Four Star Oil & Gas Company (Four Star), our unconsolidated affiliate. Our focus is on growing our reserve base over the long-term through disciplined capital allocation and portfolio management, cost control and marketing our natural gas and oil production at optimal prices while managing associated price risks.

Our operations are conducted through two core segments, Pipelines and Exploration and Production. We also have Marketing and Power segments. Our business segments provide a variety of energy products and services and are managed separately as each segment requires different technology and marketing strategies. For a further discussion of our business segments, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data, Note 17. In October 2009, we also announced our re-entry into the midstream business where we believe that the movement to more unconventional supply basins will present future opportunities.

Pipelines Segment

Our Pipelines segment includes our interstate natural gas transmission systems and related operations conducted through seven separate, wholly or majority owned pipeline systems, and four partially owned systems. These systems connect the nation’s principal natural gas supply regions to the five largest consuming regions in the United States: the Gulf Coast, California, the northeast, the southwest and the southeast. We also have access to systems in Canada and assets in Mexico. Our Pipelines segment also includes our ownership of storage capacity through our transmission systems, three underground natural gas storage facilities, and two LNG terminalling facilities one of which is under construction.

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

	•		providing outstanding customer service;

	•		executing successfully on time and on budget our backlog of committed expansion projects;

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

	•		ensuring the safety of our pipeline systems and assets;

	•		optimizing our contract portfolio; and

	•		focusing on efficiency and synergies across our systems.

Natural gas pipeline systems. The tables below provide more information on our pipeline systems:


		As of December 31, 2009
Transmission	Supply and	Ownership		Miles of		Design		Storage		Average Throughput⁽¹⁾
System	Market Region	Percentage		Pipeline		Capacity		Capacity		2009		2008		2007
		(Percent)				(MMcf/d)		(Bcf)				(BBtu/d)
Tennessee Gas Pipeline (TGP)	Extends from Louisiana, the Gulf of Mexico and south Texas to the northeast section of the U.S., including the metropolitan areas of New York City and Boston.		100		13,700		7,208	92⁽²⁾			4,614		4,864		4,880

El Paso Natural Gas (EPNG)	Extends from San Juan, Permian, Anadarko basins and via interconnections in the Rocky Mountains to California, its single largest market, as well as markets in Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.		100		10,200	5,650⁽³⁾			44		3,937		4,379		4,189

Mojave Pipeline (MPC)	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.		100		500	400⁽⁴⁾			—		379		349		458

Cheyenne Plains Gas Pipeline (CPG)⁽⁵⁾	Extends from Cheyenne hub and Yuma County in Colorado to various pipeline interconnections near Greensburg, Kansas.		100		400		934		—		841		898		735


⁽¹⁾		Includes throughput transported on behalf of affiliates.

⁽²⁾		Includes 29 Bcf of storage capacity from Bear Creek Storage Company, L.L.C (Bear Creek) which TGP owns equally with Southern Natural Gas Company.

⁽³⁾		Reflects winter-sustainable west-flow capacity of 4,850 MMcf/d and approximately 800 MMcf/d of east-end delivery capacity.

⁽⁴⁾		Reflects east to west flow capacity.

⁽⁵⁾		We own 100 percent of the common shares. See Part II, Item 8, Financial Statements and Supplementary Data, Note 18.


		As of December 31, 2009
Transmission	Supply and	Ownership		Miles of		Design		Storage		Average Throughput⁽¹⁾
System	Market Region	Percentage		Pipeline		Capacity		Capacity		2009		2008		2007
		(Percent)				(MMcf/d)		(Bcf)				(BBtu/d)
Southern Natural Gas (SNG)	Extends from natural gas fields in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including, the metropolitan areas of Atlanta and Birmingham.		92		7,600		3,700	60	⁽²⁾		2,322		2,339		2,345

Colorado Interstate Gas (CIG)	Extends from production areas in the Rocky Mountain region and the Anadarko Basin to the front range of the Rocky Mountains and multiple interconnections with pipeline systems transporting gas to the midwest, the southwest, California and the Pacific northwest.		81		4,200		3,750	35	⁽³⁾		2,299		2,225		2,339

Wyoming Interstate (WIC)	Extends from western Wyoming, eastern Utah, western Colorado and the Powder River Basin to various pipeline interconnections near Cheyenne, Wyoming.		67		800		3,340	—			2,652		2,543		2,071

Florida Gas Transmission (FGT)⁽⁴⁾	Extends from South Texas to South Florida.		50		5,000		2,100	—			2,250		2,147		2,056

Samalayuca Pipeline and Gloria a Dios Compression Station⁽⁵⁾	Extends from U.S.-Mexico border into the state of Chihuahua, Mexico.		50		23		460	—			439		428		462

San Fernando Pipeline⁽⁵⁾	Extends from Pemex Compression Station 19 to the Pemex metering station in San Fernando, Mexico in the State of Tamaulipas.		50		71		1,000	—			951		951		951


⁽¹⁾		Includes throughput transported on behalf of affiliates and represents the systems’ totals and are not adjusted for our ownership interest.

⁽²⁾		Includes 29 Bcf of storage capacity from Bear Creek which SNG owns equally with TGP.

⁽³⁾		Includes 6 Bcf of storage capacity from Totem Gas Storage which is owned by WYCO Development L.L.C. (WYCO), our 50 percent equity investee.

⁽⁴⁾		We have a 50 percent equity interest in Citrus Corp. (Citrus), which owns this system.

⁽⁵⁾		We have a 50 percent equity interest in Gasoductos de Chihuahua, which owns these systems. In February 2010, we entered into an agreement to sell our interest in these assets.

Liquefied Petroleum Gas (LPG) Pipeline System. In December 2007, we placed the LPG Burgos pipeline in service. This 117 mile pipeline, in which we own a 50 percent interest, transports liquefied petroleum gas and extends from Pemex’s Burgos complex to the Monterrey market in the state of Nuevo León, Mexico. The system has a design capacity of 34,000 barrels/day and transported an average of 30,000 barrels/day in 2009, 2008 and 2007.

WYCO. We own a 50 percent interest in WYCO, a joint venture with an affiliate of Public Service Company of Colorado (PSCo). WYCO owns Totem Gas Storage and the High Plains pipeline, which were placed in service in June 2009 and November 2008, respectively, and are operated by us. The High Plains pipeline consists of a 164-mile interstate gas pipeline extending from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain electric generation plant and other points of interconnections with PSCo’s system. The Totem Gas Storage facility interconnects with the High Plains Pipeline and has 6 Bcf of working natural gas storage capacity, with a maximum withdrawal rate of 200 MMcf/d and a maximum injection rate of 100 MMcf/d. WYCO also owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain’s electric generation plant, which we do not operate, and a compressor station in Wyoming that we operate.

Underground Natural Gas Storage Facilities. In addition to the storage capacity in our wholly and majority owned pipeline systems, we have interests in the following natural gas storage facilities:

As of December 31, 2009

Ownership

Storage

Storage Facility

Interest

Capacity

Location

(Percent)

(Bcf)

Bear Creek

100

⁽¹⁾

Louisiana

Young Gas Storage

⁽²⁾

Colorado


⁽¹⁾		Approximately 58 Bcf is contracted to affiliates.

⁽²⁾		Amount is not adjusted for our ownership interest.

Master Limited Partnership. At December 31, 2009, our master limited partnership, EPB, owns WIC, a 58 percent general partner interest in CIG and a 25 percent general partner interest in SNG. As of December 31, 2009, we had a two percent general partner interest and a 65 percent limited partner interest in EPB. Subsequent to a January 2010 public common unit offering, we now own a two percent general partner interest and a 60 percent limited partner interest in EPB.

Federal Energy Regulatory Commission (FERC) Approved Projects. As of December 31, 2009, we had the following significant FERC approved expansion projects on our systems. For a further discussion of other expansion projects, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Anticipated

Existing

Capacity

Completion or

Project

System

(MMcf/d)

Description

In-Service Date

South System III

SNG

370

To add 81 miles of pipe and 17,310 of horsepower compression on our pipeline facilities

2011 — 2012

Southeast Supply
Header Phase II

SNG

350

To add 26,000 of horsepower compression to the jointly owned pipeline facilities

2011

FGT Phase VIII

FGT⁽¹⁾

800

To add more than 483 miles of pipeline loops, laterals and mainline and 213,600 of horsepower compression

2011


⁽¹⁾		We have a 50 percent equity interest in Citrus, which owns this system.

LNG Facilities

Elba Island LNG. We own an LNG receiving terminal located on Elba Island, near Savannah, Georgia, with a peak sendout capacity of 1.2 Bcf/d and a base load sendout capacity of 0.9 Bcf/d. The capacity at the terminal is contracted with subsidiaries of British Gas Group and Royal Dutch Shell PLC.

In September 2007, we received FERC approval to expand the Elba Island LNG receiving terminal and construct the Elba Express Pipeline. The expansion is anticipated to increase the peak sendout capacity of the terminal from 1.2 Bcf/d to 2.1 Bcf/d. The Elba Express Pipeline will consist of approximately 190 miles of pipeline with a total capacity of 1.2 Bcf/d, which will transport natural gas from the Elba Island LNG terminal to markets in the southeastern and eastern United States.

Gulf LNG. In February 2008, we completed our acquisition of a 50 percent interest in the Gulf LNG Clean Energy Project, which is constructing a FERC-approved LNG terminal in Pascagoula, Mississippi with a designed sendout capacity of 1.5 bcf/d that is expected to be placed in service in October 2011.

Markets and Competition

Our Pipelines segment provides natural gas services to a variety of customers, including natural gas producers, marketers, end-users and other natural gas transmission, distribution and electric generation companies. In performing these services, we compete with other pipeline service providers as well as alternative energy sources such as coal, nuclear energy, wind, hydroelectric power, solar and fuel oil.

The 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 on pipelines. The impact will vary among pipelines according to the proximity of the new supply sources. One of our pipelines is connected to two major shale formations: the Haynesville in northern Louisiana and Texas and the Marcellus in Pennsylvania. It is likely that gas from these sources will, over time, displace receipts from traditional sources in south Texas and the Gulf of Mexico on our system. In addition, our system is close to the Eagle Ford Shale formation in south Texas, which could be a major source of supply into the system in the future. This will affect the flows on the system and the array of shipper contracts.

Another change in the supply patterns is the reduction in imports from Canada. This decrease has been the result of declining production and increasing demand in Canada. This reduction has led to increased demand for domestic supplies and related transportation services, but it has been offset in part by imported LNG. LNG has become 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 our pipelines for transportation of gas into the 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.

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, 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. As a result, our pipelines may experience lower throughput, lower revenues and slower development of new expansion projects. While our pipeline systems 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 portion of its revenues through 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. The extent that these amounts are less than the maximum rates varies for each of our pipeline systems. The weighted average remaining contract term for active contracts is approximately five years. The table below shows the years of expiration of our firm transportation contracts as of December 31, 2009 for our wholly and majority owned systems.

The following table details information related to our pipeline systems, including the customers, contracts, markets served and the competition faced by each as of December 31, 2009. Firm customers reserve capacity on our pipeline system, storage facilities or LNG terminalling facilities 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.


Customer Information	Contract Information	Competition

TGP
Approximately 470 firm and interruptible customers.	Approximately 510 firm transportation contracts. Weighted average remaining contract term of approximately four years.	TGP faces competition in all of its market areas. It competes with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on the TGP system competes with alternative energy sources such as electricity, hydroelectric power, coal and fuel oil. In addition, TGP competes with pipelines and gathering systems for connection to new supply sources in Texas, the Gulf of Mexico and from the Canadian border.

Major Customer:
National Grid USA and subsidiaries
(766 BBtu/d)	Expire in 2011-2029.

EPNG
Approximately 160 firm and interruptible customers.	Approximately 190 firm transportation contracts. Weighted average remaining contract term of approximately three years.	EPNG faces competition in the west and southwest from other existing and proposed pipelines, from California storage facilities, and from alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. In addition, EPNG faces competition from LNG facilities located in northern Mexico.

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.


Customer Information	Contract Information	Competition

MPC Approximately 10 firm and interruptible customers.	Approximately three firm transportation contracts. Weighted average remaining contract term of approximately six years.	MPC faces competition from other existing and proposed pipelines, and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil. In addition, Mojave faces competition from LNG facilities located in northern Mexico.

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

CPG Approximately 40 firm and interruptible customers.	Approximately 30 firm transportation contracts. Weighted average remaining contract term of approximately seven years.	CPG competes directly with other interstate pipelines serving the mid-continent region. Indirectly, CPG competes with pipelines that transport Rocky Mountain gas to other markets.

Major Customers:
Oneok Energy Services Company L.P.
(195 BBtu/d)	Expires in 2015.

Encana Marketing (USA) Inc.
(170 BBtu/d)	Expires in 2015.

Anadarko Petroleum Corporation
(195 BBtu/d)	Expire in 2015-2016.

Shell Energy North America US, L.P.
(125 BBtu/d)	Expires in 2019.


Customer Information	Contract Information	Competition

SNG
Approximately 270 firm and interruptible customers.	Approximately 200 firm transportation contracts. Weighted average remaining contract term of approximately six years.	SNG faces competition in a number of its key markets. SNG competes with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on SNG’s system competes with alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. SNG’s four largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines. Also, SNG competes with several pipelines for the transportation business of their other customers. In addition, SNG competes with pipelines and gathering systems for connection to new supply sources.

Major Customers:
Atlanta Gas Light Company⁽¹⁾
(1,063 BBtu/d)	Expire in 2013-2024.

Southern Company Services
(433 BBtu/d)	Expire in 2011-2018.

Alabama Gas Corporation
(372 BBtu/d)	Expire in 2010-2013.

SCANA Corporation
(315 BBtu/d)	Expire in 2013-2019.


⁽¹⁾		Atlanta Gas Light Company is currently releasing a significant portion of its firm capacity to a subsidiary of SCANA Corporation under terms allowed by SNG’s tariff.


Customer Information	Contract Information	Competition

CIG
Approximately 100 firm and interruptible customers.	Approximately 170 firm transportation contracts. Weighted average remaining contract term of approximately eight years.	CIG serves two major markets, an “on-system” market and an “off-system” market. Its “on-system” market consists of utilities and other customers located along the front range of the Rocky Mountains in Colorado and Wyoming. Competitors in this market consist of an intrastate pipeline, an interstate pipeline, local production from the Denver-Julesburg basin, and long-haul shippers who elect to sell into this market rather than the off-system market. CIG’s off-system market consists of the transportation of Rocky Mountain production from multiple supply basins to interconnections with other pipelines bound for the midwest, the southwest, California and the Pacific northwest. Competition in this off-system market consists of interstate pipelines that are directly connected to its supply sources. CIG faces competition from other existing pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, wind, solar, coal and fuel oil.

Major Customers:
PSCo
(1,787 BBtu/d)	Expire in 2010-2029.

Williams Gas Marketing, Inc.
(498 BBtu/d)	Expire in 2010-2014.

Anadarko Petroleum Corporation
(280 BBtu/d)	Expire in 2011-2015.


Customer Information	Contract Information	Competition

WIC
Approximately 50 firm and interruptible customers	Approximately 60 firm transportation contracts. Weighted average remaining contract term of approximately eight years.	WIC competes with existing pipelines to provide transportation services from supply basins in northwest Colorado, eastern Utah and Wyoming to pipeline interconnects in northeast Colorado and western Wyoming. WIC faces competition from other existing pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, wind, solar, coal and fuel oil.

Major Customers:
Williams Gas Marketing, Inc.
(1,320 BBtu/d)	Expire in 2010-2021.

Anadarko Petroleum Corporation
(1,260 BBtu/d)	Expire in 2010-2023.

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. The FERC approves tariffs that establish rates, cost recovery mechanisms, and other terms and conditions of service to our customers. The fees or rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. The FERC’s authority also extends to:

	•		rates and charges for natural gas transportation, storage and related services;

	•		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.

Exploration and Production Segment

Our Exploration and Production segment’s business strategy focuses on the exploration for and the acquisition, development and production of natural gas, oil and NGL in the U.S., Brazil and Egypt. During 2009, in the U.S., we shifted our focus to more unconventional resources including the Haynesville Shale in northwest Louisiana and east Texas, the Eagle Ford Shale in south Texas, and the Altamont-Bluebell-Cedar Rim Field fractured tight sands in Utah. As of December 31, 2009, we controlled approximately 3.9 million net leasehold acres and had proved natural gas and oil reserves of approximately 2.75 Tcfe, including 0.2 Tcfe of proved natural gas and oil reserves related to Four Star, our unconsolidated affiliate. During 2009, daily equivalent natural gas production averaged approximately 763 MMcfe/d, including 72 MMcfe/d from our equity interest in Four Star. We have a balanced portfolio of development and exploration projects that include both long-lived and shorter-lived properties.

Over the past five years, we have grown our exploration and production business through a combination of acquisitions and organic growth initiatives. During this time, we have also sold non-core properties in each of our U.S. divisions in an effort to high grade our asset portfolio. The combination of all these transactions has increased the onshore U.S. weighting of our existing inventory. Our acquisitions include Medicine Bow, which had operations in the western U.S. along with an equity interest in Four Star; Peoples Energy Production Company (Peoples), with operations in east and south Texas, north Louisiana and Mississippi; and producing properties and undeveloped acreage in Zapata County, Texas. Supplementing these acquisitions were smaller “bolt-on” acquisitions of incremental interests where we already had existing operations, including our acquisition in December 2009 of producing properties located primarily in the Altamont-Bluebell-Cedar Rim Field in Utah. Our organic growth has mainly focused on expanding acreage and inventory in proximity to our existing core assets principally in unconventional areas. We currently operate through three divisions in the U.S. which include Central, Western and Gulf Coast and one internationally. Each division is discussed below.

U.S.

Central. The Central division includes operations that are primarily focused on shale gas, tight gas sands, coal bed methane and lower risk conventional producing areas, which are generally characterized by lower development costs, higher drilling success rates and longer reserve lives. We have a large inventory of drilling prospects in this division. During 2009, we invested $376 million on capital projects and production averaged 257 MMcfe/d. The principal operating areas are listed below:


		2009
		Net		Capital		Average
Area	Description	Acres		Investment		Production
		(In millions)				(MMcfe/d)
East Texas/North Louisiana (Arklatex)	Concentrated land positions primarily focused on shale gas and tight gas sands production in the Haynesville Shale, Travis Peak/Hosston, Bossier and Cotton Valley formations. Our operations are primarily in the Bear Creek, Holly, Minden, Bald Prairie, Bethany Longstreet and Logansport fields. We have production and development activities in several fields and hold approximately 40,000 net acres in the Haynesville Shale. We also have land positions in Mississippi. In 2009, we sold certain natural gas producing properties in the Arklatex area.		138,000	$	329		173

Black Warrior Basin	Established shallow coal bed methane producing areas of northwestern Alabama. We have high average working interests and are actively developing our operated properties in this area. In addition, we have a 50 percent average working interest covering approximately 46,000 net acres operated by Black Warrior Methane Corporation which produces from the Brookwood Field.		110,000	$	37		58

Mid-Continent	Primarily in Oklahoma with established production in the Arkoma Basin where we utilize horizontal drilling in the Hartshorne Coals for coal bed methane production. We have approximately 207,000 net acres in the Illinois Basin, focused on the development of the New Albany Shale in southwestern Indiana. We are the operator of these properties and have a 95 percent working interest in this area which is producing and still under evaluation for further investment.		411,000	$	10		26

Western. The Western division includes operations that are primarily focused on natural gas and oil production from coal bed methane, shale gas and lower risk conventional producing areas. We have a large inventory of drilling prospects in this division. During 2009, we invested $190 million on capital projects, including a producing property acquisition of $87 million, and production averaged 154 MMcfe/d. The principal operating areas are listed below:


		2009
		Net		Capital		Average
Area	Description	Acres		Investment		Production
		(In millions)				(MMcfe/d)
Raton Basin	Primarily focused on coal bed methane production in the Raton Basin of northern New Mexico and southern Colorado where we own the minerals beneath the Vermejo Park Ranch.		605,000	$	17		76

Uintah Basin	Primarily focused on fractured oil production in the Altamont-Bluebell-Cedar Rim Field in Utah. In December 2009, we acquired producing properties located primarily in the Altamont-Bluebell-Cedar Rim Field. We also own and operate the Altamont and Bluebell processing plants and related gathering systems in Utah. In January 2010, we decided to close the Bluebell processing plant in the second quarter of 2010.		203,000	$	91		42

Rocky Mountains (Rockies)	Primarily in Wyoming with a focus in the Powder River basin, consisting predominantly of operated oil fields utilizing both primary and secondary recovery methods combined with a non-operated working interest in the County Line coal bed methane unit.		273,000	$	82		36

Gulf Coast. In May 2009, we reorganized our domestic exploration and production operations to combine our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions into the Gulf Coast division. Along the Texas Gulf Coast, we focus on developing and exploring for tight gas sands and unconventional shales in south Texas and the upper Gulf Coast that are characterized by lower risk, longer life production profiles. Our Gulf of Mexico and south Louisiana operations are focused on deeper conventional reservoirs that are characterized by relatively high initial production rates, resulting in higher near-term cash flows and high decline rates. In these areas, we have licensed over 13,500 square miles of three dimensional (3D) seismic data onshore and over 62,500 square miles of 3D seismic data offshore. During 2009, we invested $290 million on capital projects and production averaged 268 MMcfe/d in the Gulf Coast division. The principal operating areas are listed below:


		2009
				Capital		Average
Area	Description	Net Acres		Investment		Production
		(In millions)				(MMcfe/d)
South Texas	Includes the Vicksburg/Frio area with concentrated and contiguous assets in the Jeffress and Monte Christo fields primarily in Hidalgo county, in which we have an average 90 percent working interest. This area also includes assets in the Alvarado and Kelsey fields in Starr and Brooks counties with an average working interest of over 83 percent. The Wilcox area includes working interests in Bob West, Jennings Ranch and Roleta fields in Zapata County. Other interests in Zapata County include the Bustamante and Las Comitas fields.		78,000	$	91		142

Upper Texas Gulf Coast	Includes Wilcox assets in the Renger, Dry Hollow, Brushy Creek and Speaks fields located in Lavaca county and Graceland Field located in Colorado county. In 2009, we expanded our lease position in the Eagle Ford Shale, located in Webb and LaSalle counties, to approximately 132,000 net acres as of December 31, 2009. This area also includes Vermilion Parish and associated bays and inland waters in southwestern Louisiana that are covered by the Catapult 3D seismic project. We have internally processed 2,800 square miles of contiguous 3D seismic data in this project.		215,000	$	122		40

Gulf of Mexico	Gulf of Mexico area includes interests in 70 Blocks south of the Louisiana, Texas and Alabama shoreline focused on deep (greater than 12,000 feet) natural gas and oil reserves in relatively shallow water depths (less than 400 feet).		262,000	$	77		86

Unconsolidated Affiliate — Four Star. We have an approximate 49 percent equity interest in Four Star. Four Star operates onshore in the San Juan, Permian, Hugoton and South Alabama basins and in the Gulf of Mexico. During 2009, our equity interest in Four Star’s daily equivalent natural gas production averaged approximately 72 MMcfe/d.

International

Brazil. Our Brazilian operations cover approximately 139,000 net acres in three blocks and nine development areas in the Camamu, Espirito Santo and Potiguar basins located offshore Brazil. During 2009, we invested $155 million on capital projects in Brazil and production averaged 12 MMcfe/d. Our operations in each basin are described below:

	•		Camamu Basin. We own a 100 percent working interest in two development areas, the Camarao and Pinauna Fields. In Pinauna, we are continuing the process of obtaining regulatory and environmental approvals that are required to enter the next phase of development. The timing of the Pinauna Field development will be dependent on the receipt of all required regulatory approvals.

			In 2009, we relinquished our interest in the BM-CAL-5 block, operated by Petrobras, but retained an 18 percent working interest in a development area around an exploratory well drilled on the block in 2008. We continue to search for viable commercial options to develop the resources found by the exploratory well. In addition, we continue to own a 20 percent interest in two additional blocks in the Camamu Basin, CAL-M-312 and CAL-M-372, which are located east of and contiguous to the BM-CAL-5 block. We will be further evaluating these two blocks over the next several years. In 2009, we also relinquished our interest in the BM-CAL-6 block following unsuccessful exploration activities in 2008 and the completion of our evaluation of the block.

	•		Espirito Santo Basin. We own an approximate 24 percent working interest in the Camarupim Field. The plan of development for the field included drilling four horizontal natural gas wells, all of which had been drilled and tested as of December 31, 2009. We began natural gas and condensate production in October 2009 from the first well. The second well began production in January 2010, while the third well began production in February 2010. We continue to work with Petrobras to connect the fourth well and anticipate bringing the well on production by the end of 2010.

			In 2009, we completed drilling an exploratory well with Petrobras in the ES-5 block in the Espirito Santo Basin in which we own a 35 percent working interest. Hydrocarbons were found in the well and we are now evaluating the results. The exploratory well is located north of the Camarupim Field. In 2010, we plan to participate with Petrobras in spudding another exploratory well in the ES-5 block to evaluate an additional prospect.

	•		Potiguar Basin. We own a 35 percent working interest in the Pescada-Arabaiana Fields. Our production from these fields averaged approximately 9 MMcfe/d in 2009. In late 2009, we executed an agreement with Petrobras to relinquish our interest in two blocks, BM-POT-11 and BM-POT-13.

Egypt. As of December 31, 2009, our Egyptian operations cover approximately 1.4 million net acres in four blocks located primarily onshore in Egypt’s Western Desert. During 2009, we invested $81 million on capital projects in Egypt. In 2009, we completed a transaction to swap a 40 percent working interest in our South Mariut block, which contains approximately 700,000 net acres, for an equal working interest in the Tanta block, which contains approximately 300,000 net acres and is located in the Nile Delta area just to the east of and adjacent to our South Mariut block. We also acquired a 50 percent interest in the South Alamein block, which contains approximately 400,000 net acres and is located just south of our South Mariut block. Finally, we own a 22 percent non-operated working interest in the South Feiran concession, which contains approximately 10,000 net acres and is located offshore in the Gulf of Suez. In December 2009, we made a decision to no longer evaluate prospects in the South Feiran concession and are planning to relinquish the concession in March 2010.

In 2009, we drilled or participated in drilling five wells, two in the South Mariut block and three in the South Alamein block. The South Mariut wells and one of the South Alamein wells were unsuccessful, but the other two South Alamein wells discovered hydrocarbons. In late 2009, we spud a fourth exploratory well in the South Alamein block.

Natural Gas and Oil Properties

Natural Gas, Oil and Condensate and NGL Reserves and Production

The table below presents information about our estimated proved reserves included in our internal reserve report as of December 31, 2009, based on 12-month average fiscal-year prices, calculated as the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period. The reserve data represents only estimates which are often different from the quantities of natural gas and oil that are ultimately recovered. The risks and uncertainties associated with estimating proved natural gas and oil reserves are discussed further in Item 1A, Risk Factors. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at December 31, 2009.


	Net Proved Reserves												2009
	Natural Gas		Oil/Condensate		NGL		Total						Production
	(MMcf)		(MBbls)		(MBbls)		(MMcfe)			(Percent)			(MMcfe)
Reserves and Production by Division
Consolidated:
Proved
U.S.
Central		1,009,030		1,167		—		1,016,031			40	%		93,785
Western		652,349		52,822		—		969,281			38	%		56,341
Gulf Coast		390,145		6,860		304		433,124			17	%		97,880

Total		2,051,524		60,849		304		2,418,436			95	%		248,006
Brazil		105,053		4,196		—		130,232			5	%		4,426

Total Consolidated		2,156,577		65,045		304		2,548,668			100	%		252,432

Unconsolidated Affiliate⁽¹⁾		158,023		1,907		5,264		201,049			100	%		26,142

Total Combined		2,314,600		66,952		5,568		2,749,717			100	%		278,574


Reserves by Classification
Consolidated:
Proved Developed
U.S.		1,441,620		26,588		304		1,602,966			63	%
Brazil		90,715		3,212		—		109,990			4	%

Total		1,532,335		29,800		304		1,712,956			67	%

Proved Undeveloped
U.S.		609,904		34,261		—		815,470			32	%
Brazil		14,338		984		—		20,242			1	%

Total		624,242		35,245		—		835,712			33	%

Total Consolidated		2,156,577		65,045		304		2,548,668	⁽²⁾		100	%


Unconsolidated Affiliate⁽¹⁾
Proved Developed		135,245		1,860		4,295		172,175			86	%
Proved Undeveloped		22,778		47		969		28,874			14	%

Unconsolidated Affiliate⁽¹⁾		158,023		1,907		5,264		201,049			100	%

Total Combined		2,314,600		66,952		5,568		2,749,717			100	%


⁽¹⁾		Amounts represent our approximate 49 percent equity interest in Four Star.

⁽²⁾		Includes 1,357 Bcfe of proved developed producing reserves representing 53 percent of consolidated proved reserves and 356 Bcfe of proved developed non-producing reserves representing 14 percent of consolidated proved reserves at December 31, 2009.

Our consolidated reserves in the table above are consistent with estimates of reserves filed with other federal agencies except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.

The table below presents proved reserves as reported and sensitivities related to our estimated proved reserves based on differing price scenarios as of December 31, 2009.


	Net Proved Reserves
	(MMcfe)
As Reported
Consolidated		2,548,668
Unconsolidated Affiliate		201,049

Total Combined		2,749,717


Scenario 1
Consolidated		2,776,166
Unconsolidated Affiliate		220,899

Total Combined		2,997,065

Scenario 2
Consolidated		2,638,406
Unconsolidated Affiliate		208,498

Total Combined		2,846,904

Scenario 3
Consolidated		2,469,363
Unconsolidated Affiliate		196,085

Total Combined		2,665,448

Scenario 1 — The amounts represent our consolidated and unconsolidated proved reserves assuming spot prices at December 31, 2009 of $5.79 per MMBtu of natural gas and $79.36 per barrel of oil rather than the first day 12-month average U.S. price of $3.87 per MMBtu of natural gas and $61.18 per barrel of oil.

Scenario 2 — The amounts represent our consolidated and unconsolidated proved reserves assuming prices were 10 percent higher than the first day 12-month average U.S. prices we used to determine proved reserves at December 31, 2009.

Scenario 3 — The amounts represent our consolidated and unconsolidated proved reserves assuming prices were 10 percent lower than the first day 12-month average U.S. prices we used to determine proved reserves at December 31, 2009.

On December 31, 2009, we adopted the provisions of the Securities and Exchange Commission’s (SEC’s) final rule on Modernization of Oil and Gas Reporting (Final Rule). Among other things, the Final Rule revised the definition of proved reserves and required us to use a first day 12-month average price to estimate proved reserves rather than a period end spot price as required in prior periods. The adoption of the Final Rule resulted in lower natural gas and oil prices used to estimate our proved reserves at December 31, 2009 than would have been required under the previous rules. Had we used the spot price rather than the first day 12-month average price, our consolidated proved reserves would have been approximately 227 Bcfe higher than our reported proved reserves at December 31, 2009. Other than the first day 12-month average price change, the remaining provisions of the Final Rule had minimal impact on the Company’s proved reserves. For a further discussion of the impact of the Final Rule on the Company’s financial information, see Supplemental Natural Gas and Oil Operations.

Our primary internal technical person in charge of overseeing our reserves estimates, including the reserves estimate we prepare for Four Star, our unconsolidated affiliate, has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers. He is currently responsible for reserve reporting, strategy development, technical excellence and land administration. He has over 22 years of industry experience in various domestic and international engineering and management roles. For a discussion of the internal controls over our proved reserves estimation process, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Estimates.

Ryder Scott Company, L.P. (Ryder Scott) conducted an audit of the estimates of the proved reserves prepared by us as of December 31, 2009. In connection with its audit, Ryder Scott reviewed 87 percent of the properties associated with our total proved reserves on a natural gas equivalent basis, representing 90 percent of the total discounted future net cash flows of these proved reserves. Ryder Scott also conducted an audit of the estimates we prepared of the proved reserves of Four Star as of December 31, 2009. In connection with the audit of these proved reserves, Ryder Scott reviewed 83 percent of the properties associated with Four Star’s total proved reserves on a natural gas equivalent basis, representing 85 percent of the total discounted future net cash flows. Based on our data, technical processes and interpretations and procedures and methodologies utilized by us in determining our proved reserves, we believe our reported proved reserve amounts are reasonable. Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

The technical person primarily responsible for overseeing our reserves audit by Ryder Scott has a B.S. degree in mechanical engineering. He is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers and has over 18 years of reservoir engineering experience. His technical expertise is in the area of economic evaluations, reserves management systems, probabilistic modeling, pressure transient analysis, reservoir surveillance, production optimization, field operations, Enhanced Oil Recovery certification, computer application development and database management.

In general, the volume of production from natural gas and oil properties declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties with proved reserves, or both, our proved reserves will decline as they are produced. Recovery of proved undeveloped (PUD) reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of PUD reserves and proved non-producing reserves are inherently subject to greater uncertainties than estimates of proved producing reserves. For further discussion of our reserves, see Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.

We assess our PUD reserves on a quarterly basis. At December 31, 2009, we had 836 Bcfe of consolidated PUD reserves representing an increase of 230 Bcfe of PUD reserves compared to December 31, 2008. During 2009, we added 339 Bcfe of PUD reserves primarily due to our drilling activities in the Haynesville Shale and Holly/Kingston areas in our Central division and the Altamont Field in our Western division. In addition, we added 37 Bcfe of PUD reserves with the acquisition of natural gas and oil properties in the Altamont-Bluebell-Cedar Rim Field in Utah, also in our Western division. We had negative revisions of 73 Bcfe of PUD reserves, of which 33 Bcfe related to reserves that are not included in our current five-year development plan.

During 2009, we spent $186 million and converted approximately 11 percent or 69 Bcfe of our prior year-end PUD reserves to proved developed reserves. In our December 31, 2009 reserve report, the amounts estimated to be spent in 2010, 2011 and 2012 to develop our consolidated worldwide proved undeveloped reserves are $316 million, $290 million and $223 million. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and product prices.

Of the 836 Bcfe of PUD reserves at December 31, 2009, 71 Bcfe has remained undeveloped for five years or more, primarily in our Central division in major areas of very active drilling, including the Arklatex, Black Warrior and Raton basins. In these areas, we have ongoing drilling activities and a historical record of completing development of comparable long-term projects. Our properties in these major drilling areas are included in our current five-year development plan.

Acreage and Wells

The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2009, (ii) our interest in natural gas and oil wells at December 31, 2009 and (iii) our exploratory and development wells drilled during the years 2007 through 2009. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.


	Developed				Undeveloped				Total
	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾
Acreage
United States
Central		393,966		269,850		522,493		388,987		916,459		658,837
Western		405,145		319,967		975,040		760,674		1,380,185		1,080,641
Gulf Coast		345,952		196,523		462,289		358,195		808,241		554,718

Total United States		1,145,063		786,340		1,959,822		1,507,856		3,104,885		2,294,196
Brazil		47,377		14,492		494,346		124,605		541,723		139,097
Egypt		—		—		2,841,111		1,444,933		2,841,111		1,444,933

Worldwide Total		1,192,440		800,832		5,295,279		3,077,394		6,487,719		3,878,226


⁽¹⁾		Gross interest reflects the total acreage we participate in regardless of our ownership interest in the acreage.

⁽²⁾		Net interest is the aggregate of the fractional working interests that we have in the gross acreage.

In the United States, our net developed acreage is concentrated primarily in Utah (18 percent), New Mexico (16 percent), Texas (14 percent), Louisiana (10 percent), Oklahoma (9 percent) and Alabama (9 percent). Our net undeveloped acreage is concentrated primarily in New Mexico (30 percent), Indiana (13 percent), the Gulf of Mexico (11 percent), Texas (11 percent), Wyoming (8 percent), and Colorado (7 percent). Approximately 9 percent, 10 percent and 6 percent of our total United States net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2010, 2011 and 2012, respectively. Approximately 17 percent of our total Brazilian net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2010. Approximately 29 percent and 7 percent of our total Egyptian net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2010 and 2012, respectively. We employ various techniques to manage the expiration of leases, including extending lease terms, drilling the acreage ourselves, or by entering into farm-out agreements with other operators.


													Wells Being Drilled at
	Natural Gas				Oil				Total				December 31, 2009
	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾⁽³⁾		Gross⁽¹⁾		Net⁽²⁾
Productive Wells
United States
Central		3,597		2,578		10		6		3,607		2,584		13		10
Western		1,397		953		560		372		1,957		1,325		4		3
Gulf Coast		1,428		1,055		24		21		1,452		1,076		2		2

Total		6,422		4,586		594		399		7,016		4,985		19		15
Brazil		9		2		5		2		14		4		2		1
Egypt		—		—		—		—		—		—		3		2

Worldwide Total		6,431		4,588		599		401		7,030		4,989		24		18


	Net Exploratory⁽²⁾						Net Development⁽²⁾
	2009		2008		2007		2009		2008		2007
Wells Drilled
United States
Productive		61		163		214		69		278		238
Dry		2		2		12		2		7		1

Total		63		165		226		71		285		239

Brazil
Productive		—		—		3		1		—		—
Dry		—		—		—		—		—		—

Total		—		—		3		1		—		—

Egypt
Productive		—		—		—		—		—		—
Dry		2		—		—		—		—		—

Total		2		—		—		—		—		—

Worldwide
Productive		61		163		217		70		278		238
Dry		4		2		12		2		7		1

Total		65		165		229		72		285		239


⁽¹⁾		Gross interest reflects the total wells we participated in, regardless of our ownership interest.

⁽²⁾		Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.

⁽³⁾		At December 31, 2009, we operated 4,589 of the 4,989 net productive wells.

The drilling performance above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of natural gas and oil that may ultimately be recovered.

Net Production, Sales Prices, Transportation and Production Costs

The following table details our net production volumes, average sales prices received, average transportation costs and average production costs (including production taxes) associated with the sale of natural gas and oil for each of the three years ended December 31:


	2009		2008		2007
Volumes:
Consolidated Net Production Volumes
United States
Natural gas (MMcf)		214,718		229,518		238,021
Oil, condensate and NGL (MBbls)		5,548		6,371		7,664
Total (MMcfe)		248,006		267,745		284,005
Brazil
Natural gas (MMcf)		3,826		3,185		4,295
Oil, condensate and NGL (MBbls)		100		124		157
Total (MMcfe)		4,426		3,928		5,237
Consolidated — Worldwide
Natural gas (MMcf)		218,544		232,703		242,316
Oil, condensate and NGL (MBbls)		5,648		6,495		7,821
Total (MMcfe)		252,432		271,673		289,242
Total (MMcfe/d)		691		742		792
Unconsolidated Affiliate Volumes⁽¹⁾
Natural gas (MMcf)		19,557		20,576		19,380
Oil, condensate and NGL (MBbls)		1,097		1,054		1,015
Total equivalent volumes (MMcfe)		26,139		26,899		25,470
MMcfe/d		72		74		70
Total Combined Volumes⁽¹⁾
Natural gas (MMcf)		238,101		253,279		261,696
Oil, condensate and NGL (MBbls)		6,745		7,549		8,836
Total equivalent volumes (MMcfe)		278,571		298,572		314,712
MMcfe/d		763		816		862


	2009		2008		2007
Consolidated Prices and Costs per Unit:
Natural Gas Average Realized Sales Price ($/Mcf)
United States
Physical sales	$	3.78	$	8.51	$	6.60
Including financial derivative settlements	$	7.68	$	8.26	$	7.26
Brazil
Physical sales	$	4.84	$	2.60	$	2.61
Including financial derivative settlements	$	4.22	$	2.60	$	2.61
Worldwide
Physical sales	$	3.80	$	8.43	$	6.53
Including financial derivative settlements⁽²⁾	$	7.62	$	8.18	$	7.18
Oil, Condensate and NGL Average Realized Sales Price ($/Bbl)
United States
Physical sales	$	47.03	$	82.96	$	63.56
Including financial derivative settlements	$	78.70	$	77.42	$	63.56
Brazil
Physical sales	$	60.88	$	96.21	$	70.86
Including financial derivative settlements	$	60.88	$	96.21	$	(4.41	)
Worldwide
Physical sales	$	47.27	$	83.21	$	63.71
Including financial derivative settlements⁽²⁾	$	78.38	$	77.78	$	62.19
Average Transportation Costs
United States
Natural gas ($/Mcf)	$	0.28	$	0.32	$	0.27
Oil, condensate and NGL ($/Bbl)	$	0.78	$	0.98	$	0.83
Worldwide
Natural gas ($/Mcf)	$	0.28	$	0.31	$	0.27
Oil, condensate and NGL ($/Bbl)	$	0.77	$	0.96	$	0.81
Average Production Costs ($/Mcfe)
United States
Lease operating expenses	$	0.70	$	0.89	$	0.86
Production taxes		0.21		0.44		0.31

Total production costs	$	0.91	$	1.33	$	1.17

Brazil
Lease operating expenses⁽³⁾	$	5.19	$	1.64	$	1.63
Production taxes		0.68		0.58		0.51

Total production costs	$	5.87	$	2.22	$	2.14

Worldwide
Lease operating expenses⁽³⁾	$	0.78	$	0.90	$	0.88
Production taxes		0.22		0.44		0.31

Total production costs	$	1.00	$	1.34	$	1.19


⁽¹⁾		Represents our approximate 49 percent equity interest in the volumes of Four Star.

⁽²⁾		Premiums related to natural gas derivatives settled during the year ended December 31, 2008 were $21 million. Had we included these premiums in our natural gas average realized prices in 2008, our realized price, including financial derivative settlements, would have decreased by $0.09/Mcf for the year ended December 31, 2008. We had no premiums related to natural gas derivatives settled during the years ended December 31, 2009 and 2007, or related to oil derivatives settled during the years ended December 31, 2009, 2008 and 2007.

⁽³⁾		Includes approximately $14 million of start-up costs in Camarupim Field in 2009 or $3.08 per Mcfe for Brazil and $0.05 per Mcfe worldwide.

Acquisition, Development and Exploration Expenditures

The following table details information regarding the costs incurred in our acquisition, development and exploration activities for each of the three years ended December 31:


	2009		2008		2007
			(In millions)
United States
Acquisition Costs:
Proved	$	87	$	51	$	964
Unproved		89		74		262
Development Costs		324		938		735
Exploration Costs:
Delay rentals		5		6		6
Seismic acquisition and reprocessing		27		24		19
Drilling		323		408		373
Asset Retirement Obligations		36		19		38

Total full cost pool expenditures		891		1,520		2,397
Non-full cost pool expenditures		34		30		13

Total costs incurred	$	925	$	1,550	$	2,410

Acquisition of additional investment in Four Star	$	—	$	—	$	27

Brazil and Egypt⁽¹⁾
Acquisition Costs:
Proved	$	—	$	—	$	—
Unproved		51		1		5
Development Costs		118		93		26
Exploration Costs:
Seismic acquisition and reprocessing		3		13		6
Drilling		64		91		193
Asset Retirement Obligations		6		—		7

Total full cost pool expenditures		242		198		237
Non-full cost pool expenditures		4		13		1

Total costs incurred	$	246	$	211	$	238

Worldwide⁽¹⁾
Acquisition Costs:
Proved	$	87	$	51	$	964
Unproved		140		75		267
Development Costs		442		1,031		761
Exploration Costs:
Delay rentals		5		6		6
Seismic acquisition and reprocessing		30		37		25
Drilling		387		499		566
Asset Retirement Obligations		42		19		45

Total full cost pool expenditures		1,133		1,718		2,634
Non-full cost pool expenditures		38		43		14

Total costs incurred	$	1,171	$	1,761	$	2,648

Acquisition of additional investment in Four Star	$	—	$	—	$	27


⁽¹⁾		Costs incurred for Egypt were $81 million, $27 million and $10 million for the years ended December 31, 2009, 2008 and 2007.

Markets and Competition

We primarily sell our domestic natural gas and oil to third parties through our Marketing segment at spot market prices, subject to customary adjustments. We sell our NGL at market prices under monthly or long-term contracts, subject to customary adjustments. In Brazil, we sell the majority of our natural gas and oil, under long-term contracts, to Petrobras, Brazil’s state-owned energy company. These long-term contracts include a gas sales agreement and a condensate sales agreement. The gas sales agreement provides for a price that adjusts quarterly based on a basket of fuel oil prices, while the condensate sales agreement provides for a price that adjusts monthly based on a Brent crude price less a fixed differential that will adjust annually. We enter into derivative contracts on our natural gas and oil production to stabilize our cash flows, reduce the risk and financial impact of downward commodity price movements and protect the economic assumptions associated with our capital investment programs. For a further discussion of these contracts, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The exploration and production business is highly competitive in the search for and acquisition of additional natural gas and oil reserves and in the sale of natural gas, oil and NGL. Our competitors include major and intermediate sized natural gas and oil companies, independent natural gas and oil operators and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include price and contract terms, our ability to access drilling and other equipment and our ability to hire and retain skilled personnel on a timely and cost effective basis. Ultimately, our future success in this business will be dependent on our ability to find or acquire additional reserves at costs that yield acceptable returns on the capital invested.

Regulatory Environment. Our natural gas and oil exploration and production activities are regulated at the federal, state and local levels, in the United States, Brazil and Egypt. These regulations include, but are not limited to, those governing the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners. We are also subject to governmental safety regulations in the jurisdictions in which we operate.

Our domestic operations under federal natural gas and oil leases are regulated by the statutes and regulations of the U.S. Department of the Interior that currently impose liability upon lessees for the cost of environmental impacts resulting from their operations. Royalty obligations on all federal leases are regulated by the Minerals Management Service, which has promulgated valuation guidelines for the payment of royalties by producers. Our exploration and production operations in Brazil and Egypt are subject to environmental regulations administered by those governments, which include political subdivisions in those countries. These domestic and international laws and regulations affect the construction and operation of facilities, water disposal rights, drilling operations, production or the delay or prevention of future offshore lease sales. In addition, we maintain insurance to limit exposure to sudden and accidental pollution liability exposures.

Marketing Segment

Our Marketing segment’s primary focus is to market our Exploration and Production segment’s natural gas and oil production, and to manage El Paso’s overall price risk. In addition, we continue to manage and liquidate remaining legacy contracts which were primarily entered into prior to the deterioration of the energy trading environment in 2002. As of December 31, 2009, we managed the following types of contracts:

Natural gas transportation-related contracts. Our transportation contracts give us the right to transport natural gas using pipeline capacity for a fixed reservation charge plus variable transportation costs. Our ability to utilize our transportation capacity under these contracts is dependent on several factors, including the difference in natural gas prices at receipt and delivery locations along the pipeline system, the amount of working capital needed to use this capacity and the capacity required to meet our other long-term obligations. The following table details our transportation contracts as of December 31, 2009:


	Affiliated Pipelines⁽¹⁾		Other Pipelines
Daily capacity (MMBtu/d)		514,000		241,000
Expiration	2011 to 2028		2011 to 2026
Receipt points / Delivery points	Various		Various


⁽¹⁾		Primarily consists of contracts with TGP and EPNG.

Legacy natural gas contracts. As of December 31, 2009, we had seven significant physical natural gas contracts with power plants associated with our legacy trading activities, including our Midland Cogeneration Venture (MCV) supply agreement. These contracts obligate us to sell gas to these plants and have various expiration dates ranging from 2011 to 2028, with expected obligations under individual contracts with third parties ranging from 12,550 MMBtu/d to 130,000 MMBtu/d.

Legacy power contracts. As of December 31, 2009, we had three derivative contracts that require us to swap locational differences in power prices between three power plants in the Pennsylvania-New Jersey-Maryland (PJM) eastern region with the PJM west hub. In total, these contracts require us annually to swap locational differences in power prices on approximately 3,700 GWh from 2010 to 2012, 2,400 GWh for 2013 and 1,700 GWh from 2014 to April 2016. Additionally, these contracts require us to provide approximately 1,700 GWh of power per year and approximately 71 GW of installed capacity per year in the PJM power pool through April 2016.

Markets, Competition and Regulatory Environment

Our Marketing segment operates in a highly competitive environment, competing on the basis of price, experience in the marketplace and counterparty credit. Each market served is influenced directly or indirectly by energy market economics. Our primary competitors include major oil and natural gas producers and their affiliates, large domestic and foreign utility companies, large local distribution companies and their affiliates, other interstate and intrastate pipelines and their affiliates, and independent energy marketers and financial institutions. Our marketing activities are subject to the regulations of among others, the FERC and the Commodity Futures Trading Commission.

Power Segment

As of December 31, 2009, our Power segment primarily included the ownership and operation of our remaining investment in a power generation project and a pipeline facility. These facilities are subject to regulation by government agencies and the regulatory structure is subject to change over time, and as a result, we are subject to certain political risks related to the facilities. Each of these assets is further described below:

El Paso

Expiration

Ownership

Gross

Year of Power

Power Project

Area

Interest

Capacity

Power Purchaser

Sales Contracts

Fuel Type

(Percent)

(MW)

Habibullah

Pakistan

136

Pakistan Water and Power

2029

Natural Gas

El Paso Ownership

Average 2009

Pipeline

Interest

Gross KM⁽¹⁾

Design Capacity⁽¹⁾

Throughput⁽¹⁾

(Percent)

(MMcf/d)

(BBtu/d)

Bolivia to Brazil

3,150

1,059

793


⁽¹⁾		Amounts are not adjusted for our ownership percentage.

Environmental

A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 13.

Employees

As of February 22, 2010, we had 4,991 full-time employees, of which 98 employees are subject to collective bargaining arrangements.

Executive Officers of the Registrant

Our executive officers as of February 26, 2010, are listed below.


		Officer
Name	Office	Since		Age
Douglas L. Foshee	Chairman, President and Chief Executive Officer of El Paso		2003		50
John R. Sult	Senior Vice President and Chief Financial Officer of El Paso		2005		50
Brent J. Smolik	Executive Vice President of El Paso and President of El Paso Exploration & Production Company		2006		48
James C. Yardley	Executive Vice President, Pipeline Group		2005		58
D. Mark Leland	Executive Vice President of El Paso and President of Midstream		2005		48
Robert W. Baker	Executive Vice President and General Counsel of El Paso		2002		53
Susan B. Ortenstone	Senior Vice President and Chief Administrative Officer of El Paso		2003		53
James J. Cleary	President of Western Pipeline Group		2005		55
Dane E. Whitehead	Senior Vice President, Strategy and Enterprise Business Development of El Paso		2009		48

Douglas L. Foshee has been Chairman of the Board of Directors of El Paso Corporation since May 2009 and President, Chief Executive Officer and a director of El Paso since September 2003. Prior to joining El Paso, Mr. Foshee served as Executive Vice President and Chief Operating Officer of Halliburton Company having joined that company in 2001 as Executive Vice President and Chief Financial Officer. Several subsidiaries of Halliburton, including DII Industries and Kellogg Brown & Root, commenced prepackaged Chapter 11 proceedings to discharge current and future asbestos and silica personal injury claims in December 2003 and an order confirming a plan of reorganization became final effective December 31, 2004. Prior to assuming his position at Halliburton, Mr. Foshee served as President, Chief Executive Officer and Chairman of the Board of Nuevo Energy Company and Chief Executive Officer and Chief Operating Officer of Torch Energy Advisors Inc. Mr. Foshee presently serves as a director of Cameron International Corporation and is a trustee of AIG Credit Facility Trust. Mr. Foshee serves as Chairman of the Federal Reserve Bank of Dallas, Houston Branch. Mr. Foshee also serves on the Board of Trustees of Rice University and serves as a member of the Council of Overseers for the Jesse H. Jones Graduate School of Management. He is a member of various other civic and community organizations. Mr. Foshee also serves on the board of directors of El Paso Pipeline GP Company, L.L.C., general partner of El Paso Pipeline Partners, L.P.

John R. Sult has been Senior Vice President and Chief Financial Officer of El Paso since November 2009. Mr. Sult previously served as Senior Vice President and Controller of El Paso from November 2005 to November 2009. He has served as Senior Vice President and Chief Financial Officer of El Paso Pipeline GP Company, L.L.C. since November 2009 and Senior Vice President, Chief Financial Officer and Controller from August 2007 to November 2009. Mr. Sult served as Senior Vice President, Chief Financial Officer and Controller of El Paso’s Pipeline Group from November 2005 to November 2009. Mr. Sult was Vice President and Controller for Halliburton Energy Services from August 2004 to October 2005. Mr. Sult also serves on the board of directors of El Paso Pipeline GP Company, L.L.C., general partner of El Paso Pipeline Partners, L.P.

Brent J. Smolik has been Executive Vice President of El Paso and President of El Paso Exploration & Production Company since November 2006. Mr. Smolik was President of ConocoPhillips Canada from April 2006 to October 2006. Prior to the Burlington Resources merger with ConocoPhillips, he was President of Burlington Resources Canada from September 2004 to March 2006. From 1990 to 2004, Mr. Smolik worked in various engineering and asset management capacities for Burlington Resources Inc., including the Chief Engineering role from 2000 to 2004. He was a member of the Burlington Executive Committee from 2001 to 2006. Mr. Smolik also serves on the Boards of the American Exploration and Production Council, America’s Natural Gas Alliance and the Independent Petroleum Association of America.

James C. Yardley has been Executive Vice President of El Paso with responsibility for the regulated pipeline business unit since August 2006. He has served as President of Tennessee Gas Pipeline Company since February 2007 and Chairman of the Board since August 2006. Mr. Yardley has been Chairman of El Paso Natural Gas Company since August of 2006 and has served as President of Southern Natural Gas Company since May 1998. Mr. Yardley has been a member of the Management Committees of both Colorado Interstate Gas Company and Southern Natural Gas Company since their conversion to general partnerships in November 2007. Mr. Yardley is currently a member of the board of directors of Scorpion Offshore Ltd. He also serves on the Board of Interstate Natural Gas Association of America and previously served as its Chairman. Mr. Yardley also serves as Director, President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C., general partner of El Paso Pipeline Partners, L.P.

D. Mark Leland has been Executive Vice President of El Paso and President of El Paso’s Midstream business unit since October 2009. Mr. Leland previously served as Executive Vice President and Chief Financial Officer of El Paso from August 2005 to November 2009. He served as Executive Vice President of El Paso Exploration & Production Company from January 2004 to August 2005, and as Chief Financial Officer and a director from April 2004 to August 2005. Mr. Leland served as Senior Vice President and Chief Operating Officer of GulfTerra Energy Partners, L.P. and its general partner from January 2003 to December 2003, as Senior Vice President and Controller from July 2000 to January 2003, and as Vice President from August 1998 to July 2000. Mr. Leland serves on the board of directors of El Paso Pipeline GP Company, L.L.C., general partner of El Paso Pipeline Partners, L.P.

Robert W. Baker has been Executive Vice President and General Counsel of El Paso since January 2004. From February 2003 to December 2003, he served as Executive Vice President of El Paso and President of El Paso Merchant Energy. Mr. Baker previously served as Senior Vice President and Deputy General Counsel of El Paso from January 2002 to February 2003. Mr. Baker serves as Executive Vice President and General Counsel of El Paso Pipeline GP Company, L.L.C., general partner of El Paso Pipeline Partners, L.P.

Susan B. Ortenstone has been Chief Administrative Officer of El Paso since October 2009 and Senior Vice President since October 2003. Ms. Ortenstone was Chief Executive Officer for Epic Energy Pty Ltd. from January 2001 to June 2003. She served as Vice President of El Paso Gas Services Company and President of El Paso Energy Communications from December 1997 to December 2000. Ms. Ortenstone serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., general partner of El Paso Pipeline Partners, L.P.

James J. Cleary has been a director and President of El Paso Natural Gas Company since January 2004. Mr. Cleary has been a member of the Management Committee of Colorado Interstate Gas Company since November 2007 and President since January 2004. He previously served as Chairman of the Board of both El Paso Natural Gas Company and Colorado Interstate Gas Company from May 2005 to August 2006. From January 2001 to December 2003, he served as President of ANR Pipeline Company. Mr. Cleary serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., general partner of El Paso Pipeline Partners, L.P.

Dane E. Whitehead has been Senior Vice President of Strategy and Enterprise Business Development of El Paso since October 2009. Mr. Whitehead previously served as Senior Vice President and Chief Financial Officer for El Paso Exploration and Production Company from May 2006 to October 2009. From October 1993 to April 2006, Mr. Whitehead held various positions at Burlington Resources Inc. including serving as Vice President, Controller and Chief Accounting Officer.

Available Information

Our website is http://www.elpaso.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after these reports are filed with the SEC. Information about each of our Board members, as well as each of our Board’s standing committee charters, our Corporate Governance Guidelines and our Code of Business Conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.

ITEM 1A. RISK FACTORS

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

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

Our operations are subject to the inherent risks normally associated with those operations, including pipeline failures, explosions, pollution, release of toxic substances, fires, adverse weather conditions (such as hurricanes and 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 hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas could have a negative impact upon our operations in the future, particularly with regard to the facilities of our Pipeline and Exploration and Production segments that are located in or near the Gulf of Mexico and other coastal regions.

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 and self-insurance levels, 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 and self-insurance levels, 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 success of our pipeline business depends, in part, on factors beyond our control.

The results of our pipeline business are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volumes of natural gas we are able to transport and store depend on the actions of third parties and are beyond our control. Such actions include 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 systems. 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 and gas shale supplies;

	•		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;

	•		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 and/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.

Certain of our pipeline systems’ transportation services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.

It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated “recourse rate” for that service, and that contract must be filed and accepted by FERC. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation, cost of capital, taxes or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers.

The revenues of our pipeline businesses are generated under contracts that must be renegotiated periodically.

Substantially all of our pipeline 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 Conditions 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 them to negotiate short-term contracts or turn back their capacity when their contracts expire.

Fluctuations in energy commodity prices could adversely affect our pipeline businesses.

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

Pricing volatility may impact the value of under or over recoveries of retained natural gas, imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters 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 and oil 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 sale or transportation of natural gas and NGL;

	•		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 price, production and export controls.

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

We may expand the capacity of our existing pipeline, storage or LNG facilities 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;

	•		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 may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

Our pipeline systems depend on certain key customers and producers for a significant portion of their revenues. The loss of any of these key customers could result in a decline in our systems’ revenues.

Our systems rely on a limited number of customers for a significant portion of our systems’ revenues. For the year ended December 31, 2009, the four largest natural gas transportation customers for each of TGP, CIG, EPNG and SNG accounted for approximately 22 percent, 60 percent, 52 percent and 44 percent of their respective operating revenues. The loss of all or even a portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on our financial condition and results of operations.

We are exposed to the credit risk of our pipeline 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 pipeline 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.

We are exposed to the credit and performance risk of our key contractors and suppliers.

As an owner of large energy infrastructure, including significant capital expansion programs, we rely on contractors for certain construction and drilling operations and we rely on suppliers for key materials and supplies, including steel mills and pipe manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us. This could result in delays or defaults in performing such contractual obligations, which could adversely impact our financial condition and results of operations.

Natural gas and oil prices are volatile. A substantial decrease in natural gas and oil prices could adversely affect the financial results of our exploration and production business.

Our future financial condition, revenues, results of operations, cash flows and future rate of growth of our exploration and production business depend primarily upon the prices we receive for our natural gas and oil production. Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current world geopolitical conditions. The prices for natural gas and oil are subject to a variety of additional factors that are beyond our control.

Further, because the majority of our proved reserves at December 31, 2009 were natural gas reserves, we are substantially more sensitive to changes in natural gas prices than we are to changes in oil prices. Declines in natural gas and oil prices would not only reduce revenue, but could reduce the amount of natural gas and oil that we can produce economically and, as a result, could adversely affect the financial results of our exploration and production business. A decline in the first day 12-month average natural gas and oil prices could result in additional downward revisions of our reserves and additional full cost ceiling test write-downs of the carrying value of our natural gas and oil properties, which could be substantial, and would negatively impact our net income and stockholders’ equity.

The success of our exploration and production business is dependent, in part, on the following factors.

The performance of our exploration and production business is dependent upon a number of factors that we cannot control, including:

	•		the results of future drilling activity;

	•		the availability and future costs of rigs, equipment and labor to support drilling activity and production operations;

	•		our ability to identify and precisely locate prospective geologic structures and to drill and successfully complete wells in those structures in a timely manner;

	•		our ability to expand our leased land positions in desirable areas, which often are subject to intensely competitive conditions from other companies;

	•		our ability to successfully integrate acquisitions;

	•		adverse changes in future tax policies, rates, and drilling or production incentives by state, federal, or foreign governments;

	•		increased federal or state regulations, including environmental regulations, that limit or restrict the ability to drill natural gas or oil wells, limit or restrict the use of hydraulic fracturing in our drilling operations, limit or restrict our access to water rights (including disposal of water and other fluids in our operations), reduce operational flexibility, or increase capital and operating costs;

	•		governmental action affecting the profitability of our exploration and production activities, such as increased royalty rates payable on oil and gas leases, the imposition of additional taxes on such activities or the modification or withdrawal of tax incentives in favor of exploration and development activity;

	•		our ability to receive certain government approvals or permits on a timely basis on terms acceptable to us;

	•		our lack of control over jointly owned properties and properties operated by others;

	•		declines in production volumes, including those from the Gulf of Mexico; and

	•		continued access to sufficient capital at reasonable rates to fund drilling programs to develop and replace a reserve base with rapid depletion characteristics especially in periods of prolonged economic decline when we may be unable to access the capital markets.

Our natural gas and oil drilling and producing operations involve many risks and may not be profitable.

Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties and the drilling of natural gas and oil wells, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of natural gas, oil, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks. Additionally, our offshore operations may encounter usual marine perils, including hurricanes and other adverse weather conditions, damage from collisions with vessels, governmental regulations and interruption or termination of drilling rights by governmental authorities based on environmental and other considerations. Each of these risks could result in damage to property, injuries to people or the shut in of existing production as damaged energy infrastructure is repaired or replaced.

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 and self-insurance levels, limits on our maximum recovery and do not cover all risks, including potential environmental fines and penalties. In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our future results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

Our drilling operations are also subject to the risk that we will not encounter commercially productive reservoirs. New wells drilled by us may not be productive, or we may not recover all or any portion of our investment in those wells. Drilling for natural gas and oil can be unprofitable, not only because of dry holes but wells that are productive may not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs.

Estimating our reserves, production and future net cash flow is inherently imprecise.

All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond our control such as reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate.

Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. Estimating quantities of proved natural gas and oil reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical, and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which it is based, and on engineering and geological interpretations and judgment. It also requires making estimates based upon economic factors, such as natural gas and oil prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effect of governmental regulation. In addition, due to a lack of substantial, if any, production data, there are greater uncertainties in estimating proved undeveloped reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, our reserve estimates are inherently imprecise. We also use a ten percent discount factor for estimating the value of our future net cash flows from reserves and a 12-month average price (calculated as the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period) as prescribed by the SEC. This discount factor may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our exploration and production business or the natural gas and oil industry, in general, are subject. Additionally, this first day 12-month average price will not generally represent the market prices for natural gas and oil over time. Any significant variations from the interpretations or assumptions used in our estimates, changes in commodity prices or changes of conditions could cause the estimated quantities and net present value of our reserves to differ materially. For estimated quantities of proved undeveloped reserves, proved developed non-producing reserves and proved developed reserves as of December 31, 2009, see Item 1, Business, Natural Gas and Oil Properties.

Our reserve data represents an estimate. You should not assume that the present values referred to in this report represent the current market value of our estimated natural gas and oil reserves. The timing of the production and the expenses related to the development and production of natural gas and oil properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. Changes in the present value of these reserves could cause a write-down in the carrying value of our natural gas and oil properties, which could be substantial, and would negatively affect our net income and stockholders’ equity.

A portion of our estimated proved reserves are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. In addition, as the portion of our proved reserve base that consists of unconventional sources increases, the costs of finding, developing and producing those reserves may require capital expenditures that are greater than more conventional sources. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change.

The success of our exploration and production business depends upon our ability to replace reserves that we produce.

Unless we successfully replace the reserves that we produce, our reserves will decline which will eventually result in a decrease in natural gas and oil production and lower revenues and cash flows from operations. We historically have replaced reserves through both drilling and acquisitions. The business of exploring for, developing or acquiring reserves requires substantial capital expenditures. Our operations require continued access to sufficient capital to fund drilling programs to develop and replace a reserve base with rapid depletion characteristics. If we do not continue to make significant capital expenditures, if our capital resources become limited, or if our exploration, development and acquisition activities are unsuccessful, we may not be able to replace the reserves that we produce, which would negatively affect our future revenues, cash flows and results of operations.

We face competition from third parties to acquire and develop natural gas and oil reserves.

The natural gas and oil business is highly competitive in the search for and acquisition of reserves. Our competitors include the major and independent natural gas and oil companies, individual producers, gas marketers and major pipeline companies some of which have financial and other resources that are substantially greater than those available to us, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. In order to expand our leased land positions in intensively competitive and desirable areas, we must identify and precisely locate prospective geologic structures, identify and review any potential risks and uncertainties in these areas, and drill and successfully complete wells in a timely manner. Our future success and profitability in the production business may be negatively impacted if we are unable to identify these risks or uncertainties and find or acquire additional reserves at costs that allow us to remain competitive.

Our use of derivative financial instruments could result in financial losses.

Some of our subsidiaries use futures, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions. To the extent we have positions that are not designated as accounting hedges or do not qualify as hedges, changes in commodity prices, interest rates, counterparty non-performance risks, volatility, correlation factors and the liquidity of the market could cause our revenues and net income to be volatile.

We could incur financial losses in the future as a result of volatility in the market values of the energy commodities we trade, or if one of our counterparties fails to perform under a contract. The valuation of these financial instruments involves estimates. Changes in the assumptions underlying these estimates can occur, changing our valuation of these instruments and potentially resulting in financial losses. To the extent we enter into derivative contracts to manage our commodity price exposure and interest rate exposure, we forego the benefits we could otherwise experience if commodity prices or interest rates were to change favorably. To the extent that we enter into fixed price derivative contracts, we could experience losses and be required to pay cash to the extent that commodity prices or interest rates were to increase above the fixed price. The use of derivatives, to the extent they require collateral posting with our counterparties, could impact our working capital (current assets less current liabilities) and liquidity when commodity prices or interest rates change. In this regard, there is proposed federal legislation that would require commodity derivative transactions that are currently traded “over-the-counter” to be traded over regulated exchanges that could require collateral posting for many of our derivative transactions that do not currently have collateral posting requirements and therefore would negatively impact our working capital requirements. For additional information concerning our derivative financial instruments, see Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Part II, Item 8, Financial Statements and Supplementary Data, Note 8.

Our foreign operations and investments involve special risks.

Our activities in areas outside the United States, including power, pipeline and exploration and production projects in Brazil, exploration and production projects in Egypt, pipeline projects in Mexico and a power project in Pakistan, are subject to the risks inherent in foreign operations. As a general rule, we have elected not to carry political risk insurance against these sorts of risks which include:

	•		loss of revenue, property and equipment as a result of hazards such as wars or insurrection;

	•		the effects of currency fluctuations and exchange controls, such as devaluation of foreign currencies and other economic problems;

	•		changes in laws, regulations and policies of foreign governments, including those associated with changes in the governing parties, nationalization, and expropriation; and

	•		protracted delays in securing government consents, permits, licenses, customer authorizations or other regulatory approvals necessary to conduct our operations.

The midstream business may be subject to additional risks associated with fluctuations in energy commodity prices.

The midstream sector generally includes the gathering, transporting, processing, fractionating and storing of natural gas, NGLs and oil. The pricing for each of these hydrocarbon products has been volatile over time. In addition, the relative pricing between these hydrocarbon products has been volatile, which may affect fractionation spreads and the profitability of the business. Changes in prices and relative price levels may impact demand for hydrocarbon products, which in turn may impact production, demand and volumes of product for which we may provide services.

A decrease in demand for NGL products by the petrochemical, refining or heating industries could affect the profitability of our midstream business.

A decrease in demand for NGL products by the petrochemical, refining or heating industries, could adversely affect the profitability of our future midstream business. Various factors could impact the demand for NGL products, including general economic conditions, reduced demand by consumers for the end products made with NGL products, extended periods of ethane rejection, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, availability of NGL processing and transportation capacity, government regulations affecting prices and production levels of natural gas, NGLs or the content of motor fuels.

We will face competition from third parties in our midstream businesses.

As we re-enter the midstream business, we will be competing with third parties to gather, transport, process, fractionate, store or handle hydrocarbons. Although we will attempt to leverage the synergies between our pipeline and exploration and production businesses, most of these third parties will have existing facilities and as a result initially have more scale and personnel than us. Therefore, there can be no assurances on how successful our re-entry into the midstream business will be.

We will face additional reserve and volumetric risk in our midstream business.

Although the revenues in our pipeline business are typically collected in the form of demand or reservation charges and are not dependent upon reserves or throughput levels, many transactions in the midstream business involve additional reserve and throughput risk. For example, natural gas and oil reserves committed to gathering and processing facilities may not be as large as expected, the life of the reserves may not be as long as expected or the producers may elect not to develop such reserves. We also cannot influence or control the production or the speed of development of the third-party natural gas we transport or process. The reserves committed will naturally decline overtime and our ability to attract new reserves in competition with third parties to replace these declining supplies is uncertain. Furthermore, the rate at which production from these reserves declines may be greater than we anticipate. As a result, we may face additional reserve and throughput risk in our midstream business beyond what we typically experience in our pipeline business.

Retained liabilities associated with businesses that we have sold could exceed our estimates and we could experience difficulties in managing these liabilities.

We have sold a significant number of assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets sold, including breaches of warranties, environmental expenditures, asset maintenance, tax, litigation, personal injury claims and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these businesses, including a reduction in historical knowledge of the assets and businesses and in managing the liabilities retained after closing or defending any associated litigation.

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 plans.

Our pipeline and exploration and production businesses require the retention and recruitment of a skilled workforce including engineers and other technical personnel. If we are unable to retain our current employees (many of which are retirement eligible) or recruit new employees of comparable knowledge and experience, our business could be negatively impacted.

Risks Related to Legal and Regulatory Matters

The outcome of governmental investigations could be materially adverse to us.

We are subject to various governmental investigations from time to time, including investigations by the FERC and the U.S. Department of Transportation Office of Pipeline Safety. The results of any investigation could have a material adverse effect on our business, financial condition or results of operation.

The agencies that regulate our pipeline businesses and their customers could affect our profitability.

Our pipeline businesses are regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of 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 our pipelines are permitted to charge their customers for their services and sets authorized rates of return.

Many of our pipelines periodically file to adjust their rates charged to their 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 one or more of our pipeline systems and that a successful complaint against our pipelines’ rates could have an adverse impact on our cash flows and results of operations.

We formed EPB, a master limited partnership, in 2007. The FERC currently allows publicly traded partnerships to include in their cost-of-service an income tax allowance. Any changes to FERC’s treatment of income tax allowances in cost of service and to potential adjustment in a future rate case of our pipelines’ respective equity rates of return that underlie their recourse rates may cause their recourse rates to be set at a level that is different, and in some instances lower than the level otherwise in effect, could negatively impact our investment in EPB.

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 pipelines’ local distribution company customers could impose requirements that could impact demand for our pipelines’ 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. In addition, although we have environmental management systems to manage our compliance obligations, fines and penalties can result 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 processes and systems in place to establish 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, cash flows or financial position. See Item 3, Legal Proceedings and Part II, Item 8, Financial Statements and Supplementary Data, Note 13.

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.

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 and oil. 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 for 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 and oil, 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.

Costs of litigation matters and other contingencies could exceed our estimates.

We are involved in various lawsuits in which we or our subsidiaries have been sued (see Part II, Item 8, Financial Statements and Supplementary Data, Note 13). We also have other contingent liabilities and exposures. In addition, we have significant benefit plan obligations that could be negatively impacted by changes that might arise out of potential health care and pension reform legislation. Although we believe we have established appropriate reserves for these liabilities, we could be required to set aside additional amounts in the future and these amounts could be material.

Risks Related to Our Liquidity

We have significant debt and below investment grade credit ratings, which have impacted and will continue to impact our financial condition, results of operations and liquidity.

We have significant debt, debt service and debt maturity obligations. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 with a stable outlook by Moody’s Investor Service and BB- with a negative outlook by Standard & Poor’s. These ratings have increased our cost of capital and our operating costs. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our leverage, liquidity and credit profile. Any reduction in our credit rating could impact our ability, as well as the ability of El Paso Pipeline Partners and our pipeline subsidiaries, to access the capital markets. These changes could also impact our cost of capital as well as that of our subsidiaries. As a result of the volatility in the financial markets and the capital commitments of our pipeline group, we have been maintaining greater liquidity levels. However, if commodity prices remain at current levels or continue to decline and our access to capital markets is restricted, then such liquidity levels may not be adequate to manage our business and our financial condition and future results of operations could be significantly adversely affected. See Part II, Item 8, Financial Statements and Supplementary Data, Note 12, for a further discussion of our debt.

A breach of the covenants applicable to our debt and other financing obligations could affect our ability to borrow funds and could accelerate our debt and other financing obligations and those of our subsidiaries.

Our debt and other financing obligations contain restrictive covenants, including debt to earnings before interest, income taxes, depreciation and amortization (EBITDA) and fixed charges to EBITDA covenants in our revolving credit agreement, and contain cross default provisions. In light of the volatility in the financial markets and a reduction in access to capital, these covenants may become more restrictive over time. A breach of any of these covenants could preclude us or our subsidiaries from issuing letters of credit, from borrowing under our credit agreements and could accelerate our debt and other financing obligations and those of our subsidiaries. If this were to occur, we might not be able to repay such debt and other financing obligations.

Additionally, some of our credit agreements are collateralized by our equity interests in EPNG and TGP as well as certain natural gas and oil reserves. A breach of the covenants under these agreements could permit the lenders to exercise their rights to foreclose on these collateral interests.

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

We are subject to the risks arising from adverse changes in general global 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 we announced reductions in our capital plan as well as several other actions, including non-core asset sales to address these general economic conditions. Adverse general economic conditions as well as restrictions on the ability of parties to access capital markets could negatively impact our ability to sell assets or obtain partners on certain projects on a timely basis. In addition, such conditions if they persist could negatively impact the amount of proceeds from such sales or joint venture arrangements.

If we experience prolonged periods of recession or slowed economic growth in the U.S., demand growth from consumers for natural gas and oil produced and transported by us on our natural gas transportation systems may continue to decrease, which could impact the development of our future expansion projects. Additionally, our access to capital could be impeded and the cost of capital we obtain could be higher. We are subject to the risks arising from changes in legislation and regulation associated with any such recession or prolonged economic slowdown, including creating preferences for renewables, as part of a legislative package to stimulate the economy. In addition, the general volatility in the financial markets and the economy may also affect the return expectations of our investors and could adversely impact the value of our securities. Finally, our pension plans were underfunded at December 31, 2009, due primarily to the recent adverse economic conditions. While we do not currently expect to make additional contributions in 2010, we may be required to make additional pension plan contributions in the future if adverse economic conditions continue. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.

We are subject to financing and interest rate 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 unhedged portion of our exposure to interest rates;

	•		the structured and commercial financial markets;

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

	•		tax rates due to new tax laws;

	•		our stock price; and

	•		market prices for hydrocarbon products.

Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Rising interest rates could also negatively impact our investment in El Paso Pipeline Partners as changes in interest rates may affect the yield requirements of investors in its units.

Our available liquidity could be impacted by decreases in our natural gas and oil reserves under our borrowing base facility of our exploration and production subsidiary.

We maintain $1.3 billion of our liquidity through the borrowing base facilities of our exploration and production subsidiary. A downward revision of our natural gas and oil reserves, due to future declines in commodity prices, performance revisions or otherwise, could require a redetermination of the borrowing base and could negatively impact our ability to source funds from such facilities in the future.

Our ability to sell assets or obtain partners on projects, to maintain adequate liquidity may be impacted by adverse general economic conditions.

We currently are projecting to sell certain assets during 2010. In addition, it is possible that we may be required to sell assets or obtain partners on projects in order to maintain adequate levels of liquidity. Adverse general economic conditions as well as restrictions on the ability of parties to access capital markets could negatively impact our ability to sell such assets or obtain partners on such projects on a timely basis, as well as negatively impact the amount of proceeds from such sales or joint venture arrangements.

Our inability to satisfy all conditions precedent under the transaction with Global Infrastructure Partners (GIP) associated with the development, construction and financing of the Ruby pipeline project could require us to pay all amounts owed to GIP under the associated equity and debt instruments.

During the third quarter of 2009, we entered into an agreement with GIP, whereby it will invest up to $700 million and acquire a 50 percent indirect interest in our Ruby pipeline project. To the extent that all conditions precedent set forth in the agreements with GIP are not satisfied, including obtaining certain regulatory approvals, obtaining certain financing commitments and completing the pipeline, then we are obligated to repurchase its equity interests and repay all amounts owed under the loan arrangements. These repayment obligations are secured by various interests in Ruby Pipeline Holding Company, L.L.C. (Ruby), Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains) and our common units held in El Paso Pipeline Partners, L.P. Adverse economic conditions, as well as restrictions on our ability to access the capital markets could negatively impact our ability to meet such obligations, as well as permit GIP to foreclose on such security interests.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 13, and is incorporated herein by reference.

Natural Buttes. In May 2004, the EPA issued a Compliance Order to CIG related to alleged violations of a Title V air permit in effect at CIG’s Natural Buttes Compressor Station. In September 2005, the matter was referred to the U.S. Department of Justice (DOJ). CIG entered into a tolling agreement with the United States and conducted settlement discussions with the DOJ and the EPA. While conducting some testing at the facility, CIG discovered that three generators installed in 1992 may have been emitting oxides of nitrogen at levels which suggested the facility should have obtained a Prevention of Significant Deterioration (PSD) permit when the generators were first installed, and CIG promptly reported those test data to the EPA. CIG executed a Consent Decree with the DOJ and has paid a total of $1.02 million to settle all of these Title V and PSD issues at the Natural Buttes Compressor Station. In addition, as required by the Consent Decree, ambient air monitoring at the Uintah Basin commenced on January 1, 2010 for a period of two years. In November 2009, CIG sold its Natural Buttes compressor station and gas processing plant to a third party for $9 million.

PART II


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

Our common stock is traded on the New York Stock Exchange under the symbol EP. As of February 23, 2010, we had 29,916 stockholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.

Quarterly Stock Prices. The following table reflects the quarterly high and low sales prices for our common stock based on the daily composite listing of stock transactions for the New York Stock Exchange and the cash dividends per share we declared in each quarter:


	High		Low		Dividends
2009
Fourth Quarter	$	11.37	$	8.94	$	0.01
Third Quarter		10.85		8.00		0.05
Second Quarter		10.91		6.10		0.05
First Quarter		9.52		5.22		0.05
2008
Fourth Quarter	$	12.57	$	5.32	$	0.05
Third Quarter		22.47		11.25		0.05
Second Quarter		22.10		15.80		0.04
First Quarter		18.27		14.83		0.04

Stock Performance Graph. This graph reflects the comparative changes in the value of $100 invested since December 31, 2004 as invested in (i) El Paso’s common stock, (ii) the Standard & Poor’s 500 Stock Index, (iii) the Standard & Poor’s 500 Oil & Gas Storage & Transportation Index and (iv) our Peer Group identified below. The Peer Group we used for this comparison is the same group we use to compare total shareholder return relative to our performance for compensation purposes. Our peer group for 2008 and 2009 included the following companies: Anadarko Petroleum Corp., Apache Corp., CenterPoint Energy Inc., Chesapeake Energy Corp., Devon Energy Corp., Dominion Resources, Inc., Enbridge, Inc., EOG Resources Inc., EQT Corp., National Fuel Gas Co., Newfield Exploration Co., NiSource, Inc., Noble Energy Inc., ONEOK, Inc., Pioneer Natural Resources Co., Questar Corp., Sempra Energy, Southern Union Co., Spectra Energy Corp., TransCanada Corp., Williams Companies, Inc., and XTO Energy Inc.

COMPARISON OF ANNUAL CUMULATIVE TOTAL RETURNS



	12/04		12/05		12/06		12/07		12/08		12/09
El Paso Corporation	$	100	$	118.61	$	150.75	$	171.76	$	79.15	$	101.40
S&P 500 Stock Index	$	100	$	104.91	$	121.48	$	128.16	$	80.74	$	102.11
S&P 500 Oil & Gas Storage & Transportation Index⁽¹⁾	$	100	$	132.10	$	157.13	$	179.50	$	89.21	$	124.66
Peer Group (2008 & 2009)	$	100	$	139.85	$	150.42	$	193.68	$	126.90	$	196.69


⁽¹⁾		The S&P 500 Oil & Gas Storage & Transportation Index was created as of May 1, 2005 and thus, historical values for this index were not available. Accordingly, we provided this comparison against a custom index which includes the companies in the Standard & Poor’s 500 Oil & Gas Storage & Transportation Index, including El Paso.

⁽²⁾		The annual values of each investment are based on the share price appreciation and assume cash dividend reinvestment. The calculations exclude any applicable brokerage commissions and taxes. Cumulative total stockholder returns from each investment can be calculated from the annual values given above.

Dividends Declared. On February 24, 2010, we declared a quarterly dividend of $0.01 per share of our common stock, payable on April 1, 2010, to shareholders of record as of March 5, 2010. Future dividends will depend on business conditions, earnings, our cash requirements and other relevant factors.

Other. The terms of our 750,000 outstanding shares of 4.99% convertible preferred stock prohibit the payment of dividends on our common stock unless we have paid or set apart for payment all accumulated and unpaid dividends on such preferred stock for all preceding dividend periods. In addition, although our credit facilities do not contain any direct restrictions on the payment of dividends, dividends are included as a fixed charge in the calculation of our fixed charge coverage ratio under our credit facilities. If we are unable to comply with our fixed charge ratio, our ability to pay additional dividends would be restricted.

Odd-lot Sales Program. We have an odd-lot stock sales program available to stockholders who own fewer than 100 shares of our common stock. This voluntary program offers these stockholders a convenient method to sell all of their odd-lot shares at one time without incurring any brokerage costs. We also have a dividend reinvestment and common stock purchase plan available to all of our common stockholders of record. This voluntary plan provides our stockholders a convenient and economical means of increasing their holdings in our common stock. Neither the odd-lot program nor the dividend reinvestment and common stock purchase plan have a termination date; however, we may suspend either at any time. You should direct your inquiries to Computershare Trust Company, N.A., our stock transfer agent at 1-877-453-1503.

ITEM 6: SELECTED FINANCIAL DATA

The following selected historical financial data as of December 31, 2009 and 2008 and for each of the three years in the period ended December 31, 2009 is derived from the audited consolidated financial statements included in this Report on Form 10-K in Item 8, Financial Statements and Supplementary Data. The selected financial data as of December 31, 2007, 2006 and 2005 and for each of the two years in the period ended December 31, 2006 are derived from unaudited consolidated financial statements adjusted to reflect the adoption of the new presentation and disclosure requirements for noncontrolling interests. The selected financial data is not necessarily indicative of results to be expected in future periods and should be read together with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary Data included in this Report on Form 10-K.


	As of or for the Year Ended December 31,
	2009			2008			2007		2006		2005
	(In millions, except per common share amounts)
Operating Results Data:
Operating revenues	$	4,631		$	5,363		$	4,648	$	4,281	$	3,359
Income (loss) from continuing operations	$	(474	)	$	(789	)	$	442	$	532	$	(505	)
Net income (loss) attributable to El Paso Corporation’s common stockholders	$	(576	)	$	(860	)	$	1,073	$	438	$	(633	)
Earnings (loss) per common share from continuing operations attributable to El Paso Corporation’s common stockholders:
Basic	$	(0.83	)	$	(1.24	)	$	0.57	$	0.73	$	(0.82	)
Diluted	$	(0.83	)	$	(1.24	)	$	0.57	$	0.72	$	(0.82	)
Cash dividends declared per common share	$	0.16		$	0.18		$	0.16	$	0.16	$	0.16
Basic average common shares outstanding		696			696			696		678		646
Diluted average common shares outstanding		696			696			699		739		646

Financial Position Data:
Total assets	$	22,505		$	23,668		$	24,579	$	27,261	$	31,840
Long-term financing obligations, less current maturities		13,391			12,818			12,483		13,329		16,282
Preferred stock of subsidiary		145			—			—		—		—
Total equity		3,991			4,596			5,845		4,217		3,420

Factors Affecting Trends. During 2009 and 2008, we recorded non-cash full cost ceiling test charges of $2.1 billion and $2.7 billion, principally as a result of declines in commodity prices. In 2007, we sold our ANR pipeline system and related assets and also completed the initial public offering of common units in EPB, our master limited partnership. Our 2005 financial position and operating results were substantially affected by the restructuring and realignment of our business around our core pipeline and exploration and production operations, under which we sold a substantial amount of non-core assets to reduce our long-term financing obligations resulting in a significant reduction of our net income during that year.


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

Overview

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 Item 1A, Risk Factors. Listed below is a general outline of our MD&A:

Our Business — includes a summary of our business purpose and description, factors influencing profitability, a summary of our 2009 performance and an outlook for 2010;

Results of Operations — includes a year-over-year analysis of the results of our business segments, our corporate activities and other income statement items, including trends that may impact our business in the future;

Liquidity and Capital Resources — includes a general discussion of our sources and uses of cash, available liquidity, our liquidity outlook for 2010, an overview of cash flow activity during 2009, and additional factors that could impact our liquidity;

Off Balance Sheet Arrangements, Contractual Obligations, and Commodity-Based Derivative Contracts — includes a discussion of our (i) off balance sheet arrangements, including guarantees and letters of credit, (ii) other contractual obligations, and (iii) derivative contracts used to manage the price risks associated with our natural gas and oil production; and

Critical Accounting Estimates — includes a discussion of accounting estimates that involve the use of significant assumptions and/or judgments in the preparation of our financial statements.

Our Business

Our business purpose is to provide natural gas and related energy products in a safe, efficient and dependable manner. We own or have interests in North America’s largest interstate natural gas pipeline systems, which provide a stable base of earnings and cash flow with a significant backlog of committed expansion projects. We are also a large independent natural gas and oil producer focused on generating competitive financial returns through disciplined capital allocation and portfolio management, cost control and marketing and selling our natural gas and oil production at optimal prices while managing associated price risks.

Factors Influencing Our Profitability. Our pipeline operations are rate-regulated and accordingly we generate profit based on our ability to earn a return in excess of our costs through the rates we charge our customers. Our exploration and production operations generate profits dependent on the prices for natural gas and oil, our costs to explore, develop, and produce natural gas and oil, and the volumes we are able to produce, among other factors. Our long-term profitability in each of our operating segments will be primarily influenced by the following factors:

Pipelines

	•		Successfully executing on our remaining backlog of committed expansion projects on time and on budget and developing new growth projects in our market and supply areas;

	•		Contracting and recontracting pipeline capacity with our customers;

	•		Maintaining or obtaining approval by the FERC of acceptable rates, terms of service, and expansion projects; and

	•		Improving operating efficiency.

Exploration and Production

	•		Growing our natural gas and oil proved reserve base and production volumes through successful drilling programs;

	•		Finding and producing natural gas and oil at a reasonable cost; and

	•		Managing price risks to optimize realized prices on our natural gas and oil production.

In addition to these factors, our future profitability will also be affected by any impacts of the volatility in the financial and commodity markets, our debt level and related interest costs, the successful resolution of our historical contingencies and completing the orderly exit of our remaining power assets, historical derivative contracts and other remaining non-core assets.

Summary of 2009 Financial and Operational Performance

During 2009, we generated significant operating cash flows from our core pipeline and exploration and production businesses while executing on our plan outlined in late 2008 to respond to the volatility in the financial markets, energy industry and the global economy. During 2009, we placed several pipeline expansion projects into service, obtained a partner on our Ruby project and secured financing for a portion of our remaining pipeline backlog. In our exploration and production business, despite a lower level of drilling activity, lower natural gas prices and lower capital spending in 2009, we expanded our resource inventory with low-risk onshore reserves, lowered our operating costs, and managed our exposure to a volatile commodity price environment through an expanded hedging program through 2011. However, due to lower natural gas prices at the end of the first quarter of 2009, we recorded approximately $2.1 billion of non-cash ceiling test charges, primarily on our domestic full cost pool, which significantly impacted our overall financial results. We believe the stability of our pipeline earnings coupled with the hedging program in our exploration and production business will continue to protect our earnings base and cash flows from operations. Additionally, we believe we have managed our capital program to provide for our pipeline backlog while retaining substantially all of our existing natural gas and oil resource positions for future exploration and production activities.

The following table provides 2009 operational highlights in our core businesses:


Area of Operations		Significant Highlights

Pipelines		Continued to make progress on our backlog of expansion projects placing four growth projects in service on budget, including the Carthage Expansion, the Totem Gas Storage project, the WIC Piceance Lateral expansion, and the Concord Lateral Expansion

		Obtained a 50 percent partner for our Ruby pipeline project and completed $2.1 billion of financings to partially fund our pipeline backlog Successfully settled the SNG rate case with contract extensions through August 2013 and a rate moratorium until September 2012

Exploration and Production		Achieved an overall domestic drilling success rate of 96 percent Shifted focus to more unconventional resource plays domestically including the Haynesville Shale in northwest Louisiana and east Texas, the Eagle Ford Shale in south Texas and the Altamont-Bluebell-Cedar Rim Field fractured tight sands in Utah Brought Camarupim project on line in Brazil and found hydrocarbons in two wells drilled in Egypt Managed price risk through derivative contracts on 2009, 2010 and 2011 natural gas production as well as our 2009 and 2010 oil production

In our non-core Power segment, we completed the sale of our interests in the Porto Velho power generation facility and the Argentina-to-Chile pipeline to our partners in these projects. In October 2009, we also announced our re-entry into the midstream business where we believe that the movement to more unconventional supply basins will present future opportunities.

Outlook for 2010

We expect that our pipeline operations will continue to provide a strong base of earnings and operating cash flow in 2010. We expect to have relatively stable rates within our pipeline group, with the majority of our pipelines not having any outstanding rate cases pending before the FERC. We have also increased our 2010 capital expenditure program for this business to approximately $2.9 billion and have a backlog of growth projects which we will remain focused on implementing both on time and on budget. We currently plan to place three more projects in service by the end of 2010. However, the largest portion of our capital program is related to the anticipated construction of our Ruby pipeline project. Finally, we will consider additional opportunities with our master limited partnership (MLP), EPB, as the markets permit.

In our exploration and production business, we also expect to generate significant operating cash flow and earnings, although additional non-cash ceiling test charges could impact our earnings in the future as a result of future declines in natural gas and oil prices. We anticipate spending approximately $1.1 billion in capital expenditures in this business during 2010, with approximately one-half of the domestic capital program targeted for our Haynesville, Altamont and Eagle Ford areas and $175 million planned for our Brazil and Egypt programs. Our planned average daily production for 2010 is expected to range between 740 MMcfe/d and 780 MMcfe/d, including approximately 60 MMcfe/d to 65 MMcfe/d from our ownership interest in the production of Four Star. Although commodity prices remain at lower levels, we have expanded our financial derivative contracts in place for 2010 providing $6.41 average floors on approximately 85 percent of our estimated consolidated natural gas production and $75 average floors on approximately 90 percent of our estimated consolidated oil production. These contracts also allow for potential upside.

As of December 31, 2009, we had approximately $1.8 billion of available liquidity. In 2010, we have an estimated $4.1 billion capital program which provides for funding our pipeline backlog as well as exploration and production reserves growth. Our 2010 capital program consists of $2.9 billion related to our pipeline business (including 100% of Ruby pipeline capital) and approximately $1.1 billion related to our exploration and production business. While our 2010 pipeline capital requirements are significant, our 2011 requirements decline significantly and by the end of 2011 most of our backlog will be placed in service. Accordingly, in 2012, we expect to benefit from the earnings generated from our substantially completed pipeline backlog and greater exploration and production volumes. In 2010, our debt maturities are nominal. We believe we are well positioned to meet our obligations based on the anticipated performance of our core businesses, our financing actions taken to date and planned for 2010, and the additional steps noted below to enhance our liquidity. For a further discussion, see Liquidity and Capital Resources.

In November 2009, we announced additional steps we would take to further improve our financial flexibility to fund our core businesses. The additional steps are designed to (i) provide incremental funding for our 2010 capital programs focused on our industry-leading pipeline backlog of growth opportunities and growing our unconventional natural gas drilling inventory in our exploration and production business, (ii) improve our overall cost structure, (iii) protect our credit profile, (iv) manage commodity risk and (v) enhance overall shareholder returns. These steps were:

	•		A reduction of $150 million in annual operating and administrative expenses achieved primarily by reducing internal costs and improving efficiencies from leveraging a consolidated supply chain organization, a portion of which was realized in 2009.

	•		The sale of $300 million to $500 million of assets during 2010. In February 2010, we entered into an agreement to sell our interest in Mexican pipeline and compression assets for approximately $300 million; and

	•		A reduction in our quarterly dividend from $0.05 per share to $0.01 per share, which will result in annual cash savings of approximately $112 million.

We will continue to assess and take further actions where prudent to meet our long-term objectives and capital requirements as well as address further changes in the financial and commodity markets.

Results of Operations

Overview

As of December 31, 2009, our core operating business segments were Pipelines and Exploration and Production. We also have a Marketing segment that markets our natural gas and oil production and manages our legacy trading activities and a Power segment that has interests in power and pipeline assets in South America and Asia. Our segments are managed separately, provide a variety of energy products and services, and require different technology and marketing strategies. Our corporate activities include our general and administrative functions, as well as other miscellaneous businesses, contracts and assets all of which are immaterial.

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business segments, which consist of both consolidated businesses and investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to evaluate more effectively our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for items such as (i) interest and debt expense, (ii) income taxes, and (iii) net income attributable to noncontrolling interests so that our investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flows.

Below is a reconciliation of our EBIT (by segment) to our consolidated net income (loss) for each of the three years ended December 31:


	2009			2008			2007
	(In millions)
Segment
Pipelines	$	1,416		$	1,273		$	1,265
Exploration and Production		(1,349	)		(1,448	)		909
Marketing		20			(104	)		(202	)
Power		(25	)		1			(37	)

Segment EBIT⁽¹⁾		62			(278	)		1,935
Corporate and other		8			124			(283	)

Consolidated EBIT⁽¹⁾		70			(154	)		1,652
Interest and debt expense		(1,008	)		(914	)		(994	)
Income tax benefit (expense)		399			245			(222	)
Discontinued operations, net of income taxes		—			—			674

Net income (loss) attributable to El Paso Corporation		(539	)		(823	)		1,110
Net income attributable to noncontrolling interests		65			34			6

Net income (loss)	$	(474	)	$	(789	)	$	1,116


⁽¹⁾		^{2007 EBIT represents EBIT from continuing operations.}

The discussions that follow provide additional analysis of the year over year results of each of our business segments, our corporate activities and other income statement items.

Pipelines Segment

Overview

Our Pipelines segment operates primarily in the United States and consists of interstate natural gas transmission, storage and LNG terminalling related services. We face varying degrees of competition in this segment from other existing and proposed pipelines and proposed 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, storage, LNG terminalling and related services consist of two types:

The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, regulatory actions, competition, weather and declines in the creditworthiness of our customers. We also experience earnings volatility at certain pipelines when the amount of natural gas used in our operations differs from the amounts we receive for that purpose.

Historically, much of our business was conducted through long-term contracts with customers. However, many of our customers have shifted from a traditional dependence on long-term contracts to a portfolio approach, which balances short-term opportunities with long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new supply sources, volatility in natural gas prices, demand for short-term capacity and new power plant markets.

We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum 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 five years as of December 31, 2009.

Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts on our wholly and majority owned systems as of December 31, 2009, including those with terms beginning in 2010 or later:


	Contracted Capacity						Percent of Total
	BBtu/d		Percent of Total		Reservation Revenue		Reservation Revenue
					(In millions)
2010		3,275		12	$	115		6
2011		2,570		10		198		10
2012		3,852		15		212		10
2013		5,359		20		506		25
2014		1,211		5		118		6
2015 and beyond		10,337		38		867		43

Total		26,604		100	$	2,016		100

Summary of Operational and Financial Performance

In 2009, we continued to deliver strong operational and financial performance across all pipelines benefitting from several expansion projects placed in service. These projects included the Carthage Expansion in May, Totem Gas Storage in June, the WIC Piceance Lateral expansion in September, and the Concord Lateral Expansion in October. We continue to make significant progress on our remaining backlog of expansion projects. In 2009, EPB issued additional public common units and used the proceeds primarily to acquire additional interests in CIG. At December 31, 2009, our ownership interest in EPB consisted of a two percent general partner interest and a 65 percent limited partner interest.

During 2010, we plan to spend $2.9 billion in capital on our pipeline business, including $2.5 billion on our backlog of expansion projects. Our most significant projects are listed below grouped by anticipated in-service dates.

Cumulative

Project Spend

Anticipated In-Service

Total Estimated

as of

Project

Dates

Project Costs

December 31, 2009

FERC Approved

(In millions)

2010:

Elba Expansion III and Elba Express (Phase A)

March/August 2010⁽²⁾

903

812

Yes

CIG Raton 2010 Expansion

December 2010

146

⁽¹⁾

2011 and Beyond:

WIC System Expansion⁽³⁾

First Quarter of 2011

⁽¹⁾

Ruby Pipeline⁽⁴⁾⁽⁵⁾

First Quarter of 2011

2,964

732

⁽¹⁾

FGT Phase VIII Expansion (50%)⁽⁴⁾⁽⁶⁾

April 2011

1,202

372

Yes

Gulf LNG Clean Energy (50%)⁽⁶⁾⁽⁷⁾

October 2011

808

563

Yes

TGP 300 Line Expansion

November 2011

642

100

⁽¹⁾

South System III and Southeast Supply Header — Phase II⁽⁴⁾

2011-2012

421

Yes

TGP Northeast Upgrade Project

November 2013

416

—

Elba Expansion III and Elba Express (Phase B)

January 2014

261

Yes


⁽¹⁾		^{An application has been filed with the FERC for this project.}

⁽²⁾		^{Elba Expansion III vaporization and Elba Express in-service dates are March 2010 and Elba Expansion III storage in-service date is August 2010.}

⁽³⁾		^{This expansion consists of two projects.}

⁽⁴⁾		^{These projects have substantial contractual commitments with customers but are not fully contracted.}

⁽⁵⁾		^{Amount includes 100 percent of our Ruby pipeline project expenditures. As of December 31, 2009, we have received $362 million and anticipate obtaining approximately $700 million of funding in total from our equity partner on this project.}

⁽⁶⁾		^{Amounts represent our share of the estimated costs for these unconsolidated affiliates.}

⁽⁷⁾		^{Amount includes approximately $295 million that we paid to acquire a 50 percent interest in this project.}

Listed below is additional information related to our significant backlog projects:

•		Elba Expansion III/ Elba Express/ Cypress Phase III. During the second quarter of 2009, BG LNG Services LLC (BG) and SNG, Elba Express and Southern LNG, Inc. entered into agreements to delay the in-service date of the Elba Expansion III Phase B project at BG’s option, to as late as December 31, 2014, or, in the event certain conditions are unable to be met by BG, to terminate the Elba Expansion III Phase B project. In exchange for this delay/termination option, BG has committed to subscribe to certain firm Phase B capacity on our Elba Express pipeline and to provide certain rate considerations on an existing transportation contract on our SNG Pipeline. In addition, BG has given up its right to proceed with Phase III of the Cypress Expansion Project on SNG. Phase A of both the Elba Expansion III vaporization facilities and the Elba Express project are expected to commence commercial operations in March 2010.

•		WIC Expansion. WIC expanded the scope of this project to add a second compressor unit on the Kanda Lateral due to increased shipper commitments. This portion of the project will add a 12,400 horsepower compressor station on the Kanda Lateral which will increase the capacity on this lateral to 595 MDth/d. WIC also plans to install three miles of pipeline and reconfigure one compressor at its Wamsutter station which will provide 155 MDth/d natural gas deliveries from the WIC Mainline into a third party pipeline and onto the Opal Hub and the proposed Ruby pipeline.

•		Ruby Pipeline Project. We expect that the Ruby pipeline project will consist of approximately 680 miles of 42” pipeline and multiple compressor stations with total horsepower of approximately 157,000; however, final sizing will be based on market support. In September 2009, we received a Preliminary Determination from the FERC on non-environmental issues related to this project. In January 2010, the FERC issued a final Environmental Impact Statement (EIS) related to our Ruby project. Subject to FERC and other approvals, the project is expected to commence construction in the first half of 2010 and is anticipated to be placed in service during the first quarter of 2011.

•		FGT Phase VIII Project. In September 2009, the FERC issued a final EIS. We also received the Pipeline and Hazardous Materials Safety Administration special permit from the Department of Transportation in order to operate the pipeline at higher operating pressures. In November 2009, the FERC approved this project.

•		Gulf LNG. In February 2008, we completed our acquisition of a 50 percent interest in the Gulf LNG Clean Energy Project, which is constructing a FERC approved LNG terminal in Pascagoula, Mississippi with a designed sendout capacity of 1.5 bcf/d that is expected to be placed in service in October 2011.

•		TGP 300 Line Expansion. All of the firm transportation capacity resulting from this project in the northeast U.S. market area is fully subscribed with one shipper based on a precedent agreement which was executed in the third quarter of 2009. An environmental assessment is expected to be issued by the FERC in the first quarter of 2010.

•		South System II/ Southeast Supply Header. The South System II expansion project will expand SNG’s pipeline system in Mississippi, Alabama and Georgia by adding approximately 81 miles of pipeline looping and replacement on SNG’s south system and 17,310 of horsepower compression to serve an existing power generation facility in the Atlanta, Georgia area. This project will be completed in three phases with each phase expected to add an additional 122 MMcf/d of capacity.

		The Southeast Supply Header is expected to provide access through pipeline interconnects to several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale basins and is expected to provide SNG with an additional 350 MMcf/d of supply capacity.

•		TGP Northeast Upgrade Project. In February 2010, TGP entered into precedent agreements with two shippers to provide 636,000 MMBtu/d of additional firm transportation service from receipt points in the Marcellus Shale basin to an interconnect in New Jersey. In order to accommodate the additional service, we will pursue Northeast Upgrade project which includes approximately 37 miles of 30” pipeline looping and approximately 20,600 horsepower of additional compression. The expected cost for this project is $416 million and construction is anticipated to be placed in service by November 2013.

Successful execution on our committed pipeline backlog will continue to require effective project management. In addition to securing a partner for the Ruby pipeline project in 2009, we have significantly mitigated the risk associated with our remaining backlog by subscribing approximately 90 percent of the capacity of our aggregate backlog under contract terms of 10 to 30 years primarily with investment-grade customers and purchasing or committing to purchase steel at fixed prices for all of our largest projects as well as contracting a significant portion of the construction costs.

In addition to our current backlog of contracted organic growth projects, we have other potential projects that are in various phases of commercial development. Many of these projects involve expansion capacity to serve increased natural gas-fired generation loads, as well as new supply projects. Most of our potential expansion projects would have in-service dates for 2014 and beyond. If we are successful in contracting for these new projects, the capital requirements could be substantial and would be incremental to our current projects. Although we pursue the development of these and other potential projects from time to time, there can be no assurance that we will be successful in negotiating the definitive binding contracts necessary for such projects.

•

Potential Power Plant Loads. Similar to SNG’s South System III project, we are pursuing various expansion projects particularly in the southeastern portion of the United States (U.S.) to serve increased natural gas-fired generation loads. In addition, along the Front Range of CIG’s system, utilities have various projects under development that involve constructing new natural gas-fired generation in part to provide backup capacity required when renewable generation is not available during certain daily or seasonal periods.

Operating Results


	2009			2008			2007
	(In millions, except volumes)
Operating revenues	$	2,767		$	2,684		$	2,494
Operating expenses		(1,486	)		(1,532	)		(1,383	)

Operating income		1,281			1,152			1,111
Other income, net		200			156			157

EBIT before noncontrolling interests		1,481			1,308			1,268
Net income attributable to noncontrolling interests		(65	)		(35	)		(3	)

EBIT⁽³⁾	$	1,416		$	1,273		$	1,265

Throughput volumes (BBtu/d)⁽¹⁾
TGP		4,614			4,864			4,880
El Paso Natural Gas (EPNG) and Mojave Pipeline (MPC)		3,982			4,422			4,216
CIG, WIC and Cheyenne Plains Gas Pipeline (CPG)		5,550			5,376			4,906
SNG		2,322			2,339			2,345
Other		50			50			50
Equity investments and other⁽²⁾		1,820			1,763			1,734

Total throughput		18,338			18,814			18,131


⁽¹⁾		^{Volumes exclude intrasegment activities.}

⁽²⁾		^{Represents our proportional share of unconsolidated affiliates.}

⁽³⁾		^{2007 EBIT represents EBIT from continuing operations.}

Below is a discussion that details the impact on EBIT of significant events in 2009 compared with 2008 and 2008 as compared with 2007. We have also provided an outlook on events that may affect our operations in the future.


	2009 to 2008												2008 to 2007
	Variance												Variance
	Revenue			Expense			Other			Total			Revenue			Expense			Other			Total
	Favorable/(Unfavorable)
	(In millions)
Expansions	$	103		$	(25	)	$	49		$	127		$	74		$	(26	)	$	19		$	67
Reservation and usage revenues		23			—			—			23			67			—			—			67
Gas not used in operations and revaluations		2			30			—			32			33			(13	)		—			20
Bankruptcy proceeds		(48	)		(1	)		—			(49	)		27			1			—			28
Operating and general and administrative expense		—			4			—			4			—			(62	)		—			(62	)
Gain/loss on long-lived assets		—			42			—			42			—			(31	)		1			(30	)
Hurricanes		10			13			—			23			(10	)		(14	)		—			(24	)
Equity earnings from Citrus		—			—			2			2			—			—			(17	)		(17	)
Net income attributable to noncontrolling interests		—			—			(30	)		(30	)		—			—			(32	)		(32	)
Other⁽¹⁾		(7	)		(17	)		(7	)		(31	)		(1	)		(4	)		(4	)		(9	)

Total impact on EBIT	$	83		$	46		$	14		$	143		$	190		$	(149	)	$	(33	)	$	8


⁽¹⁾		^{Consists of individually insignificant items on several of our pipeline systems.}

Expansions. During 2009 and 2008, our reservation revenues and throughput volumes increased due to the projects placed in service. During 2009 and 2008, we placed the Carthage expansion project, the Totem Gas Storage facility, the Concord Lateral expansion, the WIC Piceance Lateral expansion, the WIC Kanda Lateral project, Phase II of the Cypress project, the Cheyenne Plains compression expansion project, Phase I of the Southeast Supply Header project, the Medicine Bow expansion and the High Plains Pipeline projects in service.

Reservation and Usage Revenues. During the year ended December 31, 2009 compared with 2008, our reservation and usage revenues were also impacted by:

	•		increased revenues for the mainline and lateral capacity on our Rocky Mountain region systems primarily due to new contracts and restructured contract terms;

	•		additional capacity sales of approximately $8 million primarily from the Marcellus Basin in the northeast market area of our TGP system;

	•		increased reservation and other services revenues of approximately $24 million primarily on our SNG system due to higher tariff rates effective September 1, 2009 pursuant to SNG’s rate case settlement further discussed below;

	•		higher reservation charges of approximately $11 million for capacity on our EPNG system resulting from increased contracted capacity to primary delivery points in California and an increase in EPNG’s tariff rates effective January 1, 2009, subject to refund; and

	•		unfavorable usage revenue of approximately $20 million due to decreased activity under various interruptible services and lower demand at the southeast interconnects resulting from increased competition on our TGP system.

For the year ended December 31, 2009, our throughput volumes on the TGP and EPNG systems decreased compared with 2008. This was due, in part, to general weakness in natural gas demand in the United States, including in the northeast and southwest. Although fluctuations in throughput on our pipeline systems have a limited effect on our short-term results since a material portion of our revenues are derived from firm reservation charges, it can be an indication of the risks we may face when seeking to recontract or renew any of our existing firm transportation contracts. Continuing negative economic impacts on demand, as well as adverse shifting of sources of supply, could negatively impact basis differentials and our ability to renew firm transportation contracts that are expiring on our system or our ability to renew such contracts at current rates. If we determine there is a significant change in our costs or billing determinants on any of our pipeline systems, we will have the option to file rate cases on certain of our pipelines with the FERC to recover our prudently incurred costs.

For the year ended December 31, 2008 compared with 2007, the increase in our reservation and usage revenues was primarily due to:

	•		approximately $22 million related to increased demand for off-system and mainline capacity on our Rocky Mountain region systems primarily due to lower natural gas prices in the Rocky Mountains as compared to other regions in the United States;

	•		approximately $15 million related to additional firm capacity sold in the northern and southern regions of our TGP system, partially offset by lower surcharges from certain firm customers on this system ;

	•		approximately $29 million related to increased reservation and usage revenues on our EPNG system due to higher amounts charged on recontracted capacity in Arizona and California; and

	•		approximately $1 million related to additional interruptible and firm commodity services provided in several of our pipeline systems.

Gas Not Used in Operations and Revaluations. During the year ended December 31, 2009, our overall EBIT was $32 million favorable when compared with 2008, primarily due to retained fuel volumes in excess of fuel used in operations, higher realized prices on operational sales, lower electric compression utilization, and lower index prices related to fuel imbalance revaluations, settlement and other gas balance related items.

In addition, during 2008, CIG and WIC recorded cost and revenue tracker adjustments associated with the implementation of fuel and related gas cost recovery mechanisms, which the FERC approved subject to the outcome of technical conferences. The implementation of these mechanisms was protested by a limited number of shippers. On July 31, 2009 and October 1, 2009, the FERC issued orders to CIG and WIC, respectively, directing them to remove the cost and revenue components from their fuel recovery mechanisms. Additionally, on October 1, 2009, EPNG received an order from the FERC directing EPNG to remove the cost and revenue component of its fuel recovery mechanism. EPNG’s compliance filing to remove the cost and revenue component was approved in the fourth quarter of 2009. Our future earnings may be impacted positively or negatively depending on fluctuations in gas prices related to the revaluation of EPNG’s under or over recoveries, imbalances and system encroachments. EPNG’s 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. We continue to explore options to minimize the price volatility associated with these operational pipeline activities.

During the year ended December 31, 2008 compared with the same period in 2007, our EBIT was favorably impacted by $20 million due to higher volumes of gas not used in our TGP operations.

Bankruptcy Proceeds. During 2008, our revenue increased by $39 million related to Calpine Corporation’s (Calpine’s) rejection of its transportation contracts with us primarily associated with distributions received under Calpine’s approved plan of reorganization. During 2008 and 2007, we recorded income of approximately $10 million and $5 million, net of amounts potentially owed to certain customers, related to amounts recovered from the Enron bankruptcy settlement. In 2007, we received $10 million to settle our bankruptcy claim against USGen New England, Inc.

Operating and General and Administrative Expenses. For the year ended December 31, 2009, our operating and general and administrative expenses were lower than in 2008 primarily due to $18 million of decreased field repair and maintenance expense on several of our pipeline systems. Partially offsetting these cost reductions were severance costs of approximately $14 million. During the year ended December 31, 2008, our operating and general and administrative expenses were higher than in 2007 primarily due to increased labor costs of approximately $43 million to support our growth and customer activities and approximately $29 million in additional maintenance work required on several of our pipeline systems.

Gain/Loss on Long-Lived Assets. During 2009, we recorded a gain of $8 million related to the sale of CIG’s Natural Buttes compressor station and gas processing plant. During 2008, we recorded impairments of $41 million, including an impairment related to our Essex-Middlesex Lateral project due to a prolonged permitting process and an impairment of our EPNG Arizona gas storage projects that we are no longer developing due to declining real estate values. During 2007, we recorded (i) a $10 million impairment of certain pipeline assets originally purchased to repair certain offshore hurricane damage following a decision not to use these assets, (ii) a loss of approximately $9 million on EPNG’s East Valley Line Lateral pursuant to a FERC determination on the accounting treatment for the pending sale of certain transmission facilities and (iii) a $7 million pre-tax gain on the sale of a pipeline lateral.

Hurricanes. During 2008, we incurred damage to sections of our Gulf Coast and offshore pipeline facilities due to Hurricanes Ike and Gustav. Our EBIT was unfavorably impacted by $8 million in 2009 due to repair costs and $31 million in 2008 related to these hurricanes due to gas loss from various damaged pipelines, lower volume of gas not used in operations, and repair costs that did not exceed self-retention levels.

Equity Earnings from Citrus. In 2008, equity earnings on our Citrus investment decreased as compared to 2007 primarily due to Citrus’s favorable settlement in 2007 of approximately $8 million for litigation brought against Spectra LNG Sales (formerly Duke Energy LNG Sales, Inc.) for the wrongful termination of a gas supply contract and Citrus’ sale of a receivable in 2007 for approximately $3 million related to the bankruptcy of Enron North America.

Net Income Attributable to Noncontrolling Interests. Our net income attributable to noncontrolling interests increased during 2009 and 2008 due to (i) the additional public common units issued by our majority-owned MLP in July 2009 and (ii) our contribution to our MLP of additional interests in CIG (18 percent in July 2009 and 20 percent in September 2008) and SNG (15 percent in September 2008). As of December 31, 2009, our MLP owned 58 percent of CIG, 25 percent of SNG and 100 percent of WIC and we owned 67 percent of the MLP.

Other Regulatory Matters. Our pipeline systems periodically file for changes in their rates, which are subject to the approval by the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. Currently, while certain of our pipelines are expected to continue operating under their existing rates, other pipelines have projected upcoming rate actions with anticipated effective dates from 2011 through 2013.

In January 2010, the FERC approved SNG’s settlement in which SNG (i) increased its base tariff rates, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next general rate case to be effective after August 31, 2012 but no later than September 1, 2013, and (iv) extended the vast majority of SNG’s firm transportation contracts until August 31, 2013.

In June 2008, EPNG filed a rate case with the FERC as required under the settlement of its previous rate case. The filing proposed an increase in EPNG’s base 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 EPNG’s proposals in the technical conference proceeding. The FERC has appointed an administrative law judge to preside over a hearing if EPNG is unable to reach a negotiated settlement with its customers on the remaining issues. Settlement negotiations are continuing; however, the hearing has been postponed until May 2010. The outcome of the settlement discussions and the hearing is not currently determinable.

Exploration and Production Segment

Overview and Strategy

Our Exploration and Production segment conducts our natural gas and oil exploration and production activities. The profitability and performance of this segment are driven by the ability to locate and develop economic natural gas and oil reserves and extract those reserves at the lowest possible production and administrative costs. Accordingly, we manage this business with the goal of creating value through disciplined capital allocation, cost control and portfolio management. Our strategy focuses on building and applying competencies in assets with repeatable programs, executing to improve capital and expense efficiency, and maximizing returns by adding assets and inventory that match our competencies and divesting assets that do not. During 2009, in the U.S., we shifted our focus to more unconventional resource plays including the Haynesville Shale in northwest Louisiana and east Texas, the Eagle Ford Shale in south Texas and the Altamont-Bluebell-Cedar Rim Field fractured tight sands in Utah.

Our domestic natural gas and oil reserve portfolio blends lower decline rate, typically longer lived assets in our Central and Western divisions, with steeper decline rate, shorter lived assets in our Gulf Coast division. Approximately 79 percent of our 2009 capital was spent on domestic projects. Internationally, our portfolio consists of producing fields along with several exploration and development projects in offshore Brazil and exploration projects in Egypt. Our 2009 international capital, primarily in Brazil, constituted approximately 21 percent of our total capital program. Success of our international programs in Brazil and Egypt will require effective project management, strong partner relations and obtaining approvals from regulatory agencies.

During 2009, the challenging commodity price environment resulted in ceiling test charges totaling $2.1 billion. Coupled with unprecedented challenges in the credit markets, we also reduced our capital spending during 2009.

We continue to evaluate acquisition and growth opportunities that are focused on our core competencies and areas of competitive advantage. Strategic acquisitions, like the one we completed in December 2009 of natural gas and oil properties in the Altamont-Bluebell-Cedar Rim Field in Utah, can support our corporate objectives, providing us greater opportunities to achieve our long term performance goals by leveraging operational expertise already possessed in key operating areas, balancing our exposure to regions, basins and commodities, achieving risk-adjusted returns competitive with those available within our existing inventory, and increasing our reserves by supplementing our current drilling inventory.

In addition to effectively executing on our strategy, our profitability and performance is impacted by (i) changes in commodity prices, (ii) industry-wide changes in the cost of drilling and oilfield services, and (iii) the effect of hurricanes and other weather impacts on our daily production, operating, and capital costs. To the extent possible, we attempt to mitigate these factors. As part of our risk management activities, we maintain derivative contracts to reduce the financial impact of downward commodity price movements.

Significant Operational Factors Affecting the Year Ended December 31, 2009

Production. Our average daily production for the year was 763 MMcfe/d, including 72 MMcfe/d from our equity interest in the production of Four Star. Below is an analysis of our 2009 production by division (MMcfe/d):


	2009		2008		2007
United States
Central		257		238		227
Western		154		154		147
Gulf Coast		268		339		404
International
Brazil		12		11		14

Total consolidated		691		742		792

Four Star		72		74		70

Total combined		763		816		862

		Central division — Our 2009 Central division production volumes continued to increase as a result of our successful Arklatex drilling programs including the Haynesville Shale. In the Haynesville Shale, we drilled 17 wells during the year and had average net production of approximately 36 MMcfe/d. At December 31, 2009, we had 20 operated wells producing at a rate of approximately 110 MMcfe/d.

		Western division — Our 2009 Western division production volumes were flat as compared to 2008 primarily due to the successful drilling programs in the Altamont-Bluebell-Cedar Rim Field offset by natural declines in the Rockies.

		Gulf Coast division — Our 2009 Gulf Coast division production volumes decreased primarily due to sales of assets in 2008 and early 2009. In this division, our 2009 focus was on increasing our Eagle Ford Shale acreage, where we hold approximately 132,000 net acres as of December 31, 2009 and drilled our first well which was successful.

		Brazil — In Brazil, our 2009 production volumes were up slightly from 2008. Production from natural declines in our Pescada-Arabiana Fields was more than offset by new production from our Camarupim Field, where we began production in the fourth quarter of 2009.

2009 Drilling Results

Central. We achieved a 99 percent success rate on 139 gross wells drilled.

Western. We achieved a 100 percent success rate on seven gross wells drilled.

Gulf Coast. We achieved an 80 percent success rate on 30 gross wells drilled.

Brazil. We achieved a 75 percent success rate on four gross wells drilled.

Egypt. Hydrocarbons were found in two of five or 40 percent of the gross exploratory wells we drilled or participated in drilling.

For a further discussion of our activities in Brazil and Egypt, see Part I, Item 1, Business, Exploration and Production Segment, International.

Cash Operating Costs. We monitor cash operating costs required to produce our natural gas and oil production volumes. Cash operating costs is a non-GAAP measure calculated on a per Mcfe basis and includes total operating expenses less depreciation, depletion and amortization expense, ceiling test and other impairment charges, transportation costs and cost of products. Cash operating costs per unit is a valuable measure of operating performance and efficiency for the exploration and production segment.

During the year ended December 31, 2009, cash operating costs per unit decreased to $1.82/Mcfe as compared to $1.97/Mcfe in 2008. The decrease in 2009 is primarily due to lower lease operating expenses and production taxes partially offset by lower production volumes in 2009 versus 2008.

Reserve Replacement Ratio/Reserve Replacement Costs. We calculate two primary metrics, (i) a reserve replacement ratio and (ii) reserve replacement costs, to measure our ability to establish a long-term trend of adding reserves at a reasonable cost in our core asset areas. The reserve replacement ratio is an indicator of our ability to replenish annual production volumes and grow our reserves. It is important for us to economically find and develop new reserves that will more than offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves. In addition, we calculate reserve replacement costs to assess the cost of adding reserves, which is ultimately included in depreciation, depletion and amortization expense. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core asset areas at lower costs than our competition. We calculate these metrics as follows:


Reserve replacement ratio		Sum of reserve additions^{(1) (2)}

		Actual production for the corresponding period

Reserve replacement costs/Mcfe		Total oil and gas capital costs⁽³⁾

		Sum of reserve additions ^{(1) (2)}


⁽¹⁾		^{Reserve additions include proved reserves and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities or proved reserve additions attributable to investments accounted for using the equity method. We present these metrics separately, both including and excluding the impact of price revisions on reserves, to demonstrate the effectiveness of our drilling program exclusive of economic factors (such as price) outside of our control. All amounts are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations.}

⁽²⁾		^{The proved reserves used in the calculation of reserve replacement ratio and reserve replacement costs in 2009 were determined based on the SEC’s final rule on Modernization of Oil and Gas Reporting (Final Rule) effective December 31, 2009. The Final Rule, among other things, revised the definitions of proved reserves and required us to use a first day 12-month average price in determining estimated proved reserves.}

⁽³⁾		^{Total oil and gas capital costs include the costs of development, exploration and property acquisition activities conducted to add reserves and exclude asset retirement obligations. Amounts are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations.}

The reserve replacement ratio and reserve replacement costs per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio is limited because it typically varies widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. In addition, since the reserve replacement ratio does not consider the cost or timing of developing future production of new reserves, it cannot be used as a measure of value creation.

The exploration for and the acquisition and development of natural gas and oil reserves is inherently uncertain as further discussed in Part I, Item 1A, Risk Factors, Risks Related to our Business. One of these risks and uncertainties is our ability to spend sufficient capital to increase our reserves. While we currently expect to spend such amounts in the future, there are no assurances as to the timing and magnitude of these expenditures or the classification of the proved reserves as developed or undeveloped. At December 31, 2009, proved developed reserves represent approximately 67 percent of our total proved reserves. Proved developed reserves will generally begin producing within the year they are added, whereas proved undeveloped reserves generally require a major future expenditure.

The table below shows our reserve replacement costs and reserve replacement ratio for our domestic and worldwide operations, including and excluding the effect of price revisions on reserves for each of the years ended December 31:


	Including Price Revisions						Excluding Price Revisions
	2009		2008		2007		2009		2008		2007
			($/Mcfe)						($/Mcfe)
*Domestic*
Reserve replacement costs, including acquisitions	$	1.84	$	6.68	$	3.26	$	1.57	$	2.87	$	3.46
Reserve replacement costs, excluding acquisitions		1.91		7.01		3.22		1.59		2.87		3.65
*Worldwide*
Reserve replacement costs, including acquisitions	$	2.04	$	36.00	$	3.55	$	1.76	$	3.25	$	3.77
Reserve replacement costs, excluding acquisitions		2.13		56.05		3.79		1.81		3.26		4.29


	(% of Production)							(% of Production)
*Domestic*
Reserve replacement ratio, including acquisitions		188	%	84	%	255	%		220	%	195	%	240	%
Reserve replacement ratio, excluding acquisitions		162	%	77	%	129	%		195	%	188	%	114	%
*Worldwide*
Reserve replacement ratio, including acquisitions		212	%	17	%	252	%		245	%	192	%	237	%
Reserve replacement ratio, excluding acquisitions		187	%	11	%	129	%		220	%	186	%	114	%

We typically cite reserve replacement costs in the context of a multi-year trend, in recognition of its limitation as a single year measure, and also to demonstrate consistency and stability, which are essential to our business model. The table below shows our reserve replacement costs for our domestic and worldwide operations for the three years ended December 31, 2009.


	Including Price		Excluding Price
	Revisions		Revisions
	Three Years Ending December 31, 2009
	($/Mcfe)
*Domestic*
Reserve replacement costs, including acquisitions	$	3.33	$	2.70
Reserve replacement costs, excluding acquisitions		3.48		2.59
*Worldwide*
Reserve replacement costs, including acquisitions	$	4.10	$	2.94
Reserve replacement costs, excluding acquisitions		4.66		2.92

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


	2009		2008		2007
	(in millions)
Total oil and gas capital costs, excluding acquisitions	$	1,004	$	1,648	$	1,411
Acquisitions		87		51		1,178

Total oil and gas capital costs, including acquisitions⁽¹⁾	$	1,091	$	1,699	$	2,589


⁽¹⁾		^{Total oil and gas capital costs include the costs of development, exploration and property acquisition activities conducted to add reserves and exclude asset retirement obligations. Amounts are derived directly from the table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations.}

Outlook for 2010

For 2010, we anticipate continued volatility in the commodity markets and the general economic climate. We will exercise flexibility in allocating capital in response to changing conditions.

We expect the following on a worldwide basis:

	•		Capital expenditures, excluding acquisitions, of approximately $1.1 billion. Of this total, we expect to spend approximately $0.9 billion on our domestic program and approximately $0.2 billion in Brazil and Egypt.

	•		Average daily production volumes for the year of approximately 740 MMcfe/d to 780 MMcfe/d, which includes approximately 60 MMcfe/d to 65 MMcfe/d from Four Star. Production volumes from our Brazil operations are expected to increase to between 45 MMcfe/d and 55 MMcfe/d in 2010.

	•		Average cash operating costs between $1.85/Mcfe and $2.15/Mcfe for the year; and

	•		Depreciation, depletion and amortization rate between $1.65/Mcfe and $1.85/Mcfe.

Price Risk Management Activities

We enter into derivative contracts on our natural gas and oil production to stabilize cash flows, reduce the risk and financial impact of downward commodity price movements on commodity sales and to protect the economic assumptions associated with our capital investment programs. Because we apply mark-to-market accounting on our financial derivative contracts and because we do not hedge the entirety of our price risk, this strategy only partially reduces our commodity price exposure. Our reported results of operations, financial position and cash flows can be impacted significantly by commodity price movements from period to period. Adjustments to our strategy and the decision to enter into new positions or to alter existing positions are made based on the goals of the overall company.

During 2009, we entered into option and basis swap contracts on our 2010 and 2011 natural gas production and swaps on our 2010 oil production and paid $173 million in premiums to enter into these contracts.

The following table reflects the contracted volumes and the minimum, maximum and average prices we will receive under our derivative contracts as of December 31, 2009.


	Fixed Price
	Swaps⁽¹⁾				Floors⁽¹⁾				Ceilings⁽¹⁾				Basis Swaps⁽¹⁾⁽²⁾
																		Western										Central
													Texas Gulf Coast					Raton					Rockies					Mid-Continent
			Average				Average				Average				Average					Average					Average					Average
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price			Volumes		Price			Volumes		Price			Volumes		Price
Natural Gas
2010		52	$	6.19		123	$	6.50		60	$	8.14		48	$	(0.40	)		20	$	(0.78	)		9	$	(1.93	)		9	$	(0.74	)
2011		16	$	5.99		120	$	6.00		120	$	9.00		33	$	(0.13	)		7	$	(0.29	)		—		—			—		—
2012		2	$	3.93		—		—		—		—		—		—			—		—			—		—			—		—

Oil
2010		2,373	$	74.63		1,643	$	75.00		1,643	$	91.33


⁽¹⁾		^{Volumes presented are TBtu for natural gas and MBbl for oil. Prices presented are per MMBtu of natural gas and per Bbl of oil.}

⁽²⁾		^{Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences.}

Internationally, production from the Camarupim Field in Brazil is sold at a price that is adjusted quarterly based on a basket of fuel oil prices. In addition to the amounts included in the table above, as of December 31, 2009, we have fuel oil swaps that effectively lock in a price of approximately $4.00 per MMBtu on approximately 8 TBtu of projected Brazilian natural gas production in 2010.

During the first two months of 2010, we entered into 635 MBbls of fixed price swaps on our anticipated 2010 oil production at an average price of $85.18 per barrel. In addition, we entered into collars on 2,008 MBbls of our anticipated 2011 oil production with a floor price of $80 per barrel and an average ceiling price of $95.56 per barrel, and basis swaps at an average price of $0.21 per MMBtu on 15 TBtu of anticipated 2011 natural gas production.

Operating Results and Variance Analysis

The information below provides the financial results and an analysis of significant variances in these results during the periods ended December 31:


	2009			2008			2007
	(In millions)
Physical sales:
Natural gas	$	830		$	1,960		$	1,582
Oil, condensate and NGL		267			541			499

Total physical sales		1,097			2,501			2,081

Realized and unrealized gains on financial derivatives⁽¹⁾		687			196			184
Other revenues		44			65			35

Total operating revenues		1,828			2,762			2,300

Operating Expenses:
Cost of products		31			38			20
Transportation costs		66			79			72
Production costs		252			363			344
Depreciation, depletion and amortization		440			799			780
General and administrative expenses		195			160			185
Ceiling test charges		2,123			2,669			—
Impairment of inventory and other assets		25			—			—
Other		13			12			13

Total operating expenses		3,145			4,120			1,414

Operating income (loss)		(1,317	)		(1,358	)		886
Other income (expense)⁽²⁾		(32	)		(90	)		23

EBIT	$	(1,349	)	$	(1,448	)	$	909


⁽¹⁾		^{Includes $406 million, $(88) million and $176 million for the years ended December 31, 2009, 2008 and 2007, reclassified from accumulated other comprehensive income associated with accounting hedges.}

⁽²⁾		^{Other income includes equity earnings from Four Star, our unconsolidated affiliate, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets. In 2008, other income also includes a $125 million impairment charge related to our equity interest in Four Star.}


			Percent					Percent
	2009		Variance			2008		Variance			2007
Volumes:
Natural gas
Consolidated volumes (MMcf)		218,544		(6	)%		232,703		(4	)%		242,316
Unconsolidated affiliate volumes (MMcf)		19,557		(5	)%		20,576		6	%		19,380
Oil, condensate and NGL
Consolidated volumes (MBbls)		5,648		(13	)%		6,495		(17	)%		7,821
Unconsolidated affiliate volumes (MBbls)		1,097		4	%		1,054		4	%		1,015
Equivalent volumes
Consolidated MMcfe		252,432		(7	)%		271,673		(6	)%		289,242
Unconsolidated affiliate MMcfe		26,139		(3	)%		26,899		6	%		25,470

Total combined MMcfe		278,571		(7	)%		298,572		(5	)%		314,712

Consolidated MMcfe/d		691		(7	)%		742		(6	)%		792
Unconsolidated affiliate MMcfe/d		72		(3	)%		74		6	%		70

Total Combined MMcfe/d		763		(6	)%		816		(5	)%		862

Consolidated prices and costs per unit:
Natural gas
Average realized price on physical sales ($/Mcf)	$	3.80		(55	)%	$	8.43		29	%	$	6.53
Average realized prices, including financial derivative settlements ($/Mcf)⁽¹⁾	$	7.62		(7	)%	$	8.18		14	%	$	7.18
Average transportation costs ($/Mcf)	$	0.28		(10	)%	$	0.31		15	%	$	0.27
Oil, condensate and NGL
Average realized price on physical sales ($/Bbl)	$	47.27		(43	)%	$	83.21		31	%	$	63.71
Average realized price, including financial derivative settlements ($/Bbl)⁽¹⁾	$	78.38		1	%	$	77.78		25	%	$	62.19
Average transportation costs ($/Bbl)	$	0.77		(20	)%	$	0.96		19	%	$	0.81
Production costs and other cash operating costs ($/Mcfe)
Average lease operating expenses	$	0.78		(13	)%	$	0.90		2	%	$	0.88
Average production taxes⁽²⁾		0.22		(50	)%		0.44		42	%		0.31

Total production costs	$	1.00		(25	)%	$	1.34		13	%	$	1.19
Average general and administrative expenses	$	0.77		31	%	$	0.59		(8	)%	$	0.64
Average taxes, other than production and income taxes	$	0.05		25	%	$	0.04		(20	)%	$	0.05

Total cash operating costs	$	1.82		(8	)%	$	1.97		5	%	$	1.88

Depreciation, depletion and amortization ($/Mcfe)⁽³⁾	$	1.74		(41	)%	$	2.94		9	%	$	2.70


⁽¹⁾		^{Premiums related to natural gas derivatives settled during the year ended December 31, 2008 were $21 million. Had we included these premiums in our natural gas average realized prices in 2008, our realized price, including financial derivative settlements, would have decreased by $0.09/Mcf for the year ended December 31, 2008. We had no premiums related to natural gas derivatives settled during the years ended December 31, 2009 and 2007, or related to oil derivatives settled during the years ended December 31, 2009, 2008 and 2007.}

⁽²⁾		^{Production taxes include ad valorem and severance taxes.}

⁽³⁾		^{Includes $0.06 per Mcfe, $0.05 per Mcfe and $0.07 per Mcfe for the years ended December 31, 2009, 2008 and 2007 related to accretion expense on asset retirement obligations.}

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Our EBIT for 2009 increased $99 million as compared to 2008. The table below shows the significant variances in our financial results in 2009 as compared to 2008:


	Variance
	Operating			Operating
	Revenue			Expense			Other			EBIT
	Favorable/(Unfavorable)
	(In millions)
Physical sales
Natural gas
Lower realized prices in 2009	$	(1,011	)	$	—		$	—		$	(1,011	)
Lower volumes in 2009		(119	)		—			—			(119	)
Oil, condensate and NGL
Lower realized prices in 2009		(203	)		—			—			(203	)
Lower volumes in 2009		(71	)		—			—			(71	)
Realized and unrealized gains on financial derivatives		491			—			—			491
Other revenues		(21	)		—			—			(21	)
Depreciation, depletion and amortization expense
Lower depletion rate in 2009		—			305			—			305
Lower production volumes in 2009		—			54			—			54
Production costs
Lower lease operating expenses in 2009		—			46			—			46
Lower production taxes in 2009		—			65			—			65
General and administrative expenses		—			(35	)		—			(35	)
Ceiling test charges		—			546			—			546
Impairment of inventory and other assets		—			(25	)		—			(25	)
Earnings from unconsolidated affiliate		—			—			63			63
Other		—			19			(5	)		14

Total variances	$	(934	)	$	975		$	58		$	99

Physical sales. Physical sales represent accrual-based commodity sales transactions with customers. During the year ended December 31, 2009, natural gas, oil, condensate and NGL revenues decreased as compared to 2008 due to lower commodity prices and lower production volumes.

Realized and unrealized gains on financial derivatives. During the year ended December 31, 2009, we recognized net gains of $687 million compared to net gains of $196 million during 2008 due to lower natural gas and oil prices in 2009 relative to the commodity prices contained in our derivative contracts.

Depreciation, depletion and amortization expense. During 2009, our depreciation, depletion and amortization expense decreased as a result of a lower depletion rate and lower production volumes. The lower depletion rate is primarily a result of the impact of the ceiling test charges recorded in December 2008 and March 2009.

Production costs. Our production costs decreased during 2009 as compared to the same periods in 2008 primarily due to lower production taxes as a result of lower natural gas and oil revenues and lower lease operating expenses from cost declines in the lower commodity price environment.

General and administrative expenses. Our general and administrative expenses increased during 2009 as compared to the same periods in 2008 primarily due to the reversal of a $20 million accrual in 2008 as a result of a favorable ruling on a legal matter and higher severance costs of approximately $7 million due to reorganizations in 2009.

Ceiling test charges. We are required to conduct quarterly impairment tests of our capitalized costs in each of our full cost pools. During the fourth quarter of 2008 and the first quarter of 2009, we recorded total non-cash ceiling test charges of $2.7 billion and $2.1 billion. The calculation of these charges was based on spot commodity prices at the end of each period. In calculating our fourth quarter 2008 ceiling test charges, capitalized costs exceeded the ceiling limit by $2.2 billion for our domestic full cost pool and $0.5 billion for our Brazilian full cost pool. In the first quarter of 2009, due to low natural gas and oil prices, we experienced a downward price-related reserve revision of approximately 400 Bcfe (primarily in our Arklatex, Raton and Mid-Continent areas) and recorded non-cash ceiling test charges of approximately $2.0 billion in our domestic full cost pool and $28 million in our Brazilian full cost pool.

During the fourth quarter of 2009, primarily due to proved reserve additions, we did not record ceiling test charges in our domestic full cost pool; however, we recorded a $30 million ceiling test charge in our Brazilian full cost pool as a result of lower commodity prices and a downward performance-related reserve revision in our Pescada-Arabaiana Fields.

As a result of the SEC’s final rule on the Modernization of Oil and Gas Reporting, effective December 31, 2009, we were required to use a 12-month average price (calculated as the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period) when performing the ceiling tests. In calculating our ceiling test charges, we are also required to hold prices constant over the life of the reserves, even though actual prices of natural gas and oil are volatile and change from period to period. For more information on the first day 12-month average price used to calculate the ceiling test, see Supplemental Natural Gas and Oil Operations.

During 2009 and 2008, we also recorded non-cash ceiling test charges in our Egyptian full cost pool of $34 million and $9 million. These charges were primarily as a result of dry hole costs on unsuccessful wells drilled during these years.

Impairment of inventory and other assets. In 2009, we recorded a $16 million non-cash charge to reflect the current market price we expect to receive upon the sale of certain casing and tubular goods inventory (materials and supplies), which prior to the third quarter, we intended to use in our capital programs. Based on changes to our capital program we decided that we would sell this inventory and use the proceeds to purchase inventory related to our current capital projects. We also recorded a $9 million non-cash charge as a result of our decision to close our Bluebell processing plant in 2010.

Other. Our equity earnings from Four Star increased by $63 million during the year ended December 31, 2009 as compared to 2008 primarily due to an impairment of the carrying value of our investment of $125 million recorded in 2008, partially offset by the impact of lower commodity prices in 2009.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Our EBIT for 2008 decreased $2,357 million as compared to 2007. The table below shows the significant variances in our financial results in 2008 as compared to 2007:


	Variance
	Operating			Operating
	Revenue			Expense			Other			EBIT
	Favorable/(Unfavorable)
	(In millions)
Physical sales
Natural gas
Higher realized prices in 2008	$	441		$	—		$	—		$	441
Lower volumes in 2008		(63	)		—			—			(63	)
Oil, condensate and NGL
Higher realized prices in 2008		127			—			—			127
Lower volumes in 2008		(85	)		—			—			(85	)
Realized and unrealized gains on financial derivatives		12			—			—			12
Other revenues		30			—			—			30
Depreciation, depletion and amortization expense
Higher depletion rate in 2008		—			(64	)		—			(64	)
Lower production volumes in 2008		—			45			—			45
Production costs
Lower lease operating expenses in 2008		—			10			—			10
Higher production taxes in 2008		—			(29	)		—			(29	)
General and administrative expenses		—			25			—			25
Ceiling test charges		—			(2,669	)		—			(2,669	)
Earnings from unconsolidated affiliate		—			—			(104	)		(104	)
Other		—			(24	)		(9	)		(33	)

Total variances	$	462		$	(2,706	)	$	(113	)	$	(2,357	)

Physical sales. Physical sales represent accrual-based commodity sales transactions with customers. During 2008, revenues increased as compared with 2007 due primarily to higher commodity prices. During the year ended December 31, 2008, we also benefited from an increase in production volumes in all of our domestic divisions compared to 2007 primarily as a result of successful drilling programs and our Peoples acquisition in the third quarter of 2007. Our Gulf Coast division production volumes decreased in 2008 versus 2007 primarily due to asset sales, production shut in as a result of Hurricanes Ike and Gustav and natural production declines.

Realized and unrealized gains on financial derivatives. During the year ended December 31, 2008, we recognized net gains of $196 million compared to net gains of $184 million during 2007 due to natural gas and oil prices in 2008 relative to the commodity prices contained in our derivative contracts.

Depreciation, depletion and amortization expense. During 2008, our depletion rate increased as compared to the same period in 2007 as a result of the Peoples and Zapata County, Texas acquisitions in 2007 and higher finding and development costs.

Production costs. Our production costs increased during 2008 as compared to 2007 primarily due to higher production taxes which increased due to higher natural gas and oil revenues. The increase in production taxes was partially offset by a reduction in lease operating expenses for the year ended December 31, 2008, primarily as a result of the impact of divested properties.

General and administrative expenses. Our general and administrative expenses decreased during 2008 as compared to the same periods in 2007 primarily due to the reversal of a $20 million accrual as a result of a favorable ruling on a legal matter.

Ceiling test charges. In the fourth quarter of 2008, we recorded non-cash full cost ceiling test charges of $2.7 billion. Capitalized costs exceeded the ceiling limit by $2.2 billion for our domestic full cost pool and $0.5 billion for our Brazilian full cost pool. The calculation of these charges was based on the December 31, 2008 spot natural gas price of $5.71 per MMBtu and oil price of $44.60 per barrel, as required at that time. In calculating our ceiling test charges, we were required to hold prices constant over the life of the reserves, even though actual prices of natural gas and oil are volatile and change from period to period.

Prior to the fourth quarter of 2008, we included derivatives that were designated as accounting hedges in the determination of our future net revenues for purposes of calculating our ceiling tests. During the fourth quarter of 2008, we removed the hedging designation on all of our commodity-based derivative contracts related to our hedged natural gas and oil production volumes. We estimate that had we chosen not to de-designate these hedges, our ceiling test charges as of December 31, 2008 would have been lower by approximately $400 million.

Other. Our equity earnings from Four Star in 2008 decreased as compared to 2007 due primarily to a $125 million impairment of the carrying value of our investment based on a decline in its fair value as a result of lower forecasted commodity prices.

Marketing Segment

Our Marketing segment’s primary focus is to market our Exploration and Production segment’s natural gas and oil production and to manage El Paso’s overall price risk. In addition, we continue to manage and liquidate remaining legacy contracts which were primarily entered into prior to the deterioration of the energy trading environment in 2002. All of our remaining contracts are subject to counterparty credit and non-performance risks while our remaining mark-to-market contracts are also subject to interest rate exposure.

Legacy power contracts. The primary exposure remaining in the Marketing segment relates to mark-to-market power contracts that extend through April 2016. The exposure relates to volatility in locational power prices within the Pennsylvania-New Jersey-Maryland (PJM region).

Legacy transportation-related contracts. The impact of these accrual-based contracts is based on our ability to use or remarket the contracted pipeline capacity. As of December 31, 2009, these contracts require us to pay demand charges of $47 million in 2010 and an average of $41 million between 2011 and 2014. Additionally, in the fourth quarter of 2009, we entered into an agreement associated with the Ruby pipeline project that commences in 2016 and continues through 2021.

Legacy natural gas contracts. As of December 31, 2009, we have long term gas supply contracts that obligate us to deliver natural gas to specified power plants. The accounting on these contracts is a combination of mark-to-market and accrual-based. These are expected to have minimal future impact on this segment as we have substantially offset all of the fixed price exposure.

Operating Results

Overview. Our overall operating results and analysis by significant contract type for our Marketing segment during each of the three years ended December 31 are as follows:


	2009			2008			2007
	(In millions)
Revenue by Significant Contract Type:
Production-Related Natural Gas and Oil Derivative Contracts:
Changes in fair value of options and swaps	$	—		$	(50	)	$	(89	)
Contracts Related to Legacy Trading Operations:
Changes in fair value of power contracts		44			(46	)		(77	)
Natural gas transportation-related contracts:
Demand charges		(35	)		(35	)		(98	)
Settlements, net of termination payments		23			41			76
Changes in fair value of other natural gas derivative contracts		(3	)		7			(31	)

Total revenues		29			(83	)		(219	)
Operating expenses		(9	)		(20	)		(15	)

Operating income (loss)		20			(103	)		(234	)
Other income, net		—			(1	)		32

EBIT	$	20		$	(104	)	$	(202	)

Our 2009 results were primarily driven by a $52 million mark-to-market gain related to the adoption of new accounting requirements for our derivative liabilities associated with non-cash collateral (e.g. letters of credit) partially offset by $27 million related to the impact of El Paso’s credit standing on our derivative liabilities. Our 2008 and 2007 results were significantly impacted by mark-to-market losses on
production-related natural gas and crude contracts that we held and managed during these years and losses of $46 million and $100 million in 2008 and 2007 due to changes in fair value of our PJM contracts. Additionally, in 2008 we signed a capacity purchase agreement that was executed to reduce our exposure to installed capacity prices which contributed to the losses recognized during 2007 and also recorded $19 million of revenue related to bankruptcy settlements. Additional items impacting our 2007 results were $23 million of other income from the sale of an investment and $28 million ($23 million of revenues and $5 million of other income) related to the settlement of outstanding California power price disputes.

Power Segment

Overview. As of December 31, 2009, our remaining investment, guarantees and letters of credit related to projects in this segment totaled approximately $174 million, which consisted primarily of equity investments, notes and accounts receivable as follows:


Area	Amount
	(In millions)
South America
Manaus & Rio Negro	$	52
Bolivia-to-Brazil Pipeline		117
Asia		5

Total	$	174

For the years ended December 31, 2009, 2008, and 2007, our Power segment generated an EBIT loss of $25 million, EBIT of $1 million, and an EBIT loss of $37 million. Our 2009 EBIT loss primarily relates to a loss on the sale of the Porto Velho notes receivable during 2009. Our 2007 EBIT loss was primarily due to impairments of $57 million on Porto Velho and $15 million on the Manaus and Rio Negro project offset by $30 million in EBIT generated on Porto Velho prior to the impairment and $9 million from our Manaus and Rio Negro project. Beginning in 2007, we ceased recognizing earnings from our Porto Velho project based on our inability to realize those earnings through the expected sales price of the investment. In 2007, our other Brazilian operations generated EBIT of $12 million.

In 2008, we transferred the ownership of our Manaus and Rio Negro power plants in Brazil to the plants’ power purchaser. While we no longer own the plants, we still have exposure relating to outstanding Brazilian reais-denominated receivables due from the power purchaser. We are also in the process of trying to resolve several outstanding claims related to these projects. In early 2009, we completed the sale of our investment in the Porto Velho power generation facility in Brazil to our partner in the project for cash and a notes receivable. In the second quarter of 2009, we sold the notes, including accrued interest, to a third party financial institution for $57 million and recorded a loss of $22 million. In 2009, we also sold our investment in the Argentina-to-Chile pipeline to our partners for approximately $32 million. Until the sale of our remaining international investments is completed, the Manaus and Rio Negro receivables are collected or matters further discussed in Item 8, Financial Statements and Supplementary Data, Note 19 are resolved, any changes in regional political and economic conditions could negatively impact the anticipated proceeds we may receive, which could result in impairments of our remaining assets and investments.

Corporate and Other Expenses, Net

Our corporate activities include our general and administrative functions as well as a number of miscellaneous businesses, which do not qualify as operating segments and are not material to our current year results. The following is a summary of significant items impacting the EBIT in our corporate activities for each of the three years ended December 31:


	2009		2008		2007
	(In millions)
Early extinguishment/exchange of debt	$	—	$	—	$	(291	)
Foreign currency fluctuations on Euro-denominated debt		2		—		(8	)
Change in litigation, environmental and other reserves		2		84		23
Gain on the sale of legacy assets		—		35		—
Other		4		5		(7	)

Total EBIT	$	8	$	124	$	(283	)

Litigation, Environmental, and Other Reserves. During the year ended December 31, 2009, we recorded mark-to-market gains of $21 million associated with an indemnification in conjunction with the sale of a legacy ammonia facility based on fluctuations in ammonia prices. We also recorded $16 million in additional estimated environmental remediation costs related to a legacy non-operating chemical plant. During 2008, we recorded favorable adjustments related to resolving certain legacy litigation matters including $65 million related to our Case Corporation indemnification dispute (see Item 8, Financial Statements and Supplementary Data, Note 13) and $32 million related to the settlement of certain class action matters. Partially offsetting these 2008 settlements were approximately $46 million in mark-to-market losses based on significant increases in ammonia prices during the first quarter of 2008. Changes in ammonia prices will continue to impact this contract, which could affect our results in the future.

During 2007, we recorded a gain of approximately $77 million on the reversal of a liability related to The Coastal Corporation’s legacy crude oil marketing and trading business.

We have a number of pending litigation matters and reserves related to our historical business operations that affect our corporate results. Adverse rulings or unfavorable outcomes or settlements against us related to these matters have impacted and may continue to impact our future results.

In addition to these matters, we anticipate an increase in our non-cash pension costs of approximately $40 million during 2010 primarily as a result of our pension plan asset performance during 2008. Overall losses on our pension assets will be amortized into our future net benefit cost through 2011. Despite the increased expense, we do not anticipate making any contributions to our primary pension plan in 2010. For further discussion of our primary pension plan and related net benefit cost, see Item 8, Financial Statements and Supplementary Data, Note 14.

Extinguishment of Debt. During 2007, we incurred losses of $291 million in conjunction with repurchasing or refinancing more than $5 billion of our debt. For further information on our debt, see Item 8, Financial Statements and Supplementary Data, Note 12.

Interest and Debt Expense

Our interest and debt expense for the years ended December 31, 2009, 2008 and 2007 was $1.0 billion, $0.9 billion and $1.0 billion. During 2009, our interest and debt expense increased as compared to the prior year due primarily to higher interest rates and amortization of discounts related to debt issuances and other financing obligations, net of retirements. During 2008, our interest and debt expense decreased as compared to 2007 primarily due to debt repurchases in 2007 and 2008, net of issuances. See Item 8, Financial Statements and Supplementary Data, Note 12, for a further discussion.

Income Taxes


	Years Ended December 31,
	2009			2008			2007
	(In millions)
Income tax expense (benefit)	$	(399	)	$	(245	)	$	222
Effective tax rate		46	%		24	%		33	%

In 2009, our overall effective tax rate on continuing operations differed from the statutory rate due primarily to recording an $88 million income tax benefit relating to a U.S. tax loss on the liquidation of certain foreign entities. Following the 2009 sale of the remaining significant non-core international power projects, these entities had no liquidating value. As these entities had tax basis, the liquidation resulted in a tax loss. In 2008, our overall effective tax rate on continuing operations differed from the statutory rate due primarily to: (i) a Brazilian ceiling test charge in our exploration and production operations that did not have a corresponding U.S. or Brazilian tax benefit and (ii) the establishment of a valuation allowance against deferred tax assets (associated with Brazilian net operating losses) based on uncertainties about our ability to realize these assets. In 2007, our overall effective tax rate on continuing operations was impacted primarily by earnings from unconsolidated affiliates where we anticipate receiving dividends that qualify for the dividend received deduction. For a discussion of these and other items affecting our effective tax rates in each year and other tax matters, see Item 8, Financial Statements and Supplementary Data, Note 5.

Discontinued Operations

In 2007, our income from discontinued operations was due to a gain on the sale of ANR and related operations of $648 million, net of income taxes of $354 million as further discussed in Item 8, Financial Statements and Supplementary Data, Note 2.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 13.

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. These measures include the Kyoto Protocol, which has been ratified by some of the international countries in which we have operations such as Mexico, Brazil, and Egypt. Over 50 countries, including the U.S. and Brazil, 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, our operations in the United States emitted approximately 13.9 million tonnes of carbon dioxide equivalent emissions during 2008. We believe that approximately 10.7 to 12.4 million tonnes of these GHG emissions, depending on how the legislation is interpreted, 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 4.5 million tonnes 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 costs of operations. Although we believe that many of these costs should be recoverable in our sales price for natural gas and the rates charged by our pipelines, recovery through these mechanisms 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 and construction projects remains uncertain.

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 engines 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 $60 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.

Liquidity and Capital Resources

Our continued focus has been on expanding our core pipeline and exploration and production businesses and to build liquidity to fund that growth. Our primary sources of cash are cash flows generated from our operations and amounts available to us under our revolving credit facilities. As conditions warrant, we may also generate funds through additional bank financings, project financings, capital market activities and asset sales. Our primary uses of cash are funding the capital expenditure programs, meeting operating needs and repaying debt when due or repurchasing debt when conditions warrant. We believe we are well positioned in 2010 to meet these obligations based on the anticipated performance of our core businesses, our financing actions taken to date or planned in 2010, and the additional steps we announced in November 2009 to enhance our liquidity.

Available Liquidity and Liquidity Outlook for 2010. At December 31, 2009, we had available liquidity of approximately $1.8 billion (approximately $0.5 billion cash, $1.3 billion of available credit facility), exclusive of approximately $0.4 billion of combined cash /credit facility capacity of EPB and Ruby. In 2009, we took a number of actions to generate additional liquidity and address the instability in the global financial markets including reducing our 2009 capital program, obtaining a 50 percent partner on our Ruby pipeline project (as further described below) and raising $2.1 billion of net liquidity in financings. These 2009 financings included (i) the issuance of approximately $500 million of El Paso notes and $250 million of TGP notes, (ii) completing two additional facilities that provide a combined $300 million of letter of credit capacity, (iii) completing $300 million of financings related to our Elba Island LNG facility and Elba Express pipeline project, (iv) extending our $300 million El Paso Exploration and Production Company 364-day revolving credit facility without any additional collateral requirements to maintain the current borrowing base, (v) raising $215 million in conjunction with contributing additional interests in CIG to our master limited partnership, and (vi) selling approximately $300 million of non-core assets.

Our 2010 capital programs anticipate planned cash capital expenditures in our operations as follows:


	Total
	(In billions)
Pipelines
Maintenance	$	0.4
Growth⁽¹⁾		2.5
Exploration and Production		1.1
Other		0.1

	$	4.1


(1)		^{Our pipeline growth capital expenditures reflect 100 percent of the capital related to the Ruby pipeline project. In 2009, we obtained a partner on this project as described below.}

Although our 2010 pipeline capital requirements are significant, our 2011 requirements decline significantly, and by the end of 2011 most of our backlog will be placed in service. Our capital program is designed to deliver on our pipeline expansion backlog while keeping our exploration and production capital spend levels essentially consistent with 2009, allowing for continued reserve growth. In addition to our capital needs, in 2010 we have approximately $250 million of debt (excluding Ruby debt of approximately $217 million which we anticipate will convert into Ruby preferred equity) that will mature; however, our primary revolving credit facility is not scheduled for renewal until late 2012.

We plan to meet these requirements through a variety of measures in 2010 which include (i) generating positive operating cash flows from our core operations (ii) raising approximately $1.5 billion in third party financing for Ruby expected to close in the first half of 2010 (of which we expect to borrow approximately $1 billion in 2010), (iii) receiving approximately $300 million in committed funding from Global Infrastructure Partners (GIP) for the Ruby project, and (iv) selling $300 million to $500 million of assets. We will also consider additional opportunities with our MLP as the markets permit.

In November 2009, we announced additional actions for 2010 to provide incremental funding and further improve our financial flexibility, including a reduction of $150 million in annual operating and administrative expenses, the sale of $300 million to $500 million of assets, and a reduction in our quarterly dividend for annual cash savings of approximately $112 million. As part of this plan, in February 2010 we entered into an agreement to sell our interest in Mexican pipeline and compression assets for $300 million which is expected to close in the second quarter of 2010 subject to lender consent and Mexican regulatory approval.

We believe the actions planned for 2010 will provide sufficient liquidity to meet our operating, financing and capital needs in 2010. However, there are a number of factors that could impact our plans, including our ability to access the financial markets to fund our long-term capital needs if the financial markets are restricted, a further decline in commodity prices, or if any of our announced actions are not sufficient. If these events occur, additional adjustments to our plan and outlook may be required which could impact our financial and operating performance including reductions in our discretionary capital program, further reductions in operating and general and administrative expenses, obtaining secured financing arrangements, seeking additional partners for other growth projects and the sale of additional non-core assets.

Ruby financing. During the third quarter of 2009, we entered into an agreement with several infrastructure funds managed by GIP, whereby they will invest up to $700 million in Ruby Pipeline Holding Company L.L.C. (Ruby) in three major tranches including (i) a series of 7 percent loans totaling $405 million ($217 million of which has been borrowed as of December 31, 2009), which will be converted into a preferred equity interest in Ruby upon satisfaction of certain conditions, (ii) $145 million which was contributed in October 2009 as a convertible preferred equity interest in Ruby and simultaneously exchanged for a convertible preferred equity interest in Cheyenne Plains Investment Company (“Cheyenne Plains”) with a 15 percent rate of return until the Ruby pipeline project is placed in-service, among other conditions and (iii) up to an additional $150 million of convertible preferred equity to be made to Ruby under the conditions that all FERC approvals for construction of the project are obtained and third party financing of approximately $1.4 billion is secured by Ruby by December 2010. The convertible preferred equity interest in Ruby will earn a 13 percent yield beginning at final project completion. GIP will have the right to convert its preferred equity to common equity in Ruby at any time. However, the preferred equity is subject to a mandatory conversion to common equity upon the satisfaction of certain conditions, including Ruby entering into additional firm transportation agreements.

If all conditions to closing are satisfied or waived, at the time of project completion, GIP would own a 50 percent equity interest in Ruby and all ownership in Cheyenne Plains would be transferred back to us. However, the GIP preferred equity interests in Ruby and Cheyenne Plains, amounts borrowed under GIP’s loan commitment to Ruby and a 15 percent return on all outstanding amounts, must be repaid in cash to GIP if (i) all FERC approvals for construction of the Ruby pipeline project are not obtained by December 2010, (ii) third party financing of approximately $1.4 billion is not secured by Ruby by December 2010 or (iii) the Ruby pipeline project is not placed in-service within 16 months of obtaining all FERC approvals. Additionally, if the financings are not completed, GIP has the option to convert its preferred interest in Cheyenne Plains to a 50 percent common interest in Cheyenne Plains. Our obligation to repay these amounts is secured by our equity interests in Ruby, Cheyenne Plains, and approximately 50 million common units we own in our MLP.

Overview of 2009 Cash Flow Activities. During 2009, we generated positive operating cash flow of approximately $2.1 billion primarily from our pipeline and exploration and production operations. We also generated approximately $0.3 billion from the sale of certain non-core power and exploration and production assets and $1.6 billion from debt issuances in 2009 (including consolidated project financings). We utilized these amounts to fund our capital programs, refinance 2009 debt maturities of $1.0 billion, and pay common and preferred dividends, among other items. For the year ended December 31, 2009 and 2008, our cash flows from continuing operations are summarized as follows:


	2009			2008
	(In billions)
Cash Flow from Operations
Continuing operating activities
Loss from continuing operations	$	(0.5	)	$	(0.8	)
Ceiling test charges		2.1			2.7
Other income adjustments		0.5			1.2
Change in other assets and liabilities		—			(0.7	)

Total cash flow from operations	$	2.1		$	2.4


Other Cash Inflows
Continuing investing activities
Net proceeds from the sale of assets and investments	$	0.3		$	0.7
Other		0.1			0.1

		0.4			0.8


Continuing financing activities
Net proceeds from the issuance of long-term debt		1.6			4.6
Net proceeds from issuance of noncontrolling interests		0.2			—
Net proceeds from issuance of preferred stock of subsidiary		0.1			—

		1.9			4.6

Total other cash inflows	$	2.3		$	5.4


Cash Outflows
Continuing investing activities
Capital expenditures	$	2.8		$	2.8
Cash paid for acquisitions		0.1			0.4

		2.9			3.2


Continuing financing activities
Payments to retire long-term debt and other financing obligations⁽¹⁾		1.7			3.7
Dividends and other		0.2			0.2

		1.9			3.9

Total cash outflows	$	4.8		$	7.1

Net change in cash	$	(0.4	)	$	0.7

Off-Balance Sheet Arrangements

We enter into a variety of financing arrangements and contractual obligations, some of which are referred to as off-balance sheet arrangements. These include guarantees, letters of credit and other interests in variable interest entities.

Guarantees and Indemnifications

We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.

Our potential exposure under guarantee and indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. Those arrangements with a specified dollar amount have a maximum stated value of approximately $0.8 billion, which primarily relates to indemnification arrangements associated with the sale of ANR, our Macae power facility in Brazil, and other legacy assets. These amounts exclude guarantees for which we have issued related letters of credit discussed in Item 8, Financial Statements and Supplementary Data, Note 12. Included in the above maximum stated value are certain indemnification agreements that have expired; however, claims were made prior to the expiration of the related claim periods. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

As of December 31, 2009, we have recorded obligations of $52 million related to our guarantee and indemnification arrangements. This liability consists primarily of an indemnification that one of our subsidiaries provided related to its sale of an ammonia facility that is reflected in our financial statements at its fair value. We have provided a partial parental guarantee of our subsidiary’s obligations under this indemnification.

Letters of Credit

We enter into letters of credit in the ordinary course of our operations as well as periodically in conjunction with sales of assets or businesses. As of December 31, 2009, we had outstanding letters of credit of approximately $1.3 billion, including $0.7 billion of letters of credit securing our recorded obligations related to price risk management activities. For additional information on our counterparty credit and nonperformance risk, see Item 8, Financial Statements and Supplementary Data, Note 7. Depending on changes in commodity prices or interest rates, we could be required to post additional margin or may recover margin earlier than anticipated. A 10 percent change in natural gas and power prices would not have had a significant impact on the margin requirements of our derivative contracts as of December 31, 2009.

Interests in Variable Interest Entities

We have interests in several variable interest entities, primarily in Ruby. A variable interest entity is a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. We are required to consolidate such entities if we are allocated the majority of the variable interest entity’s losses or return, including any fees paid by the entity. As of December 31, 2009, there were no significant variable interest entities that we did not consolidate. For additional information regarding our interest in Ruby, see Item 8, Financial Statements and Supplementary Data, Note 18, Variable Interest Entities and Qualifying Special Purpose Entities.

Contractual Obligations

We are party to various contractual obligations, which include the off-balance sheet arrangements described above. A portion of these obligations are reflected in our financial statements, such as long-term debt, liabilities from commodity-based derivative contracts and other accrued liabilities, while other obligations, such as demand charges under transportation and storage commitments, operating leases and capital commitments, are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2009, for each of the periods presented:


	Due in Less		Due in 1 to		Due in 3 to
	than 1 Year		3 Years		5 Years		Thereafter		Total
					(In millions)
Long-term financing obligations:
Principal	$	477	$	2,985	$	1,097	$	9,423	$	13,982
Interest		989		1,809		1,541		7,246		11,585
Liabilities from commodity-based derivative contracts		262		280		107		65		714
Other contractual liabilities		102		217		27		37		383
Operating leases		14		25		22		20		81
Other contractual commitments and purchase obligations:
Transportation and storage		71		158		135		279		643
Other		1,453		440		73		259		2,225

Total contractual obligations	$	3,368	$	5,914	$	3,002	$	17,329	$	29,613

Long-term Financing Obligations (Principal and Interest). Debt obligations included in the table above represent stated maturities unless the instrument is otherwise puttable to us prior to their stated maturity date. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual interest rate for fixed rate debt and (ii) current market interest rates and the contractual credit spread for variable rate debt. For a further discussion of our debt obligations, see Item 8, Financial Statements and Supplementary Data, Note 12.

Liabilities from Commodity-Based Derivative Contracts. These amounts only include the fair value of our price risk management liabilities. The fair value of our commodity-based price risk management assets of $333 million as of December 31, 2009 is not reflected in these amounts. We have also excluded margin and other deposits held associated with these contracts from these amounts. For a further discussion of our commodity-based derivative contracts, see the discussion of commodity-based derivative contracts below.

Other Contractual Liabilities. Included in this amount are contractual, environmental and other obligations included in other current and non-current liabilities in our balance sheet. We have excluded from these amounts expected contributions to our pension and other postretirement benefit plans because these expected contributions are not contractually required. For further information on our expected contributions to our pension and post retirement benefit plans, see Item 8, Financial Statements and Supplementary Data, Note 14. We have also excluded from these amounts liabilities for unrecognized tax benefits of $260 million as of December 31, 2009, since we cannot reasonably estimate the time frame over which these amounts may be resolved.

Operating Leases. For a further discussion of these obligations, see Item 8, Financial Statements and Supplementary Data, Note 13.

Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:

•

Transportation and Storage Commitments. Included in these amounts are commitments for demand charges for firm access to natural gas transportation and storage capacity.

•

Other Commitments. Included in these amounts are commitments for purchasing pipe and related assets in our pipeline operations, commitments for drilling and seismic activities in our exploration and production operations and various other maintenance, engineering, procurement and construction contracts, as well as service and license agreements used by our other operations. Also included are long-term commitments by us related to right of way payments as further discussed in Item 8, Financial Statements and Supplementary Data, Note 13. We have excluded asset retirement obligations and reserves for litigation, environmental remediation and self-insurance claims, other than those disclosed above, as these liabilities are not contractually fixed as to timing and amount.

Commodity-Based Derivative Contracts. We use derivative financial instruments in our Exploration and Production and Marketing segments to manage the price risk of commodities. Our commodity-based derivative contracts are not currently designated as accounting hedges and include options, swaps and other natural gas, oil and power purchase and supply contracts that are not traded on active exchanges. The following table details the fair value of our commodity-based derivative contracts by year of maturity as of December 31, 2009:


	Maturity			Maturity			Maturity			Maturity			Total
	Less Than			1 to 3			4 to 5			6 to 10			Fair
	1 Year			Years			Years			Years			Value
							(In millions)
Assets	$	220			99			5			9		$	333
Liabilities		(262	)		(280	)		(107	)		(65	)		(714	)

Total commodity-based derivatives	$	(42	)		(181	)		(102	)		(56	)	$	(381	)

The following is a reconciliation of our commodity-based derivatives for the years ended December 31, 2009 and 2008:


				Other			Total
				Commodity-			Commodity-
	Derivatives Designated			Based			Based
	as Accounting Hedges			Derivatives			Derivatives
				(In millions)
Fair value of contracts outstanding at December 31, 2007	$	(23	)	$	(869	)	$	(892	)

Fair value of contracts settled		88			257			345
Changes in fair value of contracts		309			197			506
Reclassification of de-designated hedges		(395	)		395			—
Net option premiums paid (received)		21			(5	)		16

Net change in contracts outstanding during the period		23			844			867

Fair value of contracts outstanding at December 31, 2008		—			(25	)		(25	)

Fair value of contracts settled		—			(851	)		(851	)
Changes in fair value of contracts		—			322			322
Net option premiums paid		—			173			173

Net change in contracts outstanding during the period		—			(356	)		(356	)

Fair value of contracts outstanding at December 31, 2009	$	—		$	(381	)	$	(381	)

Fair Value of Contract Settlements. The fair value of contract settlements during the period represents the estimated amounts of derivative contracts settled through physical delivery of a commodity or by a claim to cash as accounts receivable or payable, and also includes physical or financial contract terminations due to counterparty bankruptcies and the sale or settlement of derivative contracts through early termination or through the sale of the entities that own these contracts, including amounts received from the sale of option contracts.

Changes in Fair Value of Contracts. The change in fair value of contracts during the year represents the change in value of contracts from the beginning of the period, or the date of their origination or acquisition, until their settlement, early termination or, if not settled or terminated, until the end of the period.

Reclassifications of De-designated Hedges. During the fourth quarter of 2008, we removed the hedging designation on all of our commodity-based derivative contracts related to our hedged natural gas and oil production volumes.

Critical Accounting Estimates

Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of our Board of Directors.

Accounting for Natural Gas and Oil Producing Activities. Our estimates of proved reserves reflect quantities of natural gas, oil and NGL which geological and engineering data demonstrate, with reasonable certainty, will be recoverable in future years from known reservoirs under existing economic conditions. The process of estimating natural gas and oil reserves, is complex, requiring significant judgment in the evaluation of all available geological, geophysical engineering and economic data. Our proved reserves are estimated at a property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers who work closely with the operating groups. These engineers interact with engineering and geoscience personnel in each of our operating areas and accounting and marketing personnel to obtain the necessary data for projecting future production, costs, net revenues and ultimate recoverable reserves. Reserves are reviewed internally with senior management quarterly and presented to our Board of Directors in summary form on an annual basis. Additionally, on an annual basis each property is reviewed in detail by our centralized and operating divisional engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable. Our proved reserves are also reviewed by internal committees and the processes and controls used for estimating our proved reserves are reviewed by our internal auditors. In addition, a third-party reservoir engineering firm, which is appointed by and reports to the Audit Committee of our Board of Directors, conducts an audit of the estimates of a significant portion of our proved reserves. In particular, Ryder Scott Company, L.P. conducted an audit of our estimates of proved reserves as of December 31, 2009.

As of December 31, 2009, of our total consolidated proved reserves, 33 percent were undeveloped (31 percent including Four Star) and 14 percent were developed, but non-producing. The data for a given field may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. In addition, the subjective decisions and variances in available data for various fields increase the likelihood of significant changes in these estimates.

The estimates of proved natural gas and oil reserves primarily impact our property, plant and equipment amounts in our balance sheets and the depreciation, depletion and amortization amounts and any ceiling test charges in our income statements, among other items. We use the full cost method to account for our natural gas and oil producing activities. Under this accounting method, we capitalize substantially all of the costs incurred in connection with the acquisition, exploration and development of natural gas and oil reserves, including salaries, benefits and other internal costs directly related to these finding activities, asset retirement costs and capitalized interest. Capitalized costs are maintained in full cost pools by geographic area, regardless of whether reserves are actually discovered. We record depletion expense of these capitalized amounts plus estimated finding and development costs over the life of our proved reserves based on the unit of production method. If all other factors are held constant, a 10 percent increase in estimated proved reserves would decrease our unit of production depletion rate by 9 percent and a 10 percent decrease in estimated proved reserves would increase our unit of depletion rate by 11 percent. For more information regarding price sensitivities related to our estimated proved reserves, see Part I, Item 1. Business, Natural Gas and Oil Properties.

Natural gas and oil properties include unproved property costs that are excluded from costs being depleted. These unproved property costs include non-producing leasehold, geological and geophysical costs associated with unevaluated leasehold or drilling interests and exploration drilling costs in investments in unproved properties and major development projects in which we own a direct interest. We exclude these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if exclusion from the full-cost pool continues to be appropriate. If costs are determined to be impaired, the amount of any impairment is transferred to the full cost pool if a reserve base exists or is expensed if a reserve base has not yet been created. Impairments transferred to the full cost pool increase the depletion rate for that country.

Under the full cost accounting method for natural gas and oil properties, we are required to conduct quarterly impairment tests of our capitalized costs in each of our full cost pools. This impairment test is referred to as a ceiling test. Our total capitalized costs, net of related deferred income taxes, are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the cost of unproved natural gas and oil properties not being amortized less related income tax effects. On December 31, 2009, we adopted the provisions of the SEC’s final rule on Modernization of Oil and Gas Reporting. Among other things, the final rule revised the definition of proved reserves and required us to use a first day 12-month average price in calculating the ceiling test and estimating proved reserves rather than a period end spot price as required in prior periods. If the discounted future net cash flows are not greater than or equal to the total capitalized costs, we are required to write-down our capitalized costs to this level of discounted future net cash flows.

Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standard Board (FASB) accounting standards for rate-regulated operations. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of accounting standards related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.

Accounting for Legal and Environmental Reserves, Guarantees and Indemnifications. We accrue legal and environmental reserves when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated. Estimates of our liabilities are based on an evaluation of potential outcomes, currently available facts, and in the case of environmental reserves, existing technology and presently enacted laws and regulations taking into consideration the likely effects of societal and economic factors, estimates of associated onsite, offsite and groundwater technical studies and legal costs. Actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon actual outcomes or changes in expectations based on the facts surrounding each matter.

As of December 31, 2009, we had accrued approximately $67 million for legal matters, which has not been reduced by $1 million of related insurance receivables, and $189 million for environmental matters, which has not been reduced by $24 million for amounts to be paid directly under government sponsored programs or through settlement arrangements. Our environmental estimates range from approximately $189 million to approximately $381 million and the amounts we have accrued represent a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($10 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($179 million to $371 million) and the lower end of the expected range has been accrued.

We also have guarantee and indemnification agreements related to various joint ventures and other ownership arrangements that require us to assess our potential exposure. This exposure can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. For those arrangements with a specified dollar amount, we have a maximum stated value of approximately $0.8 billion. As of December 31, 2009, we have recorded obligations of $52 million related to our guarantee and indemnification arrangements. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments under the agreement due to the uncertainty of these exposures. For further information, see Off Balance Sheet Arrangements above.

Accounting for Pension and Other Postretirement Benefits. We reflect an asset or liability for our pension and other postretirement benefit plans based on their over funded or under funded status. As of December 31, 2009, our pension plans were under funded by $154 million and our other postretirement benefit plans were under funded by $399 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plans and other factors. A significant assumption we utilize is the discount rates used in calculating our benefit obligations. We select our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations, along with changes to the plans and other items, are deferred and amortized into income over either the period of expected future service of active participants, or over the lives of inactive plan participants. We record these deferred amounts as accumulated other comprehensive income for our non-regulated operations and as either a regulatory asset or liability for our regulated operations. As of December 31, 2009, we had deferred net losses of approximately $682 million, net of income taxes, in accumulated other comprehensive income. The following table shows the impact of a one percent change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2009 (in millions):


	Pension Benefits						Other Postretirement Benefits
				Change in Funded						Change in Funded
				Status and Pretax						Status and Pretax
				Accumulated Other						Accumulated Other
	Net Benefit			Comprehensive			Net Benefit			Comprehensive
	Expense (Income)			Income			Expense (Income)			Income
One percent increase in:
Discount rates	$	(7	)	$	161		$	1		$	50
Expected return on plan assets		(22	)		—			(2	)		—
Rate of compensation increase		2			(5	)		—			—
Health care cost trends		—			—			3			(47	)
One percent decrease in:
Discount rates	$	8		$	(187	)	$	(3	)	$	(54	)
Expected return on plan assets⁽¹⁾		22			—			2			—
Rate of compensation increase		(1	)		4			—			—
Health care cost trends		—			—			(3	)		42


(1)		^{If the actual return on plan assets was one percent lower than the expected return on plan assets, our expected cash contributions to our pension and other postretirement benefit plans would not change significantly.}

The estimates for our net benefit expense or income are partially based on the expected return on pension plan assets. We use a market-related value of plan assets to determine the expected return on pension plan assets. In determining the market-related value of plan assets, differences between expected and actual asset returns are deferred over three years, after which they are considered for inclusion in net benefit expense or income. If we used the fair value of our plan assets instead of the market-related value of plan assets in determining the expected return on pension plan assets, our net benefit expense would have been $85 million higher for the year ended December 31, 2009.

Price Risk Management Activities. We record the derivative instruments used in our price risk management activities at their fair values. We estimate the fair value of our derivative instruments using exchange prices, third-party pricing data and valuation techniques that incorporate specific contractual terms, statistical and simulation analysis and present value concepts. One of the primary assumptions used to estimate the fair value of derivative instruments is pricing. Our pricing assumptions are based upon price curves derived from actual prices observed in the market, pricing information supplied by a third-party valuation specialist and independent pricing sources and models that rely on this forward pricing information. The extent to which we rely on pricing information received from third parties in developing these assumptions is based, in part, on whether the information considers the availability of observable data in the marketplace. For example, in relatively illiquid markets such as the PJM forward power market, we may make adjustments to the pricing information we receive from third parties based on our evaluation of whether third party market participants would use pricing assumptions consistent with these sources.

The table below presents the hypothetical sensitivity of our commodity-based price risk management activities to changes in fair values arising from immediate selected potential changes in natural gas, oil and power prices at December 31, 2009:


				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
							(In millions)
Production-related derivatives	$	127		$	(29	)	$	(156	)	$	290		$	163
Other commodity-based derivatives		(508	)		(517	)		(9	)		(500	)		8

Total	$	(381	)	$	(546	)	$	(165	)	$	(210	)	$	171

Another significant assumption are the discount rates we use in determining the fair value of our derivative instruments. The table below presents the hypothetical sensitivity of our commodity-based price risk management activities to changes in fair values arising from changes in the discount rates we used to determine the fair value of our derivatives at December 31, 2009:


				Change in Discount Rate
				1 Percent Increase						1 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
							(In millions)
Production-related derivatives	$	127		$	126		$	(1	)	$	128		$	1
Other commodity-based derivatives		(508	)		(495	)		13			(522	)		(14	)

Total	$	(381	)	$	(369	)	$	12		$	(394	)	$	(13	)

Other significant assumptions that we use in determining the fair value of our derivative instruments are those related to anticipated market liquidity and the credit and non-performance risk of our counterparties. We adjust the fair value of our derivative assets for the risk of non-performance of our counterparties considering the collateral posted for the derivative and changes in the counterparties’ creditworthiness, which is measured in part based on changes in their bond yields, changes in actively traded credit default swap prices (if available) and other information about their credit standing. We adjust the fair value of our derivative liabilities for our creditworthiness utilizing similar inputs considering cash collateral we have posted with our counterparties.

The table below presents the hypothetical sensitivity of our commodity-based price risk management activities to changes in fair values arising from potential changes in credit risk at December 31, 2009:


				Change in Credit Risk
				1 Percent Increase						1 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
							(In millions)
Production-related derivatives	$	127		$	126		$	(1	)	$	128		$	1
Other commodity-based derivatives		(508	)		(501	)		7			(515	)		(7	)

Total	$	(381	)	$	(375	)	$	6		$	(387	)	$	(6	)

Deferred Taxes and Uncertain Income Tax Positions. We record deferred income tax assets and liabilities reflecting tax consequences deferred to future periods based on differences between the financial statement carrying value of assets and liabilities and the tax basis of assets and liabilities. Additionally, our deferred tax assets and liabilities reflect our assessment of tax positions taken, and the resulting tax basis, and reflect our conclusions about which positions are more likely than not to be sustained if they are audited by taxing authorities. Our most significant judgments on tax related matters include, but are not limited to, the items noted below. All of these matters involve the exercise of significant judgment which could change and materially impact our financial condition or results of operations. For a further discussion of these items and other income tax matters, see Item 8, Financial Statements and Supplementary Data, Note 5.

Valuation Allowance. The realization of our deferred tax assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences are deductible. Valuation allowances are established when necessary to reduce deferred income tax assets to the amounts we believe are more likely than not to be recovered. In evaluating our valuation allowance, we consider the reversal of existing temporary differences, the existence of taxable income in prior carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowance could materially impact our results of operations.

Uncertain Tax Positions. We have liabilities for unrecognized tax benefits related to uncertain tax positions connected with ongoing examinations and open tax years. Changes in our assessment of these liabilities may require us to increase the liability and record additional tax expense or reverse the liability and recognize a tax benefit which would positively or negatively impact our effective tax rate.

Undistributed Earnings of Foreign Investees and Certain Unconsolidated Affiliates. We record deferred tax liabilities on the undistributed earnings of our foreign investments if we anticipate these earnings to be repatriated. If we do not plan to repatriate these foreign undistributed earnings, no provision has been made for any U.S. taxes or foreign withholding taxes. Any changes to our repatriation assumptions, including the repatriation of proceeds from sales of these investments, could require us to record additional deferred taxes.

Additionally, we believe certain of our unconsolidated affiliates’ undistributed earnings will ultimately be distributed to us through dividends which would be eligible for a dividends received deduction. We and our joint venture partners have the intent and ability to recover these cumulative undistributed earnings over time through dividends or through a structured sale which would not result in any additional deferred tax liabilities.

Asset and Investment Impairments. The accounting rules on asset and investment impairments require us to continually monitor our businesses, the business environment and the performance of our investments to determine if an event has occurred that indicates that a long-lived asset or investment may be impaired. If an event occurs, which is a determination that involves judgment, we then estimate the fair value of the asset, which considers a number of factors, including the potential value we would receive if we sold the asset and the projected cash flows of the asset based on current and anticipated future market conditions and discount rates. The assessment of project level cash flows requires significant judgment to make projections and assumptions for many years into the future for pricing, demand, competition, operating costs, legal and regulatory issues and other factors that are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates.

We utilize the cash flow projections to assess our ability to recover the carrying value of our assets and investments based on either (i) our long-lived assets’ ability to generate future cash flows on an undiscounted basis or (ii) the fair value of our investments in unconsolidated affiliates and whether any decline in this fair value below our carrying amount is considered to be other than temporary. If an impairment is indicated, we record an impairment charge for the excess of carrying value of the asset over its fair value. During the year ended December 31, 2009, we recorded impairments of $21 million related to our long-lived assets and other assets. We recorded impairments of our long-lived assets of $41 million and $20 million and impairments and losses on our investments in and advances to unconsolidated affiliates of $127 million and $75 million during the years ended December 31, 2008 and 2007. Future changes in the economic and business environment can impact our assessments of potential impairments.

New Accounting Pronouncements Issued But Not Yet Adopted

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to and examples of each are:

•

Commodity Price Risk

	•		Changes in natural gas and oil prices impact the amounts at which we sell our natural gas and oil in our Exploration and Production segment, affect gas not used in the operations of our Pipelines segment and affect the fair value of our natural gas and oil derivative contracts held in our Exploration & Production and Marketing segments;

	•		Changes in natural gas locational price differences also affect amounts at which we sell our natural gas and oil production, the fair values of any related derivative products and affect our ability to optimize pipeline transportation capacity contracts held in our Marketing segment; and

	•		Changes in electricity prices and locational price differences affect the value of our remaining power contracts held in our Marketing segment.

•

Interest Rate Risk

	•		Changes in interest rates affect the interest expense we incur on our variable-rate debt and the fair value of our fixed-rate debt;

	•		Changes in interest rates result in increases or decreases in the unrealized value of our derivative positions; and

	•		Changes in interest rates used to discount liabilities result in higher or lower accretion expense over time.

Where practical, we manage these various risks by entering into contractual commitments involving physical or financial settlement that attempt to limit exposure related to future market movements. The timing and extent of our risk management activities are based on a number of factors, including our market outlook, risk tolerance and liquidity. Our risk management activities typically involve the use of the following types of contracts:

	•		Forward contracts, which commit us to purchase or sell energy commodities in the future;

	•		Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement at a specific price and future date;

	•		Options, which convey the right to buy or sell a commodity, financial instrument or index at a predetermined price;

	•		Swaps, which require payments to or from counterparties based upon the differential between two prices or rates for a predetermined contractual (notional) quantity; and

	•		Structured contracts, which may involve a variety of the above characteristics.

Many of the contracts we use in our risk management activities qualify as derivative financial instruments. A discussion of our accounting policies for derivative instruments are included in Item 8, Financial Statements and Supplementary Data, Notes 1 and 8.

Commodity Price Risk

Production-Related Derivatives

We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts. These contracts impact our earnings as the fair value of these derivatives changes. Our production-related derivatives do not mitigate all of the commodity price risks of our forecasted sales of natural gas and oil production and, as a result, we are subject to commodity price risks on our remaining forecasted production.

Other Commodity-Based Derivatives

In our Marketing segment, we have long-term natural gas and power derivative contracts which include forwards, swaps, options and futures that we either intend to manage until their expiration or seek opportunities to liquidate to the extent it is economical and prudent. We utilize a sensitivity analysis to manage the commodity price risk associated with these contracts.

Sensitivity Analysis

The table below presents the hypothetical sensitivity of our production-related derivatives and our other commodity-based derivatives to changes in fair values arising from immediate selected potential changes in the market prices (primarily natural gas, oil and power prices and basis differentials) used to value these contracts. This table reflects the sensitivities of the derivative contracts only and does not include any underlying hedged commodities.


				Change in Market Price
				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
							(In millions)
Production-related derivatives — net assets (liabilities)
December 31, 2009	$	127		$	(29	)	$	(156	)	$	290		$	163
December 31, 2008	$	682		$	582		$	(100	)	$	785		$	103
Other commodity-based derivatives — net assets (liabilities)
December 31, 2009	$	(508	)	$	(517	)	$	(9	)	$	(500	)	$	8
December 31, 2008	$	(707	)	$	(719	)	$	(12	)	$	(695	)	$	12

Interest Rate Risk

Many of our debt-related financial instruments and project financing arrangements are sensitive to changes in interest rates. The table below shows the maturity of the carrying amounts and related weighted-average effective interest rates on our long-term interest-bearing securities by expected maturity date as well as the total fair value of those securities. The fair value of the securities has been estimated based on quoted market prices for the same or similar issues.


	December 31, 2009																						December 31, 2008
	Expected Fiscal Year of Maturity of Carrying Amounts																				Fair		Carrying		Fair
	2010			2011			2012			2013			2014			Thereafter			Total		Value		Amounts		Value
													(In millions)
Fixed rate long-term debt and other obligations⁽¹⁾	$	458		$	665		$	458		$	550		$	450		$	9,124		$	11,705	$	12,170	$	11,628	$	9,438
Average interest rate		7.4	%		7.5	%		6.9	%		14.5	%		7.4	%		7.6	%
Variable rate long-term debt and other obligations⁽¹⁾	$	19		$	22		$	1,837		$	25		$	27		$	233		$	2,163	$	1,981	$	2,280	$	1,789
Average interest rate		5.0	%		4.8	%		1.9	%		4.8	%		4.8	%		4.5	%


⁽¹⁾		^{Includes current portion}

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index

Below is an index to the items contained in Part II, Item 8, Financial Statements and Supplementary Data.


	Page
Management’s Annual Report on Internal Control over Financial Reporting		93
Reports of Independent Registered Public Accounting Firms		94
Consolidated Statements of Income		98
Consolidated Balance Sheets		99
Consolidated Statements of Cash Flows		101
Consolidated Statements of Stockholders’ Equity		102
Consolidated Statements of Comprehensive Income		103
Notes to Consolidated Financial Statements		104
1. Basis of Presentation and Significant Accounting Policies		104
2. Acquisitions and Divestitures		110
3. Ceiling Test Charges		111
4. Other Income and Other Expenses		111
5. Income Taxes		112
6. Earnings Per Share		115
7. Fair Value of Financial Instruments		115
8. Price Risk Management Activities		118
9. Regulatory Assets and Liabilities		121
10. Other Assets and Liabilities		123
11. Property, Plant and Equipment		124
12. Debt, Other Financing Obligations and Credit Facilities		126
13. Commitments and Contingencies		131
14. Retirement Benefits		136
15. Equity and Preferred Stock of Subsidiary		141
16. Stock-Based Compensation		143
17. Business Segment Information		145
18. Variable Interest Entities and Qualifying Special Purpose Entities		149
19. Investments in, Earnings from and Transactions with Unconsolidated Affiliates		151
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)		154
Supplemental Natural Gas and Oil Operations (Unaudited)		156
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts		164

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

Under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), 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 (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2009. The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report included herein.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of
El Paso Corporation:

We have audited the accompanying consolidated balance sheets of El Paso Corporation as of December 31, 2009 and 2008, and the related consolidated statements of income, comprehensive income, 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). 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. The financial statements of Citrus Corp. and Subsidiaries (a corporation in which the Company has a 50% interest) as of December 31, 2009 and 2008 and for the three years in the period ended December 31, 2009 and Four Star Oil & Gas Company (a corporation in which the Company has approximately a 49% interest) as of December 31, 2008 and for the two years in the period ended December 31, 2008 have been audited by other auditors whose reports have been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included from Citrus Corp. and Subsidiaries and Four Star Oil & Gas Company, is based solely on the reports of the other auditors. In the consolidated financial statements, the Company’s investments in unconsolidated affiliates includes approximately $674 million from Citrus Corp. and Subsidiaries as of December 31, 2009 and approximately $744 million from Citrus Corp. and Subsidiaries and Four Star Oil & Gas Company combined at December 31, 2008, and the Company’s earnings from unconsolidated affiliates includes approximately $65 million for the year ended December 31, 2009 from Citrus Corp. and approximately $147 million and $149 million for the years ended December 31, 2008 and 2007, respectively, from Citrus Corp. and Subsidiaries and Four Star Oil & Gas Company combined, all of which were audited by other auditors.

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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of El Paso Corporation 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 December 31, 2009 the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements, effective January 1, 2009 the Company adopted accounting standards for the presentation and disclosure of noncontrolling interests in the financial statements, effective January 1, 2008 the Company adopted the measurement provisions of the accounting standards for retirement benefits, and effective January 1, 2007 the Company adopted the accounting standards related to income tax contingencies.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), El Paso Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas
March 1, 2010

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of
El Paso Corporation:

We have audited El Paso Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). El Paso Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, El Paso Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2009 consolidated financial statements of El Paso Corporation and our report dated March 1, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas
March 1, 2010

Report of Independent Auditors

To the Board of Directors and Stockholders of Citrus Corp.:

In our opinion, the consolidated balance sheets and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows (not presented separately herein) present fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the “Company”) at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/PricewaterhouseCoopers LLP

Houston, Texas
February 25, 2010

Report of Independent Registered Public Accounting Firm

To the Stockholders of Four Star Oil & Gas Company:

In our opinion, the consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity and of cash flows (not presented separately herein) present fairly, in all material respects, the financial position of Four Star Oil & Gas Company (the “Company”) and its subsidiary at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Notes 3 and 4 to the financial statements, the Company has significant transactions with affiliated companies. Because of these relationships, it is possible that the terms of these transactions are not the same as those that would result from transactions among wholly unrelated parties.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 20, 2009

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)


	Year Ended December 31,
	2009			2008			2007
Operating revenues
Pipelines	$	2,767		$	2,684		$	2,494
Exploration and Production		1,828			2,762			2,300
Marketing		29			(83	)		(219	)
Corporate and other		7			—			73

		4,631			5,363			4,648

Operating expenses
Cost of products and services		207			245			245
Operation and maintenance		1,257			1,190			1,333
Ceiling test charges		2,123			2,669			—
Depreciation, depletion and amortization		867			1,205			1,176
Taxes, other than income taxes		228			284			249

		4,682			5,593			3,003

Operating income (loss)		(51	)		(230	)		1,645
Earnings from unconsolidated affiliates		67			48			101
Loss on debt extinguishment		—			—			(291	)
Other income		144			94			214
Other expenses		(25	)		(32	)		(11	)
Interest and debt expense		(1,008	)		(914	)		(994	)

Income (loss) before income taxes from continuing operations		(873	)		(1,034	)		664
Income tax (benefit) expense		(399	)		(245	)		222

Income (loss) from continuing operations		(474	)		(789	)		442
Discontinued operations, net of income taxes		—			—			674

Net income (loss)		(474	)		(789	)		1,116
Net income attributable to noncontrolling interests		(65	)		(34	)		(6	)

Net income (loss) attributable to El Paso Corporation		(539	)		(823	)		1,110
Preferred stock dividends of El Paso Corporation		37			37			37

Net income (loss) attributable to El Paso Corporation’s common stockholders	$	(576	)	$	(860	)	$	1,073

Basic earnings (loss) per common share
Income (loss) from continuing operations attributable to El Paso Corporation’s common stockholders	$	(0.83	)	$	(1.24	)	$	0.57
Discontinued operations, net of income taxes		—			—			0.97

Net income (loss) attributable to El Paso Corporation’s common stockholders	$	(0.83	)	$	(1.24	)	$	1.54

Diluted earnings (loss) per common share
Income (loss) from continuing operations attributable to El Paso Corporation’s common stockholders	$	(0.83	)	$	(1.24	)	$	0.57
Discontinued operations, net of income taxes		—			—			0.96

Net income (loss) attributable to El Paso Corporation’s common stockholders	$	(0.83	)	$	(1.24	)	$	1.53

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)


	December 31,
	2009		2008
ASSETS
Current assets
Cash and cash equivalents	$	635	$	1,024
Accounts and notes receivable
Customer, net of allowance of $8 in 2009 and $9 in 2008		346		466
Affiliates		92		133
Other		115		217
Materials and supplies		175		187
Assets from price risk management activities		221		876
Deferred income taxes		298		—
Other		126		148

Total current assets		2,008		3,051

Property, plant and equipment, at cost
Pipelines		19,722		18,042
Natural gas and oil properties, at full cost		20,846		20,009
Other		314		342

		40,882		38,393
Less accumulated depreciation, depletion and amortization		22,987		20,535

Total property, plant and equipment, net		17,895		17,858

Other assets
Investments in unconsolidated affiliates		1,718		1,703
Assets from price risk management activities		123		201
Other		761		855

		2,602		2,759

Total assets	$	22,505	$	23,668

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)


	December 31,
	2009			2008
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	459		$	372
Affiliates		7			6
Other		424			618
Short-term financing obligations, including current maturities		477			1,090
Liabilities from price risk management activities		269			250
Asset retirement obligations		158			83
Accrued interest		208			192
Other		684			632

Total current liabilities		2,686			3,243


Long-term financing obligations, less current maturities		13,391			12,818

Other
Liabilities from price risk management activities		462			767
Deferred income taxes		339			565
Other		1,491			1,679

		2,292			3,011

Commitments and contingencies (Note 13)
Preferred stock of subsidiary		145			—

Equity
El Paso Corporation’s stockholders’ equity
Preferred stock, par value $0.01 per share; authorized 50,000,000 shares; issued 750,000 shares of 4.99% convertible perpetual stock; stated at liquidation value		750			750
Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 716,041,302 shares in 2009 and 712,628,781 shares in 2008		2,148			2,138
Additional paid-in capital		4,501			4,612
Accumulated deficit		(3,192	)		(2,653	)
Accumulated other comprehensive loss		(718	)		(532	)
Treasury stock (at cost); 14,761,654 shares in 2009 and 14,061,474 shares in 2008		(283	)		(280	)

Total El Paso Corporation stockholders’ equity		3,206			4,035
Noncontrolling interests		785			561

Total equity		3,991			4,596

Total liabilities and equity	$	22,505		$	23,668

See accompanying notes.

100

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)


	Year Ended December 31,
	2009			2008			2007
Cash flows from operating activities
Net income (loss)	$	(474	)	$	(789	)	$	1,116
Less income from discontinued operations, net of income taxes		—			—			674

Income (loss) from continuing operations		(474	)		(789	)		442
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization		867			1,205			1,176
Ceiling test charges		2,123			2,669			—
Deferred income tax (benefit) expense		(427	)		(172	)		182
Earnings from unconsolidated affiliates, adjusted for cash distributions		21			132			88
Loss on debt extinguishment		—			—			291
Other non-cash income items		57			32			(31	)
Asset and liability changes
Accounts and notes receivable		142			129			213
Change in price risk management activities, net		(46	)		(461	)		(69	)
Accounts payable		(140	)		(88	)		(67	)
Change in margin and other deposits		22			24			90
Other asset changes		(74	)		(32	)		(150	)
Other liability changes		44			(279	)		(327	)

Cash provided by continuing activities		2,115			2,370			1,838
Cash used in discontinued activities		—			—			(33	)

Net cash provided by operating activities		2,115			2,370			1,805

Cash flows from investing activities
Capital expenditures		(2,810	)		(2,757	)		(2,495	)
Cash paid for acquisitions, net of cash acquired		(130	)		(362	)		(1,197	)
Net proceeds from the sale of assets and investments		351			682			106
Net change in restricted cash		49			39			33
Other		(41	)		50			3

Cash used in continuing activities		(2,581	)		(2,348	)		(3,550	)
Cash provided by discontinued activities		—			—			3,660

Net cash provided by (used in) investing activities		(2,581	)		(2,348	)		110

Cash flows from financing activities
Net proceeds from issuance of long-term debt		1,618			4,641			6,624
Payments to retire long-term debt and other financing obligations		(1,668	)		(3,679	)		(8,902	)
Net proceeds from issuance of noncontrolling interests		212			15			538
Net proceeds from the issuance of preferred stock of subsidiary		145			—			—
Dividends paid		(177	)		(157	)		(149	)
Distributions to noncontrolling interest holders		(48	)		(29	)		—
Repurchase of common shares		—			(77	)		—
Contributions from discontinued operations		—			—			3,344
Other		(5	)		3			5

Cash provided by continuing activities		77			717			1,460
Cash used in discontinued activities		—			—			(3,627	)

Net cash provided by (used in) financing activities		77			717			(2,167	)

Change in cash and cash equivalents		(389	)		739			(252	)
Cash and cash equivalents
Beginning of period		1,024			285			537

End of period	$	635		$	1,024		$	285

Supplemental cash flow information related to continuing operations
Interest paid, net of amounts capitalized	$	968		$	914		$	1,054
Income tax payments (refunds)		(24	)		12			34

See accompanying notes.

101

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY
(In millions, except per share amounts)


	Year Ended December 31,
	2009						2008						2007
	Shares			Amount			Shares			Amount			Shares			Amount
El Paso Corporation stockholders’ equity:
Preferred stock, $0.01 par value:
Balance at beginning and end of year		1		$	750			1		$	750			1		$	750

Common stock, $3.00 par value:
Balance at beginning of year		712			2,138			709			2,128			706			2,118
Other, net		4			10			3			10			3			10

Balance at end of year		716			2,148			712			2,138			709			2,128

Additional paid-in capital:
Balance at beginning of year					4,612						4,699						4,804
Dividends					(149	)					(163	)					(149	)
Other, including stock-based compensation					38						76						44

Balance at end of year					4,501						4,612						4,699

Accumulated deficit:
Balance at beginning of year					(2,653	)					(1,834	)					(2,940	)
Net income (loss) attributable to El Paso Corporation					(539	)					(823	)					1,110
Cumulative effect of adopting new tax accounting standards					—						—						(4	)
Cumulative effect of adopting new pension accounting standards, net of income tax of $2					—						4						—

Balance at end of year					(3,192	)					(2,653	)					(1,834	)

Accumulated other comprehensive income (loss):
Balance at beginning of year					(532	)					(272	)					(343	)
Other comprehensive income (loss)					(186	)					(263	)					80
Cumulative effect of adopting new pension accounting standards, net of income tax of $2 in 2008 and $4 in 2007					—						3						(9	)

Balance at end of year					(718	)					(532	)					(272	)

Treasury stock, at cost:
Balance at beginning of year		(14	)		(280	)		(9	)		(191	)		(9	)		(203	)
Share repurchases		—			—			(5	)		(77	)		—			—
Stock-based and other compensation		(1	)		(3	)		—			(12	)		—			12

Balance at end of year		(15	)		(283	)		(14	)		(280	)		(9	)		(191	)

Total El Paso Corporation stockholders’ equity at end of year					3,206						4,035						5,280

Noncontrolling interests:
Balance at beginning of year					561						565						31
Distributions to noncontrolling interests					(48	)					(29	)					—
Issuance of noncontrolling interests					212						15						538
Net income attributable to noncontrolling interests (Note 15)					60						34						6
Other					—						(24	)					(10	)

Balance at end of year					785						561						565

Total equity at end of year				$	3,991					$	4,596					$	5,845

See accompanying notes.

102

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)


	Year Ended December 31,
	2009			2008			2007
Net income (loss)	$	(474	)	$	(789	)	$	1,116

Pension and postretirement obligations:
Unrealized actuarial gains (losses) arising during period (net of income taxes of $11 in 2009, $288 in 2008 and $91 in 2007)		36			(527	)		181
Reclassifications of actuarial gains during period (net of income taxes of $16 in 2009, $8 in 2008 and $13 in 2007)		27			16			26
Cash flow hedging activities:
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $6 in 2009, $106 in 2008 and $2 in 2007)		11			191			(3	)
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $146 in 2009, $31 in 2008 and $65 in 2007)		(260	)		57			(112	)
Investments available for sale:
Unrealized gains on investments available for sale arising during period (net of income taxes of $2 in 2007)		—			—			3
Realized gains on investments available for sale arising during period (net of income taxes of $8 in 2007)		—			—			(15	)

Other comprehensive income (loss)		(186	)		(263	)		80

Comprehensive income (loss)		(660	)		(1,052	)		1,196
Comprehensive income attributable to noncontrolling interests		(65	)		(34	)		(6	)

Comprehensive income (loss) attributable to El Paso Corporation	$	(725	)	$	(1,086	)	$	1,190

See accompanying notes.

103

EL PASO CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

Our consolidated financial statements are prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. Certain amounts related to noncontrolling interests have been retrospectively adjusted within these consolidated financial statements to reflect the January 1, 2009 adoption of new presentation and disclosure requirements for noncontrolling interests. Our financial statements for prior periods also include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income (loss) or stockholders’ equity.

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. We apply the equity method of accounting where we can exert significant influence over, but do not control the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. We use the cost method of accounting where we are unable to exert significant influence over the entity.

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 interstate 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. Our pipelines 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, an equity return component on regulated capital projects and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents. We maintain cash on deposit with banks and insurance companies that is pledged for a particular use or restricted to support a potential liability. We classify these balances as restricted cash in other current or non-current assets on our balance sheet based on when we expect the restrictions on this cash to be removed. We had $2 million of restricted cash in other current assets as of December 31, 2009 and 2008 and $8 million and $57 million in other non-current assets as of December 31, 2009 and 2008.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts and notes 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.

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Property, Plant and Equipment

Pipelines and Other (Excluding Natural Gas and Oil Properties). Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and, an equity return component in our regulated businesses. We capitalize major units of property replacements or improvements and expense minor items. For a description of the methods we use to depreciate regulated property, plant and equipment, see Note 11.

Included in our pipeline property balances are additional acquisition costs, which represent the excess purchase costs associated with purchase business combinations allocated to our regulated interstate systems’ property, plant and equipment. These costs are amortized on a straight-line basis and we do not recover these excess costs in our rates.

When we retire property, plant and equipment in our regulated operations, 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 operations and maintenance expense in our income statements.

Natural Gas and Oil Properties. We use the full cost method to account for our natural gas and oil properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves are capitalized on a country-by-country basis. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and periodically assessed for impairment through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs quarterly. We transfer unproved property costs into the amortizable base when properties are determined to have proved reserves. In addition, in countries where a natural gas or oil reserve base exists, we transfer unproved property costs to the amortizable base when we have completed the evaluation of the unproved properties or they are determined to be impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes future development costs; dismantlement, restoration and abandonment costs, net of estimated salvage values; and geological and geophysical costs incurred that cannot be associated with specific unevaluated properties or prospects in which we own a direct interest.

Our capitalized costs in each country, net of related deferred income taxes, are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the cost of unproved natural gas and oil properties not being amortized plus the lower of cost or fair value of unproved natural gas and oil properties included in the amortizable base less related income tax effects. We perform this ceiling test calculation each quarter. Prior to December 31, 2009, we utilized end-of-period spot prices to determine future net revenues. As a result of our adoption of the SEC’s final rule on the Modernization of Oil and Gas Reporting, effective December 31, 2009, we are required to use a 12-month average price (calculated as the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period) to calculate the ceiling test. If total capitalized costs exceed the ceiling, we are required to write-down our capitalized costs to the ceiling. Any required write-down is included as a ceiling test charge on our income statement and as an increase to accumulated depreciation, depletion and amortization on our balance sheet. Prior to December 31, 2008, our ceiling test calculations included the effects of any derivative instruments we designated as, and that qualified as, cash flow hedges of anticipated future natural gas and oil production on the date of the calculation. During the fourth quarter of 2008, we removed the hedging designation on all of our commodity-based derivative contracts related to our hedged natural gas and oil production volumes. Our ceiling test calculations exclude the estimated future cash outflows associated with asset retirement liabilities related to proved developed reserves.

105

When we sell or convey interests in natural gas and oil properties, we reduce our natural gas and oil reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of natural gas and oil properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. We treat sales proceeds on non-significant sales as an adjustment to the cost of our properties.

Asset and Investment Divestitures/Impairments

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

We reclassify assets to be sold in our financial statements as either held-for-sale or from discontinued operations when it becomes probable that we will dispose of the assets within the next twelve months and when they meet other criteria, including whether we will have significant long-term continuing involvement with those assets after they are sold. We cease depreciating assets in the period that they are reclassified as either held for sale or from discontinued operations, and reflect the results of our discontinued operations in our income statement separately from those of continuing operations.

Cash flows from our discontinued businesses are reflected as discontinued operating, investing, and financing activities in our statement of cash flows. Cash provided by (used in) discontinued activities in the operating activities section of our cash flow statement includes all operating cash flows generated by our discontinued businesses during the period. Proceeds from the sale of our discontinued operations are classified in cash provided by discontinued activities in the cash flows from investing activities section of our cash flow statement. To the extent these operations participated in our cash management program we reflect transactions related to the cash management program as financing activities in our cash flow statement. We cease depreciating assets in the period that they are reclassified as either held for sale or discontinued operations.

Pension and Other Postretirement Benefits

We maintain several pension and other postretirement benefit plans. We make contributions to our plans, if required, to fund the benefits to be paid out to participants and retirees. These contributions are invested until the benefits are paid out to plan participants. We record the net benefit cost related to these plans 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 employee’s salary, 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 pension and postretirement benefit plans, see Note 14.

In accounting for our pension and other postretirement benefit plans, we record an asset or liability based on the over funded or under funded status of each plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability for our regulated operations or in accumulated other comprehensive income (loss), a component of stockholders’ equity, for all other operations until those gains and losses are recognized in the income statement.

Effective December 31, 2009, we expanded our disclosures about postretirement benefit plan assets as a result of new disclosure requirements. See Note 14 for these expanded disclosures.

106

Effective January 1, 2008, we adopted the measurement provisions of the accounting standards for retirement benefits that resulted in a change to the measurement date of our pension and other postretirement benefit plans from September 30 to December 31. We recorded a $4 million decrease, net of income taxes of $2 million, to the January 1, 2008 accumulated deficit and a $3 million decrease, net of income taxes of $2 million, to the January 1, 2008 accumulated other comprehensive loss upon the adoption of those provisions to reflect an additional three months of net periodic benefit income based on our September 30, 2007 measurement.

Revenue Recognition

Our business segments provide a number of services and sell a variety of products. We record revenues for these products and services which include estimates of amounts earned but unbilled. We estimate these unbilled revenues based on contractual data, regulatory information, commodity prices, and preliminary throughput and allocation measurements, among other items. The revenue recognition policies of our most significant operating segments are as follows:

Pipelines revenues. Our Pipelines segment derives revenues primarily from transportation and storage services. Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. Gas not used in operations is based on the volumes we are allowed to retain relative to the amounts of gas we use for operating purposes. We recognize revenue from gas not used in operations from our shippers when the FERC allows us to retain the volumes at the market prices required under our tariffs. We are subject to FERC regulations and, as a result, revenues we collect in rate proceedings may be subject to refund. We establish reserves for these potential refunds.

Exploration and Production revenues. Our Exploration and Production segment derives revenues primarily through the physical sale of natural gas, oil, condensate and natural gas liquids. Revenues from sales of these products are recorded upon delivery and passage of title using the sales method, net of any royalty interests or other profit interests in the produced product. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved reserves for a given property, we record a liability. Costs associated with the transportation and delivery of production are included in cost of products and services.

Marketing revenues. Our Marketing segment derives revenues from physical natural gas and power transactions and the management of derivative contracts. Our derivative transactions are recorded at their fair value and changes in their fair value are reflected net in operating revenues. For a further discussion of our income recognition policies on derivatives see Price Risk Management Activities below. The impact of non-derivative transactions, including our transportation contracts, are recognized net in operating revenues based on the contractual or market price and related volumes at the time the commodity is delivered or the contracts are terminated.

Environmental Costs and Other Contingencies

Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency 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 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.

107

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.

Price Risk Management Activities

Our price risk management activities relate primarily to derivatives entered into to hedge or otherwise reduce the commodity exposure on our natural gas and oil production and interest rate and foreign currency exposure on our long-term debt. We also hold other derivatives not intended to hedge these exposures, including those related to our legacy trading activities.

Our derivatives are reflected on our balance sheet at their fair value as assets and liabilities from price risk management activities. Cash collateral associated with our derivatives is not significant to our financial statements. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities on counterparties where we have a legal right of offset. See Note 8 for a further discussion of our price risk management activities.

Derivatives that we have designated as accounting hedges impact our revenues or expenses based on the nature and timing of the transactions that they hedge. Derivatives that we have not designated as hedges are marked-to-market each period and changes in their fair value, as well as any realized amounts, are generally reflected as operating revenues in both our Exploration and Production segment and our Marketing segment.

In our cash flow statement, cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows (other than those derivatives intended to hedge the principal amounts of our foreign currency denominated debt). In our balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables.

Income Taxes

We record current income taxes based on our current taxable income and 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 recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

In 2007, we adopted new accounting standards which required us 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. greater than a 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.

108

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, depletion and amortization expense in our income statement. Our regulated pipelines have the ability to recover certain of these costs from their customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.

Accounting for Stock-Based Compensation.

We measure all employee stock-based compensation awards at fair value on the date awards are granted to employees and recognize compensation cost in our financial statements over the requisite service period. For additional information on our stock-based compensation awards, see Note 16.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2009, the following accounting standards had not yet been adopted by us.

Transfers of Financial Assets. In June 2009, the FASB updated accounting standards for financial asset transfers. Among other items, this update eliminated the concept of a qualifying special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated or not. The changes are effective for existing QSPEs as of January 1, 2010 and for transactions entered into on or after January 1, 2010. The adoption of this accounting standard in January 2010 did not have a material impact on our financial statements as we amended our existing accounts receivable sales programs in January 2010. For further information, see Note 18.

Variable Interest Entities. In June 2009, the FASB updated accounting standards for variable interest entities to revise how companies determine the primary beneficiary of these entities, among other changes. Companies will now be required to use a qualitative approach based on their responsibilities and power over the entities’ operations, rather than a quantitative approach in determining the primary beneficiary as previously required. The adoption of this accounting standard in January 2010 did not have a material impact on our financial statements.

109

2. Acquisitions and Divestitures

Acquisitions

Gulf LNG. In February 2008, we paid approximately $295 million to complete the acquisition of a 50 percent interest in the Gulf LNG Clean Energy Project, a LNG terminal which is currently under construction in Pascagoula, Mississippi. The terminal is expected to be placed in service in late 2011. In addition, we have a commitment to loan Gulf LNG up to $150 million under which we have advanced approximately $56 million and $26 million as of December 31, 2009 and 2008. Our partner in this project has a commitment to loan up to $64 million. We account for our investment in Gulf LNG using the equity method.

Exploration and Production properties. In 2009, we acquired domestic natural gas and oil properties for approximately $92 million, including producing properties of approximately $87 million located primarily in the Altamont-Bluebell-Cedar Rim Field in Utah. During 2008, we acquired interests in domestic natural gas and oil properties for $61 million, including producing properties of $51 million. During 2007, we acquired operated natural gas and oil producing properties and undeveloped acreage in south Texas for $254 million and also acquired Peoples Energy Production Company (Peoples) for $887 million. Peoples was an exploration and production company with natural gas and oil properties located primarily in the Arklatex, Texas Gulf Coast and Mississippi areas and in the San Juan and Arkoma Basins.

Divestitures

During 2009, 2008 and 2007, we sold a number of assets and investments the proceeds of which are as follows:


	2009		2008		2007
	(In millions)
Exploration and Production	$	93	$	637	$	2
Power		190		16		1
Pipelines		65		2		36
Other		—		20		27

Total continuing⁽¹⁾		348		675		66
Discontinued		—		—		3,660

Total	$	348	$	675	$	3,726


⁽¹⁾		Proceeds exclude any returns of capital on our investments in unconsolidated affiliates and cash transferred with the assets sold and include costs incurred in preparing assets for disposal. These items increased our sales proceeds by $3 million, $7 million and $40 million for the years ended December 31, 2009, 2008 and 2007.

Exploration and Production. Assets sold in 2009 consisted of natural gas producing properties in the Central and Western divisions. Assets sold in 2008 consisted primarily of natural gas and oil properties in the Gulf Coast division.

Power. Assets sold in 2009 consisted of our investment in the Argentina-to-Chile pipeline and our interest in the Porto Velho power generation facility in Brazil. Assets sold in 2008 consist of power investments in Central America and Asia.

Pipelines. Assets sold consisted primarily of certain facilities and pipeline laterals.

Other. Assets sold consisted primarily of a fuel oil terminal in 2008 and a non-core investment in 2007.

Discontinued Operations and Assets Held for Sale

In February 2007, we sold ANR, our Michigan storage assets and our 50 percent interest in Great Lakes Gas Transmission for approximately $3.7 billion. We recorded a gain on the sale of $648 million, net of taxes of $354 million.

110

The summarized operating results of ANR and related operations were as follows:


	ANR and
	Related
	Operations
	(In millions)
Year Ended December 31, 2007
Revenues	$	101
Costs and expenses		(43	)
Other expense⁽¹⁾		(7	)
Interest and debt expense		(10	)
Income taxes		(15	)

Income from operations		26
Gain on sale, net of income taxes of $354 million		648

Income from discontinued operations, net of income taxes	$	674


⁽¹⁾		Includes a loss of approximately $19 million associated with the extinguishment of certain debt obligations.

3. Ceiling Test Charges

We are required to conduct quarterly impairment tests of our capitalized costs in each of our full cost pools. During the years ended December 31, 2009 and 2008, we recorded the following ceiling test charges:


	2009		2008
	(In millions)
Full cost pool:
U.S.	$	2,031	$	2,181
Brazil		58		479
Egypt		34		9

Total	$	2,123	$	2,669


^Note:		A majority of the 2009 ceiling test charges were recorded during the first quarter of 2009 and all of the 2008 ceiling test charges were recorded during the fourth quarter of 2008. We did not record any ceiling test charges for the year ended December 31, 2007.

Through the third quarter of 2009, our quarterly impairment tests were based on the spot commodity prices at the end of each period. As a result of the SEC’s final rule on the Modernization of Oil and Gas Reporting, effective December 31, 2009, we were required to use a 12-month average price (calculated as the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period) when performing these ceiling tests. In calculating our ceiling test charges, we are also required to hold prices constant over the life of the reserves, even though actual prices of natural gas and oil are volatile and change from period to period.

4. Other Income and Other Expenses

The following are the components of other income and other expenses for each of the three years ended December 31:


	2009		2008		2007
	(In millions)
Other Income
Interest income	$	26	$	19	$	49
Allowance for funds used during construction		61		37		32
Deferred taxes on allowance for funds used during construction		34		17		18
Reversal of liability for legacy crude oil purchases (see Note 17)		—		—		77
Gain on sale of non-equity method investments		—		—		24
Foreign currency gains		14		—		—
Other		9		21		14

Total	$	144	$	94	$	214


Other Expenses
Foreign currency losses	$	—	$	28	$	1
Loss on sale of Porto Velho notes receivable		22		—		—
Other		3		4		10

Total	$	25	$	32	$	11

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5. Income Taxes

Pretax Income (Loss) and Income Tax Expense (Benefit). The tables below show our pretax income (loss) from continuing operations and the components of income tax expense (benefit) for each of the years ended December 31:


	2009			2008			2007
	(In millions)
Pretax Income (Loss)
U.S.	$	(771	)	$	(569	)	$	593
Foreign		(102	)		(465	)		71

	$	(873	)	$	(1,034	)	$	664


Components of Income Tax Expense (Benefit)
Current
Federal	$	(1	)	$	(36	)	$	(1	)
State		24			(38	)		33
Foreign		5			1			8

		28			(73	)		40


Deferred
Federal		(400	)		(238	)		217
State		(26	)		27			(39	)
Foreign		(1	)		39			4

		(427	)		(172	)		182

Total income tax expense (benefit)	$	(399	)	$	(245	)	$	222

Effective Tax Rate Reconciliation. Our income taxes included in income from continuing operations 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 rates)
Income taxes at the statutory federal rate of 35%	$	(305	)	$	(362	)	$	232
Increase (decrease)
Sales and write-offs of foreign investments		(88	)		(50	)		1
Valuation allowances		47			202			10
Foreign income (loss) taxed at different rates		(42	)		23			24
State income taxes, net of federal income tax effect		44			(6	)		14
Earnings from unconsolidated affiliates where we anticipate receiving dividends		(23	)		(41	)		(40	)
Noncontrolling interest income not subject to U.S. tax		(23	)		(12	)		(2	)
Audit settlements		(12	)		2			—
Texas margins tax credit on accumulated net operating loss		—			—			(16	)
Other		3			(1	)		(1	)

Income taxes	$	(399	)	$	(245	)	$	222

Effective tax rate		46	%		24	%		33	%

In 2009, our effective tax rate was higher than the statutory rate primarily due to recording $88 million of income tax benefit relating to a U.S. tax loss on the liquidation of certain foreign entities. Following the 2009 sale of the remaining significant non-core international power projects, these entities had no liquidating value. As these entities had tax basis, the liquidation resulted in a tax loss. In 2008, our overall effective tax rate differed from the statutory rate due primarily to a $0.5 billion ceiling test charge on our Brazilian full cost pool that did not have a corresponding U.S. or Brazilian tax benefit. The impact of the ceiling test charge on our effective tax rate is included in Foreign income (loss) taxed at different rates and Valuation allowances in the above table.

We believe certain of our unconsolidated affiliates’ undistributed earnings will ultimately be distributed to us through dividends which would be eligible for a dividends received deduction. We and our joint venture partners have the intent and ability to recover these cumulative undistributed earnings over time through dividends or through a structured sale which would not result in any additional deferred tax liabilities. At December 31, 2009, the undistributed earnings of our unconsolidated affiliates for which we expect to receive a dividends received deduction was approximately $360 million.

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


	2009			2008
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	2,193		$	2,669
Investments in affiliates		193			177
Regulatory and other assets		77			54

Total deferred tax liability		2,463			2,900

Deferred tax assets
Net operating loss and tax credit carryovers
Federal		1,399			1,315
State		77			116
Foreign		202			147
Benefits and compensation		308			353
Price risk management activities		258			111
Legal and other reserves		240			200
Other		324			420
Valuation allowance		(384	)		(337	)

Total deferred tax asset		2,424			2,325

Net deferred tax liability	$	39		$	575

Cumulative undistributed earnings from substantially all of our foreign subsidiaries and foreign corporate joint ventures have been or are intended to be indefinitely reinvested in foreign operations. Therefore, no provision has been made for any U.S. taxes or foreign withholding taxes that may be applicable upon actual or deemed repatriation, and an estimate of the taxes if earnings were to be repatriated is not practical. At December 31, 2009, the portion of the cumulative undistributed earnings from these investments on which we have not recorded U.S. income taxes was approximately $85 million.

Unrecognized Tax Benefits (Liabilities for Uncertain Tax Matters). We are subject to taxation in the U.S. and various states and foreign jurisdictions. With a few exceptions, we are no longer subject to state, local or foreign 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 (IRS) 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 had a $12 million positive impact on our results of operations but did not materially impact our financial condition or liquidity. For years in which our returns are still subject to review, our unrecognized tax benefits (liabilities for uncertain tax matters) could increase or decrease our income tax expense and effective income tax rates as these matters are finalized. We are currently unable to estimate the range of potential impacts the resolution of any contested matters could have on our financial statements. The following table shows the change in our unrecognized tax benefits:


	2009			2008
	(In millions)
Balance at January 1	$	173		$	157
Additions:
Tax positions taken in prior years		(2	)		24
Tax positions taken in current year		87			32
Foreign currency fluctuations		3			—
Reductions:
Tax positions taken in prior years		(1	)		(23	)
Settlements with taxing authorities		4			(11	)
Statute of limitations expiration		(4	)		(5	)
Foreign currency fluctuations		—			(1	)

Balance at December 31	$	260		$	173

As of December 31, 2009, and 2008, approximately $258 million and $169 million (net of federal tax benefits) of unrecognized tax benefits would affect our income tax expense and our effective income tax rate if recognized in future periods. The significant increase primarily pertains to uncertainties related to the U.S. tax loss on the liquidation of certain foreign entities. While the amount of our unrecognized tax benefits could change in the next twelve months, we do not expect this change to have a significant impact on our results of operations or financial position.

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We recognize accrued interest related to unrecognized tax benefits and penalties as income tax expense. During 2009, 2008 and 2007, we recognized $3 million, $4 million and $6 million in interest and penalties related to the unrecognized tax benefits noted above. We had $52 million and $49 million accrued for the payment of interest and penalties as of December 31, 2009 and 2008.

Tax Credit and Net Operating Loss Carryovers. As of December 31, 2009, we have U.S. federal alternative minimum tax credits of $295 million that carryover indefinitely. The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2009:


	Carryover Period
	2010		2011-2014		2015-2019		2020-2029		Total
	(In millions)
U.S. federal net operating loss	$	6	$	12	$	480	$	2,989	$	3,487
State net operating loss		53		260		814		1,090		2,217

We also had $512 million of foreign net operating loss carryovers and $71 million of foreign capital loss carryovers which carryover indefinitely. Usage of our U.S. federal carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations.

Valuation Allowances. Deferred tax assets are recorded on net operating losses and temporary differences in the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on the recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. As part of our assessment, we consider future reversals of existing taxable temporary differences, primarily related to depreciation.

As of December 31, 2009, our valuation allowance primarily relates to deferred tax assets recorded on state and foreign net operating losses and temporary differences. In 2009, we increased our valuation allowance by $93 million on deferred tax assets associated with Brazil and Egypt net operating losses and reduced our valuation allowance by $46 million on deferred tax assets associated with expiring state net operating losses. In 2008, we provided a valuation allowance of $202 million on deferred tax assets associated with Brazil net operating losses and ceiling test charges. The valuation allowance was established primarily as a result of changes in the worldwide economic conditions creating uncertainty in our outlook as to future taxable income in that particular tax jurisdiction. We believe it is more likely than not that we will realize the benefit of our deferred tax assets, net of existing valuation allowances.

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6. Earnings Per Share

We calculated basic and diluted earnings per common share as follows for the three years ended December 31:


	2009						2008						2007
	Basic			Diluted			Basic			Diluted			Basic			Diluted
	(In millions, except per share amounts)
Income (loss) from continuing operations	$	(474	)	$	(474	)	$	(789	)	$	(789	)	$	442		$	442
Net income attributable to noncontrolling interests		(65	)		(65	)		(34	)		(34	)		(6	)		(6	)
Preferred stock dividends of El Paso Corporation		(37	)		(37	)		(37	)		(37	)		(37	)		(37	)

Income (loss) from continuing operations attributable to El Paso Corporation’s common stockholders		(576	)		(576	)		(860	)		(860	)		399			399
Discontinued operations, net of income taxes		—			—			—			—			674			674

Net income (loss) attributable to El Paso Corporation’s common stockholders	$	(576	)	$	(576	)	$	(860	)	$	(860	)	$	1,073		$	1,073


Weighted average common shares outstanding		696			696			696			696			696			696
Effect of dilutive securities:
Options and restricted stock		—			—			—			—			—			3
Weighted average common shares outstanding and dilutive potential common shares		696			696			696			696			696			699


Basic and diluted earnings per common share:
Income (loss) from continuing operations attributable to El Paso Corporation’s common stockholders	$	(0.83	)	$	(0.83	)	$	(1.24	)	$	(1.24	)	$	0.57		$	0.57
Discontinued operations, net of income taxes		—			—			—			—			0.97			0.96

Net income (loss) attributable to El Paso Corporation’s common stockholders	$	(0.83	)	$	(0.83	)	$	(1.24	)	$	(1.24	)	$	1.54		$	1.53

We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on net income attributable to El Paso Corporation per common share is antidilutive. These potentially dilutive securities consist of our employee stock options, restricted stock, convertible preferred stock and trust preferred securities. For the years ended December 31, 2009 and 2008, we incurred losses attributable to El Paso Corporation and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive. For the year ended December 31, 2007, certain employee stock options, our trust preferred securities and our convertible preferred stock were antidilutive. For a discussion of our capital stock activity, our stock-based compensation arrangements, and other instruments noted above, see Notes 15 and 16.

7. Fair Value of Financial Instruments

On January 1, 2008, we adopted new fair value accounting and reporting standards that expanded the disclosure requirements for financial instruments and other derivatives recorded at fair value, and also required that a company’s own credit risk be considered in determining the fair value of those instruments. The adoption of these standards resulted in a $6 million increase in operating revenues, a $4 million pre-tax increase in other comprehensive income, and a $10 million reduction of our liabilities to reflect the consideration of our credit risk on our liabilities that are recorded at fair value, after considering collateral related to these positions. On January 1, 2009, we adopted new accounting and reporting standards for our non-financial assets and liabilities that are measured at fair value on a non-recurring basis, which primarily relates to any impairment of long-lived assets or investments. During the year ended December 31, 2009, we did not have any non-financial assets and liabilities that were recorded at fair value subsequent to their initial measurement.

On January 1, 2009, we also adopted accounting standard updates regarding how companies should consider their own credit in determining the fair value of their liabilities that have third party credit enhancements related to them. Substantially all of the derivative liabilities in our Marketing segment are supported by letters of credit. Under these accounting standard updates, non-cash credit enhancements, such as letters of credit, should not be considered in determining the fair value of these liabilities, including derivative liabilities. Accordingly, we recorded a $34 million gain (net of $18 million of taxes), or $0.05 per share, in 2009 as a result of adopting these new accounting updates.

115

We use various methods to determine the fair values of our financial instruments and other derivatives that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value may be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments and other derivatives into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.

Each of these levels and our corresponding instruments classified by level are further described below:

•

Level 1 instruments’ fair values are based on quoted prices for the instruments in actively traded markets. Included in this level are our marketable securities invested in non-qualified compensation plans whose fair value is determined using quoted prices.

•

Level 2 instruments’ fair values are primarily based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets). Included in this level are our interest rate swaps, production-related natural gas and oil derivatives and certain of our other natural gas derivatives (such as natural gas supply arrangements) whose fair values are based on commodity pricing data obtained from third party pricing sources. These fair values also consider our creditworthiness or that of our counterparties (adjusted for collateral related to our asset positions).

•

Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 above, but their fair value also reflects adjustments for being in less liquid markets or having longer contractual terms. For these instruments, we obtain pricing data from third party pricing sources, adjust this data based on the liquidity of the underlying forward markets over the contractual terms and use the adjusted pricing data to develop an estimate of forward price curves that market participants would use. The curves are then used to estimate the value of settlements in future periods based on contractual settlement quantities and dates. Our valuation of these instruments considers specific contractual terms, statistical and simulation analysis, present value concepts and other internal assumptions related to (i) contract maturities that extend beyond the periods in which quoted market prices are available; (ii) the uniqueness of the contract terms; (iii) the limited availability of forward pricing information in markets where there is a lack of viable participants, such as in the Pennsylvania-New Jersey-Maryland (PJM) forward power market and the forward market for ammonia; and (iv) our creditworthiness or that of our counterparties (adjusted for collateral related to our asset positions). Since a significant portion of the fair value of our power-related derivatives and certain of our remaining natural gas derivatives with longer terms or in less liquid markets than similar Level 2 derivatives rely on the techniques discussed above, we classify these instruments as Level 3 instruments.

Listed below are the fair values of our financial instruments that are recorded at fair value classified in each level at December 31, 2009 and 2008 (in millions):


	December 31, 2009								December 31, 2008
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Commodity-based derivatives
Production-related natural gas and oil derivatives	$	—	$	169	$	—	$	169	$	—	$	727	$	—	$	727
Other natural gas derivatives		—		106		21		127		—		141		31		172
Power-related derivatives		—		—		37		37		—		—		72		72
Interest rate and foreign currency derivatives		—		11		—		11		—		106		—		106
Marketable securities invested in non-qualified compensation plans		20		—		—		20		19		—		—		19

Total assets	$	20	$	286	$	58	$	364	$	19	$	974	$	103	$	1,096

116


	December 31, 2009											December 31, 2008
	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Liabilities
Commodity-based derivatives
Production-related natural gas and oil derivatives	$	—	$	(42	)	$	—		$	(42	)	$	—	$	(45	)	$	—		$	(45	)
Other natural gas derivatives		—		(153	)		(133	)		(286	)		—		(255	)		(186	)		(441	)
Power-related derivatives		—		—			(386	)		(386	)		—		—			(510	)		(510	)
Interest rate derivatives		—		(17	)		—			(17	)		—		(21	)		—			(21	)
Other		—		—			(31	)		(31	)		—		—			(55	)		(55	)

Total liabilities	$	—		(212	)		(550	)		(762	)	$	—		(321	)		(751	)		(1,072	)

Total	$	20	$	74		$	(492	)	$	(398	)	$	19	$	653		$	(648	)	$	24

The following table presents the changes in our financial assets and liabilities included in Level 3 for the year ended December 31, 2009 (in millions):


										Change in Fair
				Change in Fair			Change in Fair			Value Reflected
	Balance at			Value Reflected			Value Reflected			in Long-Term
	Beginning of			in Operating			in Operating			Financing						Settlements,			Balance at End
	Period			Revenues⁽¹⁾			Expenses⁽²⁾			Obligations⁽³⁾			Transfers⁽⁴⁾			Net			of Period
December 31, 2009

Assets	$	103		$	(38	)	$	—		$	—		$	—		$	(7	)	$	58
Liabilities		(751	)		75			21			—			—			105			(550	)

Total	$	(648	)	$	37		$	21		$	—		$	—		$	98		$	(492	)


December 31, 2008

Assets	$	250		$	2		$	—		$	(24	)	$	(85	)	$	(40	)	$	103
Liabilities		(839	)		(57	)		(19	)		—			—			164			(751	)

Total	$	(589	)	$	(55	)	$	(19	)	$	(24	)	$	(85	)	$	124		$	(648	)


⁽¹⁾		Includes approximately $11 million of net losses and $46 million of net gains that had not been realized through settlements for the year ended December 31, 2009 and 2008.

⁽²⁾		Includes approximately $18 million of net losses and $19 million of net gains that had not been realized through settlements for the year ended December 31, 2009 and 2008.

⁽³⁾		Includes approximately $24 million of net losses that had not been realized through settlements for the year ended December 31, 2008.

⁽⁴⁾		We transferred our foreign currency swaps and certain of our interest rate swaps out of Level 3 based on additional information received about their fair values during 2008.

On certain derivative contracts recorded as assets in the table above, we are exposed to the risk that our counterparties may not perform or post the required collateral, if any, with us. We have assessed this counterparty risk in light of the collateral our counterparties have posted with us. Based on this assessment, we have determined that our exposure is primarily related to our production-related derivatives and is limited to eight financial institutions, each of which has a current Standard & Poor’s credit rating of A or better.

The following table reflects the carrying value and fair value of our financial instruments:


	As of December 31,
	2009						2008
	Carrying			Fair			Carrying			Fair
	Amount			Value			Amount			Value
	(In millions)
Long-term financing obligations, including current maturities	$	13,868		$	14,151		$	13,908		$	11,227
Marketable securities invested in non-qualified compensation plans		20			20			19			19
Commodity-based derivatives		(381	)		(381	)		(25	)		(25	)
Interest rate and foreign currency derivatives		(6	)		(6	)		85			85
Other		17			17			72			72

As of December 31, 2009 and 2008, the carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables represented fair value because of the short-term nature of these instruments. The carrying amounts of our restricted cash and noncurrent receivables approximate their fair value based on their interest rates and our assessment of our ability to recover these amounts. We estimated the fair value of debt based on quoted market prices for the same or similar issues, including consideration of our credit risk related to those instruments.

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8. Price Risk Management Activities

Our price risk management activities relate primarily to derivatives entered into to hedge or otherwise reduce (i) the commodity price exposure on our natural gas and oil production; (ii) interest rate exposure on our long-term debt; and (iii) foreign currency exposure on our Euro-denominated debt. We also hold other derivatives not intended to hedge these exposures, including those related to our legacy trading activities. When we enter into derivative contracts, we may designate the derivative as either a cash flow hedge or a fair value hedge, at which time we document our intent. Hedges of cash flow exposure are designed to hedge forecasted sales transactions or limit the variability of cash flows to be received or paid related to a recognized asset or liability. Hedges of fair value exposure are entered into to protect the fair value of a recognized asset, liability or firm commitment.

Production-Related Derivatives. We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts. These derivatives do not mitigate all of the commodity price risks of our sales of natural gas and oil production and, as a result, we are subject to commodity price risks on our remaining forecasted production. Prior to removing the accounting hedge designation on all of our production-related derivatives during 2008, certain of these derivatives were designated as cash flow hedges. As of December 31, 2009 and 2008, we have production-related derivatives on 313 TBtu and 187 TBtu of natural gas and 4,016 MBbl and 3,431 MBbl of oil.

Other Commodity-Based Derivatives. In our Marketing segment, we have long-term natural gas and power derivative contracts that are primarily related to our legacy trading activities. These contracts include forwards, swaps and options that we either intend to manage until their expiration or liquidate to the extent it is economical and prudent. None of these derivatives are designated as accounting hedges. As of December 31, 2009 and 2008, our other commodity based derivative contracts include (i) natural gas contracts that obligate us to sell natural gas to power plants and have various expiration dates ranging from 2012 to 2019, with expected obligations under individual contracts with third parties ranging from 12,550 MMBtu/d to 104,750 MMBtu/d and (ii) derivative power contracts that require us to swap locational differences in power prices between three power plants in the PJM eastern region with the PJM west hub on approximately 3,700 GWh from 2010 to 2012, 2,400 GWh for 2013 and 1,700 GWh from 2014 to April 2016. These contracts also require us to provide approximately 1,700 GWh of power per year and approximately 71 GW of installed capacity per year in the PJM power pool through April 2016. For these natural gas and power contracts, we have entered into contracts in previous years to economically mitigate our exposure to commodity price changes on substantially all of these volumes, although we continue to have exposure to changes in locational price differences between the PJM regions.

Interest Rate Derivatives. We have long-term debt with variable interest rates that exposes us to changes in market-based interest rates. We use interest rate swaps to convert the variable rates on certain of these debt instruments to a fixed interest rate. As of December 31, 2009 and 2008, we have interest rate swaps designated as cash flow hedges that converted the interest rate on approximately $169 million of debt from a LIBOR-based variable rate to a fixed rate of 4.56%.

We also have long-term debt with fixed interest rates that exposes us to paying higher than market rates should interest rates decline. We use interest rate swaps to protect the value of certain of these debt instruments by converting the fixed amounts of interest due under the debt agreements to variable interest payments. We record changes in the fair value of these derivatives in interest expense. As of December 31, 2009 and 2008, we have interest rate swaps designated as fair value hedges that convert the interest rate on approximately $218 million of debt from a fixed rate to a variable rate of LIBOR plus 4.18%. In addition, as of December 31, 2009 and 2008, we had interest rate swaps not designated as hedges with a notional amount of $222 million for which changes in the fair value of these swaps are substantially eliminated by offsetting swaps contracts.

Cross-Currency Derivatives. During 2009, our Euro-denominated debt matured and we settled all of our related cross-currency swaps. These cross-currency swaps were designated as fair value hedges of this debt, and for the year ended December 31, 2009, these swaps increased our interest expense by approximately $3 million and decreased our other income by approximately $26 million as result of changing interest and foreign currency rates during 2009.

118

Balance Sheet Presentation. Our derivatives are reflected at fair value on our balance sheet as assets and liabilities from price risk management activities. We net our derivative assets and liabilities for counterparties where we have a legal right of offset and classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. The following table presents the fair value of our derivatives on a gross basis by contract type. We have not netted these contracts for counterparties where we have a legal right of offset or for cash collateral associated with these derivatives. At December 31, 2009, cash collateral held was not material.


	Fair Value of Derivative Assets						Fair Value of Derivative Liabilities
	December 31, 2009			December 31, 2008			December 31, 2009			December 31, 2008
	(In millions)
Derivatives Designated as Hedges:
Cash flow hedges
Interest rate derivatives	$	1		$	—		$	(17	)	$	(21	)
Fair value hedges
Interest rate derivatives		10			12			—			—
Cross-currency derivatives		—			94			—			—

Total derivatives designated as hedges		11			106			(17	)		(21	)


Derivatives not Designated as Hedges:
Commodity-based derivatives
Production-related		239			738			(112	)		(56	)
Other natural gas		519			853			(678	)		(1,122	)
Power-related		57			111			(406	)		(549	)

Total commodity-based derivatives		815			1,702			(1,196	)		(1,727	)
Interest rate derivatives		10			12			(10	)		(12	)

Total derivatives not designated as hedges		825			1,714			(1,206	)		(1,739	)


Impact of master netting arrangements⁽¹⁾		(492	)		(743	)		492			743

Total assets (liabilities) from price risk management activities		344			1,077			(731	)		(1,017	)
Other derivatives^{( 2)}		—			—			(31	)		(55	)

Total derivatives	$	344		$	1,077		$	(762	)	$	(1,072	)


⁽¹⁾		Includes adjustments to net assets or liabilities to reflect master netting arrangements we have with our counterparties.

⁽²⁾		Included in other current and noncurrent liabilities in our balance sheets.

Statements of Income, Comprehensive Income and Cash Flow Presentation. Derivatives that we have designated as accounting hedges impact our revenues or expenses based on the nature and timing of the transactions that they hedge. Changes in the fair value of derivatives designated as cash flow hedges are deferred in accumulated other comprehensive income or loss to the extent they are effective and then recognized in earnings when the hedged transactions occur. Ineffectiveness related to our cash flow hedges is recognized in earnings as it occurs. Changes in the fair value of derivatives that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair value of the related hedged assets, liabilities or firm commitments.

Our interest rate derivatives did not have a significant impact to our interest expense or other comprehensive income (loss) during 2009, and we did not record any ineffectiveness on these derivatives during 2009. The fair value of our interest rate derivatives designated as cash flow hedges was a liability of approximately $16 million as of December 31, 2009, and we do not anticipate that the accumulated other comprehensive loss associated with these derivatives that will be reclassified to interest expense during the next twelve months will be significant to our financial statements.

Derivatives that we have not designated as accounting hedges are marked-to-market each period and changes in their fair value are generally reflected as operating revenues. In our cash flow statement, cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows (other than those derivatives intended to hedge the principal amounts of our foreign currency denominated debt, which are recorded in financing activities). Listed below are the impacts of our commodity-based derivatives to our income statement and statement of comprehensive income for the year ended December 31, 2009:

119


	Operating		Other Comprehensive
	Revenues		Income (Loss)
	(In millions)
Production-related derivatives⁽¹⁾	$	687	$	(406	)

Other natural gas and power derivatives not designated as hedges		41		—

Total commodity-based derivatives⁽²⁾	$	728	$	(406	)


⁽¹⁾		Included in operating revenues for the year ended December 31, 2009 is $406 million representing the amount of accumulated other comprehensive income that was reclassified into income related to commodity-based derivatives for which we removed the hedging designation during the fourth quarter of 2008. We anticipate that approximately $13 million of our accumulated other comprehensive loss will be reclassified to operating revenues during the next twelve months.

⁽²⁾		We also had approximately $21 million of gains for the year ended December 31, 2009 recognized in operating expenses related to other derivative instruments not associated with our price risk management activities.

Credit Risk

We are subject to credit risk related to our financial instrument assets. Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. These exposures are offset where we have a legally enforceable right of setoff. We maintain credit policies with regard to our counterparties in our price risk management activities to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition (including credit rating), (ii) collateral under certain circumstances (including cash in advance, letters of credit, and guarantees), (iii) the use of margining provisions in standard contracts, and (iv) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.

We use daily margining provisions in our financial contracts, most of our physical power agreements and our master netting agreements, which require a counterparty to post cash or letters of credit when the fair value of the contract exceeds the daily contractual threshold. The threshold amount is typically tied to the published credit rating of the counterparty. Our margining collateral provisions also allow us to terminate a contract and liquidate all positions if the counterparty is unable to provide the required collateral. Under our margining provisions, we are required to return collateral if the amount of posted collateral exceeds the amount of collateral required. Collateral received or returned can vary significantly from day to day based on the changes in the market values and our counterparty’s credit ratings. Furthermore, the amount of collateral we hold may be more or less than the fair value of our derivative contracts with that counterparty at any given period. The following table presents a summary of our exposure from derivative contracts, net of collateral and liabilities where a right of offset exists. It is presented by type of derivative counterparty in which we had net asset exposure as of December 31, 2009 and 2008:


			Below			Not
Counterparty	Investment Grade⁽¹⁾		Investment Grade⁽¹⁾			Rated⁽¹⁾			Total
	(In millions)
December 31, 2009
Energy marketers	$	21	$	106		$	—		$	127
Natural gas and electric utilities		—		37			21			58
Financial institutions and other		156		—			—			156

Net financial instrument assets		177		143			21			341
Collateral held by us		—		(123	)		(21	)		(144	)

Net exposure from derivative assets	$	177	$	20		$	—		$	197


December 31, 2008
Energy marketers	$	247	$	72		$	—		$	319
Natural gas and electric utilities		—		—			30			30
Financial institutions and other		480		—			3			483

Net financial instrument assets		727		72			33			832
Collateral held by us		—		(62	)		(30	)		(92	)

Net exposure from derivative assets	$	727	$	10		$	3		$	740


⁽¹⁾		“Investment Grade” and “Below Investment Grade” are determined using publicly available credit ratings. “Investment Grade” includes counterparties with a minimum Standard & Poor’s rating of BBB — or Moody’s Investor Service rating of Baa3. “Below Investment Grade” includes counterparties with a public credit rating that does not meet the criteria of “Investment Grade”. “Not Rated” includes counterparties that are not rated by any public rating service.

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We have approximately 44 counterparties as of December 31, 2009. If one of these counterparties fails to perform, we may recognize an immediate loss in our earnings, as well as additional financial impacts in the future delivery periods to the extent a replacement contract at the same prices and/or quantities cannot be established.

As of December 31, 2009, three counterparties, Williams Gas Marketing, Citibank and RRI Energy Services comprise 31 percent, 13 percent and 11 percent, respectively, of our net financial instrument exposure. As of December 31, 2008, three counterparties, J Aron, Merrill Lynch, and Societe Generale, comprised 30 percent, 37 percent and 12 percent, respectively, of our net financial instrument asset exposure. The concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

9. Regulatory Assets and Liabilities

Our regulatory assets and liabilities relate to our interstate pipeline operations and are included in other current and non-current assets and liabilities on our balance sheets. These balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities as of December 31:


	2009		2008
	(In millions)
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	14	$	31
Other		11		8

Total current regulatory assets		25		39

Non-current regulatory assets
Taxes on capitalized funds used during construction		170		137
Postretirement benefits		13		21
Unamortized net loss on reacquired debt		62		72
Other		25		22

Total non-current regulatory assets		270		252

Total regulatory assets	$	295	$	291


Current regulatory liabilities
Gas retained and not used in operations	$	22	$	46
Environmental liability		28		—
Other		12		21

Total current regulatory liabilities		62		67


Non-current regulatory liabilities
Environmental liability		112		157
Property and plant depreciation		51		60
Postretirement benefits		59		32
Plant regulatory liability		11		11
Other		3		3

Total non-current regulatory liabilities		236		263

Total regulatory liabilities	$	298	$	330

The significant regulatory assets and liabilities include:

Difference between gas retained and gas consumed in operations: These amounts reflect the value of the volumetric difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent fuel filing periods.

Taxes on capitalized funds used during construction: Regulatory asset balance 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 and are recovered over the depreciable lives of the long lived asset to which they relate.

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Postretirement benefits: Represents 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 recovered in rates. Postretirement benefit amounts have been included in the rate base computations for certain of our pipelines and are recoverable in such periods as benefits are funded.

Unamortized net loss on reacquired debt: Amount represents the deferred and amortized portion of gains and losses on reacquired debt which are not included in the rate base, but are recovered over the original life of the debt issue through the authorized rate of return.

Gas retained and not used in operations: The regulatory liabilities related to gas retained and not used in operations have not been included in the rate base but given current pipeline tariffs are expected to be returned in subsequent fuel filing periods.

Environmental liability: Includes amounts collected, substantially in excess of certain PCB environmental remediation costs to date, through a surcharge to TGP’s customers under a settlement approved by the FERC in November of 1995. At this time the environmental liability is not deducted from the rate base on which TGP is allowed to earn current return.

Property and plant depreciation: Amounts represent 1) the deferral of customer-funded amounts for costs of future asset retirements, and 2) the excess of ratemaking depreciation expense over the depreciation expense recorded in the financial statements. These amounts are included in the rate base computations and the depreciation-related amounts are refunded over the lives of the long-lived assets to which they relate.

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10. Other Assets and Liabilities

Below is the detail of our other current and other non-current assets and liabilities on our balance sheets as of December 31:


	2009		2008
	(In millions)
Other current assets
Prepaid expenses	$	71	$	69
Margin and other deposits held by others		8		5
Deposits		6		—
Regulatory assets (Note 9)		25		39
Other		16		35

Total	$	126	$	148


Other non-current assets
Pension and other postretirement benefits (Note 14)	$	88	$	42
Notes receivable from affiliates		78		240
Restricted cash (Note 1)		8		57
Unamortized debt expenses		123		112
Regulatory assets (Note 9)		270		252
Long-term receivables		90		50
Other		104		102

Total	$	761	$	855


	2009		2008
	(In millions)
Other current liabilities
Accrued taxes, other than income	$	114	$	83
Income taxes		19		4
Environmental, legal and rate reserves (Note 13)		193		131
Deposits		32		69
Pension and other postretirement benefits (Note 14)		44		46
Dividends payable		16		44
Regulatory liabilities (Note 9)		62		67
Other		204		188

Total	$	684	$	632


Other non-current liabilities
Environmental and legal reserves (Note 13)	$	138	$	161
Pension and other postretirement benefits (Note 14)		597		675
Regulatory liabilities (Note 9)		236		263
Asset retirement obligations (Note 11)		133		171
Insurance reserves		75		84
Other		312		325

Total	$	1,491	$	1,679

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11. Property, Plant and Equipment

Depreciable lives. The table below presents the depreciation method and depreciable lives of our property, plant and equipment:


			Depreciable
	Method		Lives
			(In years)
Regulated transmission systems	Composite			⁽¹⁾
Non-regulated assets
Natural gas and oil properties		⁽²⁾		⁽²⁾
Transmission and storage facilities	Straight-line			15-24
Gathering and processing systems	Straight-line			15-40
Transportation equipment	Straight-line			5
Buildings and improvements	Straight-line			3-47
Office and miscellaneous equipment	Straight-line			1-10


⁽¹⁾		Under the composite (group) method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we redevelop our transportation rates when we file with the FERC for an increase or decrease in rates.

⁽²⁾		Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated or impaired.

Excess purchase costs. As of December 31, 2009 and 2008, TGP and EPNG have excess purchase costs associated with their historical acquisition. Total excess costs on these pipelines were approximately $2.5 billion and accumulated depreciation was approximately $0.5 billion at December 31, 2009 and 2008. These excess costs are being depreciated over the estimated life of the pipeline assets to which the costs were assigned, and our related depreciation expense for each year ended December 31, 2009, 2008, and 2007 was approximately $42 million. Such excess costs are not recoverable in our rates under current FERC policies.

Capitalized costs during construction. We capitalize a carrying cost on funds related to the construction of long-lived assets and reflect these as increases in the cost of the asset on our balance sheet. This carrying cost consists of (i) an interest cost on our debt that could be attributed to the assets being constructed, and (ii) in our regulated transmission business, a return on our equity that could be attributed to the assets being constructed. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction of interest expense in our income statements and were $48 million, $45 million and $50 million during the years ended December 31, 2009, 2008 and 2007. The equity portion is calculated using the most recent FERC approved equity rate of return. Equity amounts capitalized are included as other non-operating income on our income statement and were $61 million, $37 million and $32 million during the years ended December 31, 2009, 2008 and 2007.

Construction work-in progress. At December 31, 2009 and 2008, we had approximately $3.6 billion and $2.6 billion of construction work-in-progress included in our property, plant and equipment.

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Asset retirement obligations. We have legal obligations associated with the retirement of our natural gas and oil wells and related infrastructure, natural gas pipelines, transmission facilities and storage wells, and obligations related to our corporate headquarters building. In our exploration and production operations, we have obligations to plug wells when abandoned because production is exhausted or we no longer plan to use the wells. In our pipeline operations, our legal obligations primarily involve purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities and in our corporate headquarters if these facilities are ever demolished, replaced or renovated. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. In estimating our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount rates that currently range from 6 to 12 percent based on when the liabilities were recorded. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations. Typically, these changes result from obtaining new information in our Exploration and Production segment about the timing of our obligations to plug and abandon our natural gas and oil wells and the costs to do so and from certain other events that accelerate the timing of asset retirements (e.g. the impact of hurricanes on our Exploration and Production segment and Pipelines segment). In our pipelines operations, we intend on operating and maintaining our natural gas pipeline and storage systems as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.

The net asset retirement obligation as of December 31 reported on our balance sheet in other current and non-current liabilities and the changes in the net liability for the years ended December 31 were as follows:


	2009			2008
	(In millions)
Net asset retirement obligation at January 1	$	254		$	253
Liabilities settled		(72	)		(120	)
Accretion expense		21			16
Liabilities incurred		16			31
Changes in estimate		72			74

Net asset retirement obligation at December 31	$	291		$	254

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12. Debt, Other Financing Obligations and Other Credit Facilities


	Year Ended December 31,
	2009		2008
	(In millions)
Short-term financing obligations, including current maturities	$	477	$	1,090
Long-term financing obligations		13,391		12,818

Total	$	13,868	$	13,908

The following provides additional detail on our long-term financing obligations:


	Year Ended December 31,
	2009		2008
	(In millions)
CIG
Notes and debentures, 5.95% through 6.85%, due 2015 through 2037	$	475	$	475
El Paso Corporation
Notes, 6.70% through 12%, due 2010 through 2037		6,362		6,936
$1.5 billion revolver, variable due 2012		425		522
EPNG
Notes, 5.95% through 8.625%, due 2010 through 2032		1,169		1,169
El Paso Exploration & Production Company (EPEP)
Senior note, 7.75%, due 2013		1		1
Revolving credit facility, variable due 2012		834		914
EPB
Revolving credit facility, variable due 2012		520		585
Notes, 7.76% through 8.00%, due 2011 through 2013		140		140
Notes, variable due 2012		35		35
SNG
Notes, 5.9% through 8.0%, due 2017 through 2032		911		911
TGP
Notes, 6.0% through 8.375%, due 2011 through 2037		1,876		1,626
Other		237		252

		12,985		13,566

Other financing obligations
Capital Trust I, due 2028		325		325
Ruby Pipeline Holding Company loan commitment⁽¹⁾		217		—
Other		455		116

Subtotal		13,982		14,007
Less:
Other, including unamortized discounts and premiums		114		99
Current maturities		477		1,090

Total long-term financing obligations, less current maturities	$	13,391	$	12,818


⁽¹⁾		Amounts drawn on this commitment are convertible into a preferred equity interest in Ruby Pipeline Holding Company, L.L.C. (Ruby) subject to satisfaction of certain conditions. For further information, see Note 18.

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Changes in Long-Term Financing Obligations. During 2009, we had the following changes in our long-term financing obligations (in millions):


		Book Value			Cash
Company	Interest Rate	Increase (Decrease)			Received /(Paid)
Issuances
El Paso notes due 2016⁽¹⁾	8.250%	$	478		$	473
TGP notes due 2016⁽¹⁾	8.000%		237			234
Southern LNG notes due 2014 and 2016	9.600%		135			134
Elba Express Company LLC credit facility	variable		138			130
Ruby Holding Company loan commitment	7.000%		217			211
Ruby Pipeline, LLC term loan	variable		145			144
EPB revolving credit facilities	variable		192			192
EPEP revolving credit facility	variable		100			100

Increases through December 31, 2009		$	1,642		$	1,618


Repayments, repurchases and other
El Paso Corporation
Notes due 2009	6.375% to 7.125%	$	(1,054	)	$	(1,054	)⁽²⁾
Revolving credit facilities	variable		(97	)		(97	)
EPB revolving credit facilities	variable		(257	)		(257	)
EPEP revolving credit facility	variable		(180	)		(180	)
Ruby Pipeline, LLC term loan	variable		(145	)		(145	)
Other	various		51			(18	)

Decreases through December 31, 2009		$	(1,682	)	$	(1,751	)


⁽¹⁾		Principal amount of the notes is $500 million for El Paso Corporation and $250 million for TGP.

⁽²⁾		Amount does not reflect $83 million received in conjunction with the settlement of fair value hedges related to our Euro denominated notes.

Debt Maturities. Aggregate maturities of the principal amounts of long-term financing obligations as of December 31, 2009 for the next 5 years and in total thereafter are as follows (in millions):


2010	$	477	⁽¹⁾
2011		691
2012		2,294
2013		619
2014		478
Thereafter		9,423

Total long-term financing obligations, including current maturities	$	13,982


⁽¹⁾		Amount includes approximately $217 million of Ruby debt which is convertible into a preferred equity interest in Ruby subject to satisfaction of certain conditions. For further information, see Note 18.

Credit Facilities/Letters of Credit

As of December 31, 2009, subject to the terms of various agreements, we have total available capacity under credit agreements (not including capacity available under EPB’s $750 million revolving credit facility) of approximately $1.3 billion. Below is a description of our existing credit facilities as of December 31, 2009:

$1.5 Billion Revolving Credit Agreement. We have a $1.5 billion revolving credit facility that matures in November 2012. El Paso and certain of its subsidiaries have guaranteed the facility, which is collateralized by our stock ownership in EPNG and TGP who are also eligible borrowers.

Under the $1.5 billion revolving credit facility, we can borrow funds at LIBOR plus 1.25% based on a current applicable margin or issue letters of credit at 1.375% of the amount issued. We pay an annual commitment fee of 0.25% (based on a current applicable margin) on any unused capacity under the revolving credit facility. Under the credit agreement, the applicable margin used to calculate interest on borrowings, letters of credit and commitment fees is determined by a variable pricing grid tied to the credit ratings of our senior secured debt. As of December 31, 2009, we had approximately $0.2 billion of letters of credit issued and $0.4 billion of debt outstanding under this facility. As of December 31, 2009, our remaining capacity under the facility is approximately $0.8 billion.

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Unsecured Revolving Credit Facility. We have a $500 million unsecured revolving credit facility that matures in July 2011 with a third party and a third party trust that provides for both borrowings and issuing letters of credit. We are required to pay fixed facility fees at a rate of 2.34% on the total committed amount of the facility. In addition, we will pay interest on any borrowings at a rate comprised of either LIBOR or a base rate. Substantially all of the capacity under this facility has been used to issue letters of credit. As of December 31, 2009, our remaining capacity under this facility is approximately $24 million.

Other Unsecured Credit Facilities. During 2009, $500 million of letter of credit facilities we entered into in 2007 matured. As of December 31, 2009, we had a total of $325 million of other letter of credit facilities, not otherwise discussed above, with a weighted average fixed facility fee of 6.7% and maturities ranging from December 2013 to September 2014. As of December 31, 2009, our remaining capacity under these facilities is approximately $35 million.

EPEP $1.0 Billion Revolving Credit Agreement. As of December 31, 2009, we had $0.8 billion outstanding under EPEP’s $1.0 billion revolving credit facility and $0.2 billion of available capacity. Based on current borrowing levels, we pay interest at LIBOR plus 1.5% on borrowings, and a commitment fee of 0.35% on any unused capacity. This facility is collateralized by certain of our natural gas and oil properties, which are subject to revaluation on a semi-annual basis. In November 2009, our existing borrowing base was approved by the banks and as of December 31, 2009, the most recent determination was sufficient to fully support this facility. This facility matures in 2012.

EPEP $300 Million Revolving Credit Agreement. As of December 31, 2009, we had $300 million of available capacity under EPEP’s $300 million 364-day secured revolving credit facility that matures in December 2010. We pay LIBOR plus 3.5% for borrowed money, and a 0.75% commitment fee. This facility was originally entered into during December 2008. This facility is collateralized by certain of our natural gas and oil properties.

EPB’s $750 Million Revolving Credit Facility. In 2007, EPB and WIC (EPB’s subsidiary) entered into an unsecured 5-year revolving credit facility with an initial aggregate borrowing capacity of up to $750 million expandable to $1.25 billion for certain expansion projects and acquisitions. This facility is only available to EPB and its subsidiaries and borrowings are guaranteed by EPB and its subsidiaries. Amounts borrowed are non-recourse to El Paso. Approximately $520 million was outstanding under the credit facility and EPB had remaining capacity of approximately $215 million as of December 31, 2009. The credit facility has two pricing grids, one based on credit ratings and the other based on leverage. Currently, the leverage pricing grid is in effect and EPB’s cost of borrowings is LIBOR plus 0.425% based on EPB’s current leverage. EPB also pays a 0.125% facility fee and a 0.10% commitment utilization fee annually for this facility.

Letters of Credit. We enter into letters of credit in the ordinary course of our operating activities as well as periodically in conjunction with the sales of assets or businesses. During 2008, we entered into a new letter of credit facility with a bank to support our purchase commitments for pipe related to the Ruby Pipeline project. We have issued two letters of credit under this facility that total approximately $450 million. As of December 31, 2009, approximately $183 million remained outstanding and we pay 1.00% annually. The letters of credit mature in September 2010. As of December 31, 2009, we had total outstanding letters of credit issued under all of our facilities of approximately $1.3 billion. Included in this amount is $0.7 billion of letters of credit securing our recorded obligations related to price risk management activities.

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Restrictive Covenants

$1.5 Billion Revolving Credit Agreement. Our covenants under the $1.5 billion revolving credit facility include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, dividend restrictions, cross default and cross-acceleration provisions. A breach of any of these covenants could result in acceleration of our debt and other financial obligations and that of our subsidiaries. Under our credit agreement the most restrictive debt covenants and cross default provisions are:

(a)

Our ratio of Debt to Consolidated earnings before interest, income taxes, depreciation and amortization (EBITDA), each as defined in the credit agreement, shall not exceed 5.25 to 1 until maturity;

(b)

Our ratio of Consolidated EBITDA, as defined in the credit agreement, to interest expense plus dividends paid shall not be less than 2.0 to 1 until maturity;

(c)

EPNG and TGP cannot incur incremental Debt if the incurrence of this incremental Debt would cause their Debt to Consolidated EBITDA ratio, each as defined in the credit agreement, for that particular company to exceed 5.0 to 1; and

(d)

The occurrence of an event of default and after the expiration of any applicable grace period, with respect to debt in an aggregate principal amount of $200 million or more.

EPEP $1.0 Billion and $300 Million Revolving Credit Agreements. EPEP’s borrowings under these facilities are subject to various conditions. The financial coverage ratio under both facilities requires that EPEP’s EBITDA, as defined in the facility, to interest expense not be less than 2.0 to 1 and EPEP’s debt to EBITDA, each as defined in the credit agreement, must not exceed 4.0 to 1.

EPB’s $750 Million Revolving Credit Facility. The facility requires that EPB maintain, as of the end of each fiscal quarter, a consolidated leverage ratio, as defined in the facility, of less than 5.0 to 1 for any four consecutive quarters, and 5.5 to 1 for any three consecutive quarters subsequent to the consummation of specified permitted acquisitions having a value of greater than $25 million.

Other Restrictions and Provisions. In addition to the above restrictions and provisions, we and/or our subsidiaries are subject to various financial and non-financial covenants and restrictions. These covenants and restrictions include limitations of additional debt at some of our subsidiaries; limitations on the use of proceeds from borrowing at some of our subsidiaries; limitations, in some cases, on transactions with our affiliates; limitations on the incurrence of liens; potential limitations on some of our subsidiaries to participate in our cash management program and potential limitations on the ability of some of our subsidiaries to declare and pay dividends. As of December 31, 2009, the restricted net assets of our consolidated subsidiaries were approximately $534 million. Our most restrictive cross-acceleration provision is associated with the indenture of one of our subsidiaries. This indenture states that should an event of default occur resulting in the acceleration of other debt obligations of that subsidiary in excess of $10 million, the long-term debt obligation containing that provision could be accelerated. The acceleration of our debt would adversely affect our liquidity position and in turn, our financial condition.

We have also issued various guarantees securing financial obligations of our subsidiaries and affiliates with similar covenants as the above facilities.

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Other Financing Arrangements

Capital Trusts. El Paso Energy Capital Trust I (Trust I), is a wholly owned business trust formed in March 1998 that issued 6.5 million of 4.75 percent trust convertible preferred securities for $325 million. Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75 percent convertible subordinated debentures we issued, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We also have two wholly owned business trusts, El Paso Energy Capital Trust II and III (Trust II and III), under which we have not issued securities. We provide a full and unconditional guarantee of Trust I’s preferred securities, and would provide the same guarantee if securities were issued under Trust II and III.

Trust I’s preferred securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75 percent, carry a liquidation value of $50 per security plus accrued and unpaid distributions and are convertible into our common shares at any time prior to the close of business on March 31, 2028, at the option of the holder at a rate of 1.2022 common shares for each Trust I preferred security (equivalent to a conversion price of $41.59 per common share). We have classified these securities as long-term debt and we have the right to redeem these securities at any time.

WYCO Development L.L.C. (WYCO). In June 2009 and November 2008, the Totem Gas Storage facility and the High Plains pipeline were placed in service. We constructed the storage and pipeline facilities and our joint venture partner, an affiliate of Public Service Company of Colorado (PSCo), in WYCO funded 50 percent of the construction costs. We reflected these payments made by our joint venture partner as other non-current liabilities on our balance sheet during construction. Upon completion, our obligations for these construction advances were converted into a financing obligation to WYCO and, accordingly, we reclassified the amounts from other non-current liabilities to debt and other financing obligations. The principal amount of the Totem Gas Storage facility and the High Plains pipeline were $69 million and $106 million, respectively, as of December 31, 2009, which will be paid in monthly installments through 2060 and 2043, respectively. As of December 31, 2008, the principal amount of the Totem Gas Storage facility was $108 million. Interest payments on these obligations are based on 50 percent of the operating results of the facilities’ and are currently estimated at a 15.5 percent rate as of December 31, 2009.

Non-Recourse Project Financings. Several of our subsidiaries and investments have debt obligations related to their costs of construction or acquisition. This project financing debt is recourse only to the project company and assets (i.e. without recourse to El Paso). As of December 31, 2009, one international power project accounted for as an equity investment is in default under its debt agreement; however, we have no material exposure as a result of this default.

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13. Commitments and Contingencies

Legal Proceedings

Cash Balance Plan Lawsuit. In December 2004, a purported class action lawsuit entitled Tomlinson, et al.v. El Paso Corporation and El Paso Corporation Pension Plan was filed in U.S. District Court for Denver, Colorado. The lawsuit alleges various violations of the Employee Retirement Income Security Act (ERISA) and the Age Discrimination in Employment Act as a result of our change from a final average earnings formula pension plan to a cash balance pension plan. The trial court has dismissed the claims that our plan violated ERISA. Our costs and legal exposure related to this lawsuit are not currently determinable.

Retiree Medical Benefits Matters. In 2002, a lawsuit entitled Yolton et al. v. El Paso Tennessee Pipeline Co. and Case Corporation was filed in a federal court in Detroit, Michigan. The lawsuit was filed on behalf of a group of retirees of Case Corporation (Case) that alleged they are entitled to retiree medical benefits under a medical benefits plan for which we serve as plan administrator pursuant to a merger agreement with Tenneco Inc. Although we had asserted that our obligations under the plan were subject to a cap pursuant to an agreement with the union for Case employees, the trial court ruled that the benefits were vested and not subject to the cap. As a result, we were obligated to pay the amounts above the cap, and we adjusted our existing indemnification accrual using current actuarial assumptions and reclassified our liability as a postretirement benefit obligation. See Note 14 for a discussion of the impact of this matter. We intend to pursue appellate options following the determination by the trial court of any damages incurred by the plaintiffs during the period when premium payments above the cap were paid by the retirees. We believe our accruals established for this matter are adequate.

Price Reporting Litigation. Beginning in 2003, several lawsuits were filed against El Paso Marketing L.P. (EPM) alleging that El Paso, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. The first set of cases, involving similar allegations on behalf of commercial and residential customers, was transferred to a multi-district litigation proceeding (MDL) in the U.S. District Court for Nevada and styled In re: Western States Wholesale Natural Gas Antitrust Litigation. These cases were dismissed. The U.S. Court of Appeals for the Ninth Circuit, however, reversed the dismissal and ordered that these cases be remanded to the trial court. The second set of cases also involve similar allegations on behalf of certain purchasers of natural gas. These include Farmland Industries v. Oneok Inc., et al. (filed in state court in Wyandotte County, Kansas in July 2005) and Missouri Public Service Commission v. El Paso Corporation, et al. (filed in the circuit court of Jackson County, Missouri at Kansas City in October 2006), and the purported class action lawsuits styled: Leggett, et al. v. Duke Energy Corporation, et al. (filed in Chancery Court of Tennessee in January 2005); Ever-Bloom Inc., et al. v. AEP Energy Services Inc., et al. (filed in federal court for the Eastern District of California in September 2005); Learjet, Inc., et al. v. Oneok Inc., et al. (filed in state court in Wyandotte County, Kansas in September 2005); Breckenridge, et al. v. Oneok Inc., et al. (filed in state court in Denver County, Colorado in May 2006); Arandell, et al. v. Xcel Energy, et al. (filed in the circuit court of Dane County, Wisconsin in December 2006); Heartland, et al. v. Oneok Inc., et al. (filed in the circuit court of Buchanan County, Missouri in March 2007); and Newpage Wisconsin System, Inc., et al. (filed in the circuit court of Wood County, Wisconsin in March 2009). The Leggett case was dismissed by the Tennessee state court, but in October 2008, the Tennessee Court of Appeals reversed the dismissal, remanding the matter to the trial court. The decision has been appealed to the Tennessee Supreme Court. The Missouri Public Service case was dismissed by the state court, which dismissal was upheld by the appellate court, and appealed to the Missouri Supreme Court. The remaining cases have all been transferred to the MDL proceeding. The Breckenridge Case has been dismissed as to El Paso and other defendants, and a motion for reconsideration of this decision was denied. This ruling can still be appealed. Discovery is proceeding in the MDL cases, and motions for summary judgment based on federal preemption have been filed. We reached an agreement to settle the Western States and Ever-Bloom cases which was approved by the court and paid. Our costs and legal exposure related to the remaining lawsuits and claims are not currently determinable.

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Gas Measurement Cases. A number of our subsidiaries 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 claim are not currently determinable.

MTBE. Certain of our subsidiaries used, produced, sold or distributed methyl tertiary-butyl ether (MTBE) as a gasoline additive. Various lawsuits were filed throughout the U.S. regarding the potential impact of MTBE on water supplies. The lawsuits have been brought by different parties, including state attorney generals, water districts and individual water companies. They have sought different remedies, including remedial activities, damages, attorneys’ fees and costs. These cases were initially consolidated for pre-trial purposes in multi-district litigation in the U.S. District Court for the Southern District of New York. Several cases were later remanded to state court. In 2008, we settled 59 of these lawsuits. The settlement payments were covered by insurance. Additionally, in July 2009, we settled an additional case which our insurance covered. Following dismissal of the settled cases, we have 32 lawsuits that remain. Although there have been settlement discussions with other plaintiffs, such discussions have been unsuccessful to date. While the damages claimed in the remaining actions are substantial, there remains significant legal uncertainty regarding the validity of the causes of action asserted and the availability of the relief sought. We have or will tender these remaining cases to our insurers. It is likely that our insurers will assert denial of coverage on the 12 most-recently filed cases. Our costs and legal exposure related to these remaining lawsuits 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 and claims that arise in the ordinary course of our business. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation. 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. As of December 31, 2009, we had approximately $67 million accrued, which has not been reduced by $1 million of related insurance receivables, for our outstanding legal and governmental proceedings.

Rates and Regulatory Matters

SNG Rate Case. In January 2010, the FERC approved SNG’s settlement in which SNG (i) increased its base tariff rates, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next general rate case to be effective after August 31, 2012 but no later than September 1, 2013, and (iv) extended the vast majority of SNG’s firm transportation contracts expiring prior to September 1, 2013 until August 31, 2013.

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EPNG Rate Case. In June 2008, EPNG filed a rate case with the FERC as required under the settlement of its previous rate case. The filing proposed an increase in EPNG’s base 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 EPNG’s proposals in the technical conference proceeding. The FERC has appointed an administrative law judge to preside over a hearing if EPNG is unable to reach a negotiated settlement with its 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.

Notice of Proposed Rulemaking. On October 3, 2007, the Minerals Management Service (MMS) issued a notice of proposed rulemaking that is applicable to pipelines located in the Outer Continental Shelf (OCS). If adopted, the proposed rules would substantially revise MMS OCS pipeline and rights-of-way regulations. The proposed rules would have the effect of (i) increasing the financial obligations of entities which have pipelines and pipeline rights-of-way in the OCS, (ii) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines and rights-of-way in the OCS, and (iii) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS.

Other Matter

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. EPNG submitted the Navajo Nation’s consent agreement in support of EPNG’s pending application to the United States Department of the Interior (the Department) for an extension of the Department’s current right-of-way grant. We expect the submission will result in the Department’s final processing of our application. EPNG has filed with the FERC for recovery of payments under rights-of-way in its recent rate case.

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, we had accrued approximately $189 million for environmental matters, which has not been reduced by $24 million for amounts to be paid directly under government sponsored programs or through settlement arrangements. Our accrual includes approximately $185 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $4 million for related environmental legal costs. Of the $189 million accrual, $14 million was reserved for facilities we currently operate and $175 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites.

Our estimates of potential liability range from approximately $189 million to approximately $381 million. 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. By type of site, our reserves are based on the following estimates of reasonably possible outcomes:


	December 31, 2009
Sites	Expected		High
	(In millions)
Operating	$	14	$	20
Non-operating		159		320
Superfund		16		41

Total	$	189	$	381

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Below is a reconciliation of our accrued liability from January 1, 2009 to December 31, 2009 (in millions):


Balance as of January 1, 2009	$	204
Additions/adjustments for remediation activities		25
Payments for remediation activities		(40	)

Balance as of December 31, 2009	$	189

CERCLA Matters. As part of our environmental remediation projects, 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 33 active sites under the Comprehensive Environmental Response, Compensation and Liability Act (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. 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 issues are included in the previously indicated estimates for Superfund sites.

For 2010, we estimate that our total remediation expenditures, net of expected recoveries, will be approximately $48 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $5 million in the aggregate for the years 2010 through 2014. These expenditures primarily relate to compliance with clean air regulations.

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.

Commitments, Purchase Obligations and Other Matters

Operating Leases. We maintain operating leases in the ordinary course of our business activities. These leases include those for office space, operating facilities and equipment. The terms of the agreements vary from 2010 until 2053. Future minimum annual rental commitments under our operating leases net of minimum sublease rentals at December 31, 2009, were as follows:


	Operating
Year Ending December 31,	Leases
	(In millions)
2010	$	14
2011		13
2012		12
2013		11
2014		11
Thereafter		20

Total	$	81

Rental expense on our lease obligations for the years ended December 31, 2009, 2008, and 2007 was $39 million, $39 million and $40 million.

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Guarantees and Indemnifications. We are involved in various joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.

Our potential exposure under guarantee and indemnification agreements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. For those arrangements with a specified dollar amount, we have a maximum stated value of approximately $0.8 billion, which primarily relates to indemnification arrangements associated with the sale of ANR Pipeline Company in 2007, our Macae power facility in Brazil, and other legacy assets. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 12. Included in the above maximum stated value are certain indemnification agreements that have expired; however, claims were made prior to the expiration of the related claim periods. We are unable to estimate a maximum exposure of our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

As of December 31, 2009, we have recorded obligations of $52 million related to our guarantee and indemnification arrangements. Our liability consists primarily of an indemnification that one of our subsidiaries provided related to its sale of an ammonia facility that is reflected in our financial statements at its estimated fair value. We have provided a partial parental guarantee of our subsidiary’s obligations under this indemnification. We believe that our guarantee and indemnification agreements for which we have not recorded a liability are not probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, among other considerations.

Purchase Obligations. During 2009, we entered into contracts to purchase pipe primarily associated with the Ruby Pipeline project and TGP’s 300 Line expansion which are anticipated to be placed in service between 2010 and 2011. Our estimated obligations under these agreements are approximately $1.3 billion in 2010 and approximately $300 million in 2011.

Other Commercial Commitments. In November 2009, the FERC approved an amendment to the 1995 FERC settlement that provides for interim refunds over a three year period of approximately $157 million of amounts collected related to certain environmental costs. In December 2009, TGP refunded approximately $30 million to their customers. These refunds are recorded as other current and non-current liabilities on our balance sheet and are expected to be paid over a three year period with interest.

We have various other commercial commitments and purchase obligations that are not recorded on our balance sheet. At December 31, 2009, we had firm commitments under transportation and storage capacity contracts of $643 million due at various times and other purchase and capital commitments (including maintenance, engineering, procurement and construction contracts) of approximately $360 million, the majority of which is due in less than one year.

We also hold cancelable easements or right-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Currently, our obligation under these easements is not material to the results of our operations. However, we have executed a long-term right-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).

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14. Retirement Benefits

Overview of Retirement Benefit Plans

Pension Plans. Our primary pension plan is a defined benefit plan that covers substantially all of our U.S. employees and provides benefits under a cash balance formula. Certain employees who participated in the prior pension plans of El Paso, Sonat, Inc. or The Coastal Corporation receive the greater of their cash balance benefits or their transition benefits under the prior plan formulas. Prior to December 31, 2008, we maintained two other frozen pension plans which provide benefits to former employees of our previously discontinued coal and convenience store operations. Effective December 31, 2008, these frozen plans were merged with our cash balance plan. We do not anticipate making any contributions to our cash balance pension plan in 2010.

In addition to our primary pension plan, we maintain a Supplemental Executive Retirement Plan (SERP) that provides additional benefits to selected officers and key management. The SERP provides benefits in excess of certain IRS limits that essentially mirror those in the primary pension plan. We expect to contribute $5 million to the SERP in 2010.

Retirement Savings Plan. We maintain a defined contribution plan covering all of our U.S. employees. We match 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on the overall performance of the Company relative to its peers. Amounts expensed under this plan were approximately $19 million, $20 million and $16 million for the years ended December 31, 2009, 2008 and 2007.

Other Postretirement Benefit Plans. We provide other postretirement benefits (OPEB), including medical benefits for closed groups of retired employees and limited postretirement life insurance benefits for current and retired employees. Medical benefits for these closed groups of retirees may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs, and we reserve the right to change these benefits. OPEB for our regulated pipeline companies are prefunded to the extent such costs are recoverable through rates. To the extent OPEB costs for our regulated pipeline companies differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $48 million to our other postretirement benefit plans in 2010.

Other Matters. In various court rulings prior to March 2008, we were required to indemnify Case Corporation (Case) for certain benefits paid to a closed group of Case retirees as further discussed in Note 13. In conjunction with those rulings, we recorded a liability for estimated amounts due under the indemnification using actuarial methods similar to those used in estimating our postretirement benefit plan obligations. This liability, however, was not included in our postretirement benefit obligations or disclosures prior to 2008.

In the first quarter of 2008, we received a summary judgment from the trial court on this matter, and thus became the primary party that is obligated to pay for these benefit payments. As a result of the judgment, we adjusted our obligation using current actuarial assumptions, recording a $65 million reduction to current and non-current other liabilities and to operation and maintenance expense. We also reclassified this obligation from an indemnification liability to a postretirement benefit obligation, which increased our overall postretirement benefit obligations by $280 million.

Benefit Obligation, Plan Assets and Funded Status. In accounting for our pension and other postretirement plans, we record an asset or liability based on the over funded or under funded status of each plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability for our regulated operations or in accumulated other comprehensive income (loss), a component of stockholders’ equity, for all other operations until those gains and losses are recognized in the income statement.

The table below provides information about our pension and OPEB plans. In 2008, we adopted the revised measurement date provisions for accounting for retirement benefits 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.

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	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
	(In millions)
Change in benefit obligation:⁽¹⁾
Benefit obligation — beginning of period	$	1,989		$	2,027		$	673		$	418
Service cost		19			18			—			—
Interest cost		121			150			38			44
Participant contributions		—			—			10			13
Actuarial (gain) loss		159			(12	)		(28	)		(12	)
Benefits paid⁽²⁾		(171	)		(209	)		(51	)		(72	)
Case liability reclassification		—			—			—			282
Other		16			15			—			—

Benefit obligation — end of period	$	2,133		$	1,989		$	642		$	673

Change in plan assets:
Fair value of plan assets — beginning of period	$	1,773		$	2,537		$	210		$	303
Actual return on plan assets⁽³⁾		373			(561	)		37			(67	)
Employer contributions		4			6			44			39
Participant contributions		—			—			9			13
Benefits paid		(171	)		(209	)		(57	)		(78	)

Fair value of plan assets — end of period	$	1,979		$	1,773		$	243		$	210

Reconciliation of funded status:
Fair value of plan assets	$	1,979		$	1,773		$	243		$	210
Less: Benefit obligation		2,133			1,989			642			673

Net liability at December 31	$	(154	)	$	(216	)	$	(399	)	$	(463	)


⁽¹⁾		The benefit obligation for our pension plans represents the projected benefit obligation and the benefit obligation for our other postretirement benefit plans represents the accumulated postretirement benefit obligation.

⁽²⁾		Amounts for other postretirement benefits are shown net of a subsidy of approximately $6 million for each of the years ended December 31, 2009 and 2008 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

⁽³⁾		We defer the difference between our actual return on plan assets and our expected return over a three year period, after which it is considered for inclusion in net benefit expense or income. Our deferred actuarial gains and losses are amortized only to the extent that our remaining unrecognized actual gains and losses exceed the greater of 10 percent of our benefit obligations or market related value of plan assets.

Components of Funded Status. The following table details the amounts recognized in our balance sheet at December 31, 2009 and 2008 related to our pension and other postretirement benefit plans.


							Other
	Pension Benefits						Postretirement Benefits
	2009			2008			2009			2008
	(In millions)
Non-current benefit asset	$	—		$	—		$	88		$	42
Current benefit liability		(5	)		(4	)		(39	)		(42	)
Non-current benefit liability		(149	)		(212	)		(448	)		(463	)

Funded status	$	(154	)	$	(216	)	$	(399	)	$	(463	)

Components of Accumulated Other Comprehensive Income (Loss). The following table details the amounts recognized in our accumulated other comprehensive income (loss), net of income taxes at December 31, 2009 and 2008 related to our pension and other postretirement benefit plans.


							Other
	Pension Benefits						Postretirement Benefits
	2009			2008			2009		2008
	(In millions)
Unrecognized net gain (loss)	$	(709	)	$	(765	)	$	43	$	24
Unamortized prior service credit (cost)		(16	)		(5	)		—		1

Accumulated other comprehensive income (loss)	$	(725	)	$	(770	)	$	43	$	25

We anticipate that approximately $48 million of our accumulated other comprehensive loss, net of tax, will be recognized as part of our net periodic benefit cost in 2010.

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Our accumulated benefit obligation for our defined benefit pension plans was $2.1 billion and $2.0 billion at December 31, 2009 and 2008. Our accumulated benefit obligation for our defined benefit pension plans, whose accumulated benefit obligations exceeded the fair value of plan assets, was $2.1 billion and $2.0 billion as of December 31, 2009 and 2008. The fair value of these plans’ assets was approximately $2.0 billion and $1.8 billion at December 31, 2009 and 2008.

Our accumulated postretirement benefit obligation for our other postretirement benefit plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $542 million and $552 million as of December 31, 2009 and 2008. The fair value of these plans’ assets was $55 million and $48 million at December 31, 2009 and 2008.

Plan Assets. The primary investment objective of our plans is to ensure that over the long-term life of the plans an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to participants, 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. The plans’ investments include a wide diversification of asset types, fund strategies and fund managers. Although actual allocations vary from time to time from our targeted allocations, the target allocations for our pension plans’ assets are 50 percent equity securities, 40 percent fixed income securities and 10 percent of other types of investments. The target allocations for our postretirement plans’ assets are 65 percent equity and 35 percent fixed income securities. Equity securities for our pension plans’ assets may include investments in large-cap and small-cap companies in the United States, as well as investments in foreign companies. Fixed income securities may include corporate bonds of companies from diversified industries including international fixed income securities, United States Treasuries, and stable income products such as investment contracts. Other types of investments may include investments in hedge funds and private real estate that follow several different strategies. For our other postretirement benefit plans, 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.

Below are the details of our pension and other postretirement benefit plans assets classified by level and a description of their fair values. For a further discussion of the various methods used to determine fair value, see Note 7.

•

Level 1 assets’ fair values are based on quoted prices in actively traded markets. Included in this level are equity securities, fixed income securities, an exchange traded mutual fund and other securities whose fair values are determined using the quoted prices of these assets.

•

Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are common/collective trusts and a mutual fund. The common/collective trusts’ and mutual fund fair values are primarily based on the net asset value as reported by the issuer, which is determined based on the fair value of the underlying securities as of the valuation date. We may adjust these values, when necessary, for factors such as liquidity and risk of nonperformance of the issuer.

•

Level 3 assets’ fair values are partially calculated using valuation techniques that require inputs that are both significant to the fair value measurement and unobservable. As of December 31, 2009, we had no Level 3 assets.

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Listed below are the fair values of our pension and other postretirement benefit plans’ assets that are recorded at fair value classified in each level at December 31, 2009 (in millions):


	Pension Assets
	Level 1		Level 2		Total
Equity securities:
Domestic companies	$	480	$	—	$	480
Foreign companies		83		—		83
Fixed income securities:
U.S. treasuries		76		—		76
Corporate bonds		46		—		46
Federal mortgage-backed and other		19		—		19
Common/collective trusts ⁽¹⁾		—		1,223		1,223
Other investments		1		51		52

Total assets at fair value	$	705	$	1,274	$	1,979


⁽¹⁾		This category includes eight common/collective trusts which are invested in approximately 54 percent fixed income, 43 percent equity and 3 percent short term securities.


	OPEB Assets
	Level 1		Level 2		Total
Exchange traded mutual fund	$	12	$	—	$	12
Common/collective trusts ⁽¹⁾		—		231		231

Total assets at fair value	$	12	$	231	$	243


⁽¹⁾		This category includes four common/collective trusts which are invested in approximately 65 percent equity and 35 percent fixed income securities.

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


			Other
			Postretirement
Year Ending December 31,	Pension Benefits		Benefits⁽¹⁾
	(In millions)
2010	$	209	$	56
2011		182		56
2012		182		55
2013		182		55
2014		181		54
2015-2019		884		252


⁽¹⁾		Includes a reduction of approximately $7 million in each of the years 2010-2014 and approximately $34 million in aggregate for 2015-2019 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

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Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining the benefit obligation and net benefit costs of our pension and other postretirement plans for 2009, 2008 and 2007:


	Pension Benefits						Other Postretirement Benefits
	2009		2008		2007		2009		2008		2007
	(Percent)						(Percent)
Assumptions related to benefit obligations at December 31, 2009 and 2008 and September 30, 2007 measurement dates:
Discount rate		5.61		6.33		6.25		5.42		5.98		6.05
Rate of compensation increase		4.20		4.18		4.27
Assumptions related to benefit costs for the year ended December 31:
Discount rate		6.33		6.25		5.75		5.98		6.05		5.50
Expected return on plan assets⁽¹⁾		8.00		8.00		8.00		8.00		8.00		8.00
Rate of compensation increase		4.18		4.27		4.00


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

Actuarial estimates for our other postretirement benefit plans 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 have a significant effect on the amounts reported for other postretirement benefit plans. A one-percentage point change in assumed health care cost trends would have the following effects as of December 31, 2009 and 2008:


	2009			2008
	(In millions)
One percentage point increase:
Aggregate of service cost and interest cost	$	3		$	2
Accumulated postretirement benefit obligation		47			48
One percentage point decrease:
Aggregate of service cost and interest cost	$	(3	)	$	(2	)
Accumulated postretirement benefit obligation		(42	)		(44	)

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


	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009			2008			2007
	(In millions)
Service cost	$	19		$	15		$	17		$	—		$	—		$	1
Interest cost		121			120			119			38			38			26
Expected return on plan assets		(172	)		(187	)		(181	)		(12	)		(17	)		(16	)
Amortization of net actuarial (gain) loss		45			24			43			—			(5	)		(1	)
Amortization of prior service credit		(1	)		(2	)		(2	)		(1	)		(1	)		(1	)

Net benefit cost (income)	$	12		$	(30	)	$	(4	)	$	25		$	15		$	9

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Components of Other Comprehensive Income (Loss). The following table details the amounts recognized in our other comprehensive loss, net of income taxes, for the years ended December 31, 2009 and 2008 related to our pension and other postretirement benefit plans.


							Other
	Pension Benefits						Postretirement Benefits
	2009			2008			2009			2008
				(In millions)
Prior service cost	$	(10	)	$	(11	)	$	—		$	—
Net gain (loss)		27			(509	)		19			(7	)
Amortization of net actuarial (gain) loss		29			20			—			(1	)
Amortization of prior service credit		(1	)		(2	)		(1	)		(1	)

Other comprehensive income (loss)	$	45		$	(502	)	$	18		$	(9	)

15. Equity and Preferred Stock of Subsidiary

Below is a discussion of each of the components of our equity and noncontrolling interests as of December 31, 2009 and December 31, 2008.

Convertible Perpetual Preferred Stock. We have $750 million of convertible perpetual preferred stock outstanding. Dividends on the preferred stock are declared quarterly at the rate of 4.99% per annum if approved by our Board of Directors and dividends accumulate if not paid. Each share of the preferred stock is convertible at the holder’s option, at any time, subject to adjustment, into 77.2295 shares of our common stock under certain conditions. This conversion rate represents an equivalent conversion price of approximately $13.00 per share. The conversion rate is subject to adjustment based on certain events which include, but are not limited to, fundamental changes in our business such as mergers or business combinations as well as distributions of our common stock or payment of dividends on our common stock in excess of a specified rate. We will be able to cause the preferred stock to be converted into common stock in April 2010 if our common stock is trading at a premium of 130 percent to the conversion price.

Common and Preferred Stock Dividends. The table below shows the amount of dividends paid and declared (dollars in millions):


			Convertible
	Common Stock⁽¹⁾		Preferred Stock
Amount paid in 2009	$	140	$	37
Amount paid in January 2010	$	7	$	9
Declared in 2010:
Date of declaration	February 24, 2010		February 24, 2010
Payable to shareholders on record	March 5, 2010		March 15, 2010
Date payable	April 1, 2010		April 1, 2010


⁽¹⁾		Common stock dividends were paid at $0.05 per share through October 2009. Beginning with our November 2009 dividend declaration, we reduced our common stock dividends to $0.01 per share.

Dividends on our common stock and preferred stock are treated as reduction of additional paid-in-capital since we currently have an accumulated deficit. We expect dividends paid on our common and preferred stock in 2009 will be taxable to our stockholders because we anticipate that these dividends will be paid out of current or accumulated earnings and profits for tax purposes. During 2009, our Board of Directors declared dividends for our common shareholders of $0.05 per share in February, May and August and $0.01 per share in November.

The terms of our 750,000 outstanding shares of 4.99% convertible preferred stock provide for the conversion ratio on our preferred stock to increase when we pay quarterly dividends to our common shareholders in excess of $0.04 per share, as we did for all dividends paid during 2009. The terms of these preferred shares also prohibit the payment of dividends on our common stock unless we have paid or set aside for payment all accumulated and unpaid dividends on such preferred stock for all preceding dividend periods. In addition, although our credit facilities do not contain any direct restriction on the payment of dividends, dividends are included as a fixed charge in the calculation of our fixed charge coverage ratio under our credit facilities. If we are unable to comply with our fixed charge ratio, our ability to pay additional dividends would be restricted.

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Accumulated Other Comprehensive Income (Loss). The following table provides the components of our accumulated other comprehensive income (loss) as of December 31:


	2009			2008
Cash flow hedges (see Note 8)	$	(36	)	$	213
Pension and other postretirement benefits (see Note 14)		(682	)		(745	)

Total accumulated other comprehensive loss, net of income taxes	$	(718	)	$	(532	)

Noncontrolling Interests. During 2009, our subsidiary EPB, a master limited partnership, issued 12.7 million common units for net proceeds of $212 million. Our ownership interest in EPB decreased from 74 percent to 67 percent as a result of the offering. In January 2010, EPB issued to the public a total of 9.9 million common units and issued 0.2 million general partner units to us. Our ownership interest in EPB decreased to 62 percent as a result of this subsequent offering. EPB makes quarterly distributions of available cash to its unitholders in accordance with its partnership agreement. For the years ended December 31, 2009, 2008 and 2007, we have recorded $60 million, $34 million and $6 million which are reflected as net income attributable to noncontrolling interest holders in our income statement.

In July 2009, EPB acquired an additional 18 percent interest in one of our consolidated subsidiaries, CIG, for $215 million. As a result of this acquisition, EPB now owns a 58 percent interest in CIG, a 25 percent interest in SNG and a 100 percent interest in WIC.

Preferred Stock of Subsidiary. During October 2009, GIP, our partner on our Ruby pipeline project, contributed $145 million to Ruby and received a convertible preferred equity interest in Ruby that was simultaneously exchanged for a convertible preferred equity interest in a holding company of Cheyenne Plains. The preferred stock in Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains) has been classified outside of equity on our balance sheet since the events that require redemption of the preferred interest are not entirely within our control. The preferred dividend associated with GIP’s preferred interest of $5 million was paid during 2009 and is reflected in net income attributable to noncontrolling interests on our income statement. For a further discussion of the Ruby transaction, see Note 18.

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16. Stock-Based Compensation

Overview. Under our stock-based compensation plans, we may issue to our employees incentive stock options on our common stock (intended to qualify under Section 422 of the Internal Revenue Code), non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares, performance units and other stock-based awards. We are authorized to grant awards of approximately 55 million shares of our common stock under our current plans, which includes 47.5 million shares under our Omnibus plan, 2.5 million shares under our non-employee director plan and 5 million shares under our employee stock purchase plan. At December 31, 2009, approximately 24.4 million shares remain available for grant under our current plans, which includes approximately 20.5 million shares under our Omnibus plan, 1.7 million shares under our non-employee director plan and 2.2 million shares under our employee stock purchase plan. We also have approximately 11 million shares of stock option awards outstanding that were granted under terminated plans that obligate us to issue additional shares of common stock if they are exercised. Stock option exercises and restricted stock are funded primarily through the issuance of new common shares.

We record stock-based compensation expense, excluding amounts capitalized, as operation and maintenance expense over the requisite service period for each separately vesting portion of the award, net of estimates of forfeitures. If actual forfeitures differ from our estimates, additional adjustments to compensation expense will be required in future periods.

Non-Qualified Stock Options. We grant non-qualified stock options to our employees with an exercise price equal to the market value of our stock on the grant date. Our stock option awards have contractual terms of 10 years and generally vest in equal amounts over three years from the grant date. We do not pay dividends on unexercised options. A summary of our stock option transactions for the year ended December 31, 2009 is presented below:


						Weighted
				Weighted		Average
				Average		Remaining
	# Shares			Exercise		Contractual
	Underlying			Price		Term		Aggregate
	Options			per Share		(In years)		Intrinsic Value
								(In millions)
Outstanding at December 31, 2008		24,770,273		$	28.44
Granted		8,058,603		$	6.48
Exercised		(152,712	)	$	7.43
Forfeited or canceled		(974,668	)	$	12.11
Expired		(2,697,256	)	$	40.55

Outstanding at December 31, 2009		29,004,240		$	21.87		5.96	$	33

Vested at December 31, 2009 or expected to vest in the future		28,414,549		$	22.12		5.90	$	32

Exercisable at December 31, 2009		17,210,420		$	30.06		4.01	$	7

During 2009, 2008 and 2007, we recognized approximately $23 million, $21 million and $16 million of pre-tax compensation expense on stock options, capitalized approximately $5 million in 2009 and $4 million in 2008 and 2007 of this expense as part of fixed assets and recorded $8 million, $7 million and $6 million of income tax benefits, respectively. Total compensation cost related to non-vested option awards not yet recognized at December 31, 2009 was approximately $17 million, which is expected to be recognized over a weighted average period of 10 months. Options exercised during the years ended December 31, 2009, 2008 and 2007 had a total intrinsic value of less than $1 million, $10 million and $6 million, generated $1 million, $11 million and $7 million of cash proceeds and did not generate any significant associated income tax benefit.

Fair Value Assumptions. The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option-pricing model based on several assumptions. These assumptions are based on management’s best estimate at the time of grant. For the years ended December 31, 2009, 2008 and 2007 the weighted average grant date fair value per share of options granted was $2.96, $5.73 and $5.53.

143

Listed below is the weighted average of each assumption based on grants in each fiscal year:


	2009			2008			2007
Expected Term in Years		6.0			6.0			6.0
Expected Volatility		54	%		35	%		34	%
Expected Dividends		1.5	%		1.0	%		1.0	%
Risk-Free Interest Rate		2.0	%		2.8	%		4.6	%

We estimate expected volatility based on an analysis of implied volatilities from traded options on our common stock and our historical stock price volatility over the expected term, adjusted for certain time periods that we believe are not representative of future stock performance. We estimate the expected term of our option awards based on the vesting period and average remaining contractual term, referred to as the “simplified method”. We use this method to provide a reasonable basis for estimating our expected term based on a lack of sufficient historical data primarily due to significant changes in the composition of our employees receiving stock-based compensation awards prior to 2006.

Restricted Stock. We may grant shares of restricted common stock, which carry voting and dividend rights, to our officers and employees. Sale or transfer of these shares is restricted until they vest. We currently have outstanding and grant time-based restricted stock. The fair value of our time-based restricted shares is determined on the grant date and these shares generally vest in equal amounts over three years from the date of grant. A summary of the changes in our non-vested restricted shares for each fiscal years are presented below:


				Weighted Average
				Grant Date Fair Value
Nonvested Shares	# Shares			per Share
Nonvested at December 31, 2008		4,098,342		$	14.91
Granted		3,041,569		$	6.53
Vested		(1,844,447	)	$	14.80
Forfeited		(352,145	)	$	10.84

Nonvested at December 31, 2009		4,943,319		$	10.08

The weighted average grant date fair value per share for restricted stock granted during 2009, 2008 and 2007 was $6.53, $15.46 and $14.73. The total fair value of shares vested during 2009, 2008 and 2007 was $13 million, $29 million and $31 million.

During 2009, 2008 and 2007, we recognized approximately $26 million, $29 million and $25 million of pre-tax compensation expense on our restricted share awards, capitalized approximately $7 million of this expense each year as part of fixed assets and recorded $9 million, $10 million and $9 million of income tax benefits related to restricted stock arrangements. The total unrecognized compensation cost related to these arrangements at December 31, 2009 was approximately $17 million, which is expected to be recognized over a weighted average period of 10 months.

Employee Stock Purchase Plan. Our employee stock purchase plan allows participating employees the right to purchase our common stock at 95 percent of the market price on the last trading day of each month. This plan is non-compensatory under the provisions of current stock compensation accounting standards. Shares issued under this plan were insignificant during 2009, 2008 and 2007.

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17. Business Segment Information

As of December 31, 2009, our business consists of two core segments, Pipelines and Exploration and Production. We also have Marketing and Power segments. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. Our corporate activities include our general and administrative functions, as well as other miscellaneous businesses and various other contracts and assets, all of which are immaterial. A further discussion of each segment follows.

Pipelines. Provides natural gas transmission, storage, and related services, primarily in the United States. As of December 31, 2009, we conducted our activities primarily through seven wholly or majority owned interstate pipeline systems and equity interests in four transmission systems. In addition to the storage capacity in our wholly and majority owned pipelines systems, we also own or have interests in three underground natural gas storage facilities and two LNG terminalling facilities, one of which is under construction.

Exploration and Production. Engaged in the exploration for and the acquisition, development and production of natural gas, oil and NGL, in the United States, Brazil and Egypt.

Marketing. Markets and manages the price risks associated with our natural gas and oil production as well as manages our remaining legacy trading portfolio.

Power. Manages the risks associated with our remaining international power and pipeline assets and investments located in South America and Asia. We continue to pursue the sale of these assets.

We had no customers whose revenues exceeded 10 percent of our total revenues in 2009, 2008 and 2007.

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business segments which consist of both consolidated businesses and investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to evaluate more effectively the operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for items such as (i) interest and debt expense (ii) income taxes, and (iii) net income attributable to noncontrolling interests so that our investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to our net income (loss) for the periods ended December 31:


	2009			2008			2007
	(In millions)
Segment EBIT⁽¹⁾	$	62		$	(278	)	$	1,935
Corporate and other		8			124			(283	)

Consolidated EBIT		70			(154	)		1,652
Interest and debt expense		(1,008	)		(914	)		(994	)
Income tax benefit (expense)		399			245			(222	)
Discontinued operations, net of income taxes		—			—			674

Net income (loss) attributable to El Paso Corporation		(539	)		(823	)		1,110
Net income attributable to non-controlling interests		65			34			6

Net income (loss)	$	(474	)	$	(789	)	$	1,116


⁽¹⁾		2007 EBIT represents EBIT from continuing operations.

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The following tables reflect our segment results as of and for each of the three years ended December 31:


	As of or for the Year Ended December 31, 2009
	Segment
			Exploration and									Corporate
	Pipelines		Production			Marketing			Power			and Other⁽¹⁾			Total
	(In millions)
Revenue from external customers
Domestic	$	2,711	$	1,257	⁽²⁾	$	497		$	—		$	17		$	4,482
Foreign		10		26			114			—			—			150
Intersegment revenue		46		545	⁽²⁾		(582	)		—			(10	)		(1	)
Operation and maintenance		805		417			8			17			10			1,257
Ceiling test charges		—		2,123			—			—			—			2,123
Depreciation, depletion and amortization		414		440			—			1			12			867
Earnings (losses) from unconsolidated affiliates		92		(30	)		—			—			5			67
EBIT		1,416		(1,349	)		20			(25	)		8			70
Assets
Domestic		17,090		3,574			321			—			580			21,565
Foreign⁽³⁾		234		451			24			210			21			940
Capital expenditures and investments in and advances to unconsolidated affiliates, net⁽⁴⁾		1,710		1,154			—			(190	)		80			2,754
Total investments in unconsolidated affiliates		1,133		456			—			105			24			1,718


⁽¹⁾		Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We recorded an intersegment revenue elimination of $10 million.

⁽²⁾		Revenues from external customers include gains of $687 million related to our financial derivative contracts associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production to third parties.

⁽³⁾		Of total foreign assets, approximately $0.4 billion relates to property, plant and equipment,and approximately $0.3 billion relates to investments in and advances to unconsolidated affiliates.

⁽⁴⁾		Amounts are net of third party reimbursements of our capital expenditures, returns of capital and sales of investments and advances.

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	As of or for the Year Ended December 31, 2008
	Segment
			Exploration and									Corporate
	Pipelines		Production			Marketing			Power			and Other⁽¹⁾			Total
	(In millions)
Revenue from external customers
Domestic	$	2,621	$	1,317	⁽²⁾	$	1,137		$	—		$	9		$	5,084
Foreign		11		22			237			—			9			279
Intersegment revenue		52		1,423	⁽²⁾		(1,457	)		—			(18	)		—
Operation and maintenance		863		404			19			15			(111	)		1,190
Ceiling test charges		—		2,669			—			—			—			2,669
Depreciation, depletion and amortization		395		799			—			1			10			1,205
Earnings (losses) from unconsolidated affiliates		97		(93	)		—			40			4			48
EBIT		1,273		(1,448	)		(104	)		1			124			(154	)
Assets
Domestic		14,917		5,821			444			5			1,489			22,676
Foreign⁽³⁾		204		321			21			412			34			992
Capital expenditures and investments in and advances to unconsolidated affiliates, net⁽⁴⁾		1,457		1,622			—			(16	)		43			3,106
Total investments in unconsolidated affiliates		1,054		531			—			99			19			1,703


⁽¹⁾		Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We recorded an intersegment revenue elimination of $19 million.

⁽²⁾		Revenues from external customers include gains of $196 million related to our financial derivative contracts associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production to third parties.

⁽³⁾		Of total foreign assets, approximately $0.3 billion relates to property, plant and equipment and approximately $0.5 billion relates to investments in and advances to unconsolidated affiliates.

⁽⁴⁾		Amounts are net of third party reimbursements of our capital expenditures, returns of capital and sales of investments and advances.

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	As of or for the Year Ended December 31, 2007
	Segments
			Exploration and						Corporate⁽¹⁾
	Pipelines		Production			Marketing			Power			and Other			Total
	(In millions)
Revenue from external customers
Domestic	$	2,429	$	1,123	⁽²⁾	$	814		$	—		$	54		$	4,420
Foreign		11		17			163			—			37			228
Intersegment revenue		54		1,160	⁽²⁾		(1,196	)		—			(18	)		—
Operation and maintenance		753		439			11			17			113			1,333
Depreciation, depletion and amortization		373		780			3			1			19			1,176
Earnings (losses) from unconsolidated affiliates		105		11			—			(15	)		—			101
EBIT⁽³⁾		1,265		909			(202	)		(37	)		(283	) ⁽⁶⁾		1,652
Discontinued operations, net of income taxes		674		—			—			—			—			674
Assets
Domestic		13,764		7,404			506			5			1,482			23,161
Foreign⁽⁴⁾		175		625			31			526			61			1,418
Capital expenditures, and investments in and advances to unconsolidated affiliates, net⁽⁵⁾		1,059		2,613			—			(34	)		7			3,645
Total investments in unconsolidated affiliates		759		704			—			151			—			1,614


⁽¹⁾		Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We recorded an intersegment revenue elimination of $19 million and an operation and maintenance expense elimination of $1 million, which is included in the “Corporate” column, to remove intersegment transactions.

⁽²⁾		Revenues from external customers include gains of $192 million related to our financial derivative contracts associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production to third parties.

⁽³⁾		Represents EBIT from continuing operations as we also had discontinued operations in 2007.

⁽⁴⁾		Of total foreign assets, approximately $0.6 billion relates to property, plant and equipment and approximately $0.6 billion relates to investments in and advances to unconsolidated affiliates.

⁽⁵⁾		Amounts are net of third party reimbursements of our capital expenditures, returns of capital and sales of investments and advances.

⁽⁶⁾		Includes debt extinguishment costs of $86 million related to refinancing EPEP’s $1.2 billion notes. Also includes $77 million in other income related to the reversal of a liability related to a legacy crude oil marketing and trading business matter.

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18. Variable Interest Entities and Qualifying Special Purpose Entities

Variable Interest Entities

We have an investment in Ruby Pipeline Holding Company, L.L.C. (Ruby), a variable interest entity that owns our Ruby pipeline project which has approximately $0.6 billion of net property, plant and equipment as of December 31, 2009. We consolidate Ruby as its primary beneficiary based on the conditions discussed below. In July 2009, we entered into an agreement with several infrastructure funds managed by GIP, whereby they will invest up to $700 million and acquire a 50 percent interest in Ruby subject to certain conditions. As part of this agreement, GIP entered into a loan commitment to provide project funding of $405 million to Ruby, which will be converted into a preferred equity interest in Ruby upon satisfaction of certain conditions. As of December 31, 2009, $217 million has been borrowed under this commitment and is recorded as a short-term financing obligation on our balance sheet.

In October 2009, GIP contributed $145 million to Ruby and received a convertible preferred equity interest in Ruby that was simultaneously exchanged for a convertible preferred equity interest in a holding company of Cheyenne Plains. Cheyenne Plains is a variable interest entity that owns our Cheyenne Plains pipeline and has approximately $0.4 billion of net property, plant and equipment and $0.2 billion of long-term debt as of December 31, 2009. We consolidate Cheyenne Plains as its primary beneficiary. GIP will hold their interest in Cheyenne Plains until certain conditions are satisfied including placing the Ruby pipeline project in-service. GIP is committed to contribute up to an additional $150 million of preferred equity contributions to Ruby under certain conditions, the most significant of which are that FERC approvals for construction of the project are obtained and third party financing of approximately $1.4 billion is secured by Ruby by December 2010. GIP will have the right to convert its preferred equity to common equity in Ruby at any time. However, the preferred equity is subject to a mandatory conversion to common equity in Ruby upon the satisfaction of certain conditions, including Ruby entering into additional firm transportation agreements.

If all conditions to closing are satisfied or waived, at the time of project completion, GIP would own a 50 percent equity interest in Ruby and all ownership in Cheyenne Plains would be transferred back to us. However, the GIP preferred equity interests in Ruby and Cheyenne Plains, along with amounts borrowed under GIP’s loan commitment to Ruby, must be repaid in cash to GIP if (i) all FERC approvals for construction of the Ruby pipeline project are not obtained by December 2010, (ii) third party financing of approximately $1.4 billion is not secured by Ruby by December 2010 or (iii) the Ruby pipeline project is not placed in-service within 16 months of obtaining all FERC approvals. Additionally, if the financings are not completed, GIP has the option to convert its preferred interest in Cheyenne Plains to a 50 percent common interest in Cheyenne Plains. Our obligation to repay these amounts is secured by our equity interests in Ruby, Cheyenne Plains, and approximately 50 million common units we own in our master limited partnership (MLP), El Paso Pipeline Partners, L.P.

We hold interests in other variable interest entities that we account for as investments in unconsolidated affiliates. These entities do not have significant operations and accordingly do not have a material impact to our financial statements.

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Qualifying Special Purpose Entities

Accounts Receivable Sales Program. Several of our pipeline subsidiaries have agreements to sell certain accounts receivable to QSPEs whose purpose is solely to invest in our pipeline receivables, which are short-term assets that generally settle within 60 days. During the year ended December 31, 2009 and 2008, we received net proceeds of approximately $1.9 billion and $1.8 billion related to sales of receivables to the QSPEs and changes in our subordinated beneficial interests, and recognized losses of approximately $2 million and $3 million on these transactions. As December 31, 2009 and 2008, we had approximately $170 million and $174 million of receivables outstanding with the QSPEs, for which we received cash of $89 million and $82 million and received subordinated beneficial interests of approximately $79 million and $89 million. The QSPEs also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $90 million and $85 million as of December 31, 2009 and 2008. We reflect the subordinated beneficial interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections) are recorded as accounts receivable from affiliates on our balance sheet. Our ability to recover the carrying value of our subordinated beneficial interests is based on the collectability of the underlying receivables sold to the QSPEs. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the accounts receivable and performing all administrative duties for the QSPEs which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2009 and 2008.

In January 2010, we ceased selling the accounts receivable of our pipeline subsidiaries to the QSPEs and began selling those receivables directly to the third party financial institution. In return, the third party financial institution pays a certain amount of cash up front for the receivables, and pays the remaining amount owed over time as cash is collected from the receivables.

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19. Investments in, Earnings from and Transactions with Unconsolidated Affiliates

We hold investments in unconsolidated affiliates which are accounted for using the equity method of accounting. The earnings from unconsolidated affiliates reflected in our income statement include (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) impairments and other adjustments recorded by us. As of December 31, 2009 and 2008, our investment balance exceeded the net equity in the underlying net assets of these investments by $269 million and $481 million due primarily to purchase price adjustments and impairment charges recorded by us. The majority of our purchase price adjustments is related to our investment in Four Star which we acquired in 2005. We generally amortize and assess the recoverability of this amount based on the development and production of the underlying estimated proved natural gas and oil reserves of Four Star. The information below related to our unconsolidated affiliates includes (i) our net investment and earnings (losses) we recorded from these investments, (ii) summarized financial information of our proportionate share of these investments, and (iii) revenues and charges with our unconsolidated affiliates. Our net ownership interest, investments in and earnings (losses) from our unconsolidated affiliates are as follows as of and for the years ended December 31:


	Net Ownership									Earnings (Losses) from
	Interest				Investment					Unconsolidated Affiliates
	2009		2008		2009		2008			2009			2008			2007
	(Percent)				(In millions)					(In millions)
Four Star⁽¹⁾		49		49	$	450	$	525		$	(30	)	$	(93	)	$	12
Citrus Corp.		50		50		630		564			66			64			81
Gulf LNG⁽²⁾		50		50		285		279			(2	)		—			—
Bolivia to Brazil Pipeline		8		8		105		119			(2	)		25			11
Gasoductos de Chihuahua⁽³⁾		50		50		184		174			25			29			21
Porto Velho⁽⁴⁾		—		50		—		(64	)		—			1			(23	)
Asian and Central American Investments⁽⁵⁾	various		various			—		13			—			6			(1	)
Argentina to Chile Pipeline⁽⁶⁾		—		22		—		27			4			7			6
Other	various		various			64		66			6			9			(6	)

Total					$	1,718	$	1,703		$	67		$	48		$	101


⁽¹⁾		We recorded amortization of our purchase cost in excess of the underlying net assets of Four Star of $48 million for the year ended December 31, 2009 and $53 million during each of the years ended December 31, 2008 and 2007. In 2008, we recorded a $125 million impairment of the carrying value of our investment. In 2007, we paid $27 million to increase our ownership interest from 43 percent to approximately 49 percent.

⁽²⁾		In February 2008, we acquired a 50 percent interest in Gulf LNG. See Note 2. As of December 31, 2009 and 2008, we had outstanding advances and receivables of $56 million and $26 million, not included above, related to our investment in Gulf LNG.

⁽³⁾		In February 2010, we entered into an agreement to sell our interest in this investment.

⁽⁴⁾		As of December 31, 2008, we had outstanding advances and receivables of $242 million related to our investment in Porto Velho, that are not included in the table above. During 2009, we completed the sale of our investment in and receivables from Porto Velho. For a further discussion, see Note 2.

⁽⁵⁾		In the second quarter of 2008, we sold our interests in the Khulna and Tipitapa power facilities.

⁽⁶⁾		In June 2009, we completed the sale of our investment in the Argentina to Chile Pipeline. For a further discussion, see Note 2.

As of December 31, 2009 and 2008, approximately $485 million and $433 million of the equity in undistributed earnings of 50 percent or less owned entities accounted for by the equity method was included in our consolidated accumulated deficit. We received cash distributions and dividends from our unconsolidated affiliates of $90 million and $182 million for the years ended December 31, 2009 and 2008. Included in these amounts are returns of capital of $2 million in both 2009 and 2008.

151

Impairment charges and gains and losses on sales of equity investments are included in earnings (losses) from unconsolidated affiliates. During 2008, we impaired our investment in Four Star based on a decrease in its fair value that resulted from declining commodity prices. During 2007, we impaired our investments in Porto Velho, Manaus and Rio Negro based on an assessment of the value we would receive in a sale of those investments due to developments in the power markets in Brazil. These gains (losses) consisted of the following:


Investment or Group	2009		2008			2007
	(In millions)
Four Star	$	—	$	(125	)	$	—
Porto Velho⁽¹⁾		—		—			(32	)
Manaus and Rio Negro		—		—			(15	)
Other		2		7			(3	)

	$	2	$	(118	)	$	(50	)


⁽¹⁾		Amount does not include a $25 million impairment of our note receivable in 2007 and a $22 million loss on the sale of a note receivable in 2009. See Note 2 for further information.

Below is summarized financial information of our proportionate share of the operating results and financial position of our unconsolidated affiliates, including those in which we hold greater than a 50 percent interest.


	Year Ended December 31,
	2009		2008		2007
	(In millions)
Operating results data:
Operating revenues	$	526	$	708	$	872
Operating expenses		268		331		528
Income from continuing operations		130		220		211
Net income		130		220		211
Financial position data:
Current assets	$	358	$	320	$	390
Non-current assets		3,060		2,667		2,323
Short-term debt		232		141		41
Other current liabilities		186		100		328
Long-term debt		1,028		858		519
Other non-current liabilities		523		666		588
Equity in net assets		1,449		1,222		1,237

Revenues and charges resulting from transactions with our unconsolidated affiliates were not material in 2009, 2008 and 2007.

152

Other Investment-Related Matters

Manaus/Rio Negro. In 2008, we transferred our ownership in the Manaus and Rio Negro facilities to the plants’ power purchaser as required by their power purchase agreements. As of December 31, 2009, we have approximately $67 million of Brazilian reais-denominated non-current accounts receivable owed to us under the projects’ terminated power purchase agreements, which are guaranteed by the purchaser’s parent. The purchaser has withheld payment of these receivables in light of their Brazilian reais-denominated claims of approximately $65 million related to plant maintenance the purchaser asserts should have been performed at the plants prior to the transfer, inventory levels and other items. The purchaser’s parent has also withheld payment of these receivables under its guarantee in light of these claims. We have initiated legal action against the purchaser’s parent for their failure to pay us under the performance guaranty, and the purchaser’s parent has filed motions with the Brazilian courts to have the power purchaser added as a defendant to that litigation. Settlement discussions with the purchaser and its parent have been unsuccessful to date, and we currently anticipate that resolution of each of these matters will likely occur through legal proceedings in the Brazilian courts. We have reviewed our obligations under the power purchase agreement in relation to the claims and have accrued an obligation for the uncontested claims. We believe the remaining contested claims are without merit. The ultimate resolution of each of these matters is unknown at this time, and adverse developments related to either our ability to collect amounts due to us or related to the dispute could require us to record additional losses in the future.

During 2009, the Brazilian taxing authorities began legal proceedings against the Manaus and Rio Negro projects for $65 million of Brazilian reais-denominated ICMS taxes allegedly due on capacity payments received from the plants’ power purchaser from 1999 to 2001 and secured a court order prohibiting our subsidiaries from transferring or otherwise disposing of any assets. We believe that these ICMS tax assessments on the projects are without merit. By agreement, the power purchaser must indemnify the Manaus and Rio Negro projects for these ICMS taxes, along with related interest and penalties, and has therefore been defending the projects against this lawsuit. In order to continue its defense of this matter, the power purchaser is required to provide security for the potential tax liability to the court’s satisfaction. The power purchaser offered to pledge certain assets, but this offer was rejected by the tax authorities and the court. The power purchaser has appealed the court’s decision. If the power purchaser is unable to resolve this tax matter, any potential taxes owed by the Manaus and Rio Negro projects are also guaranteed by the purchaser’s parent.

Bolivia-to-Brazil. We own an 8 percent interest in the Bolivia-to-Brazil pipeline. As of December 31, 2009, our total investment and guarantees related to this pipeline project was approximately $117 million. We continue to monitor and evaluate the potential impact that regional and political events in Bolivia could have on our investment in this pipeline project. As new information becomes available or future material developments arise, we may be required to record an impairment of our investment.

153

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter, is summarized below.


	Quarters Ended
	March 31			June 30		September 30		December 31			Total
	(In millions, except per common share amounts)
2009
Operating revenues	$	1,484		$	973	$	981	$	1,193		$	4,631
Operating income (loss)		(1,269	)		391		329		498			(51	)
Earnings from unconsolidated affiliates		19			12		11		25			67
Net income (loss) attributable to El Paso Corporation		(969	)		89		67		274			(539	)
Net income (loss) attributable to El Paso Corporation’s common stockholders		(978	)		79		58		265			(576	)
Basic earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		(1.41	)		0.11		0.08		0.38			(0.83	)
Diluted earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		(1.41	)		0.11		0.08		0.36			(0.83	)
2008
Operating revenues	$	1,269		$	1,153	$	1,598	$	1,343		$	5,363
Operating income (loss)		550			421		839		(2,040	)		(230	)
Earnings (losses) from unconsolidated affiliates		37			52		52		(93	)		48
Net income (loss) attributable to El Paso Corporation		219			191		445		(1,678	)		(823	)
Net income (loss) attributable to El Paso Corporation’s common stockholders		200			191		436		(1,687	)		(860	)
Basic earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		0.29			0.27		0.63		(2.43	)		(1.24	)
Diluted earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		0.29			0.25		0.58		(2.43	)		(1.24	)

Below are unusual or infrequently occurring items, if any, in each of the respective quarters of 2009 and 2008:

December 31, 2009. Items include (i) $151 million of gains related to changes in fair value of our exploration and production financial derivatives, (ii) $88 million tax benefit related to the liquidation of foreign entities, (iii) $22 million related to restructuring costs and (iv) $38 million in international ceiling test charges.

September 30, 2009. Items include $87 million of gains related to changes in fair value of our exploration and production financial derivatives.

June 30, 2009. Items include (i) $55 million of gains related to changes in fair value of our exploration and production financial derivatives, (ii) $25 million in mark-to-market gains associated with an indemnification in conjunction with the sale of a legacy ammonia facility, (iii) $22 million loss on the sale of our Porto Velho notes receivables and (iv) $21 million in mark-to-market gains on power contracts.

March 31, 2009. Items include (i) a total of $2.1 billion in domestic and international ceiling test charges, (ii) $394 million in mark-to-market gains related to changes in fair value of our exploration and production financial derivatives and (iii) $52 million gain related to the application of accounting standard updates on certain of our derivative liabilities.

December 31, 2008. Items include (i) a total of $2.7 billion in domestic and international ceiling test charges; (ii) $125 million impairment of our investment in Four Star and (iii) $201 million in mark-to-market gains related to changes in fair value of our exploration and production derivatives that were not designated as hedges.

September 30, 2008. Items include (i) $214 million in mark-to-market gains related to changes in fair value of our exploration and production derivatives that were not designated as hedges and (ii) $63 million in mark-to-market gains on our PJM power contracts.

154

June 30, 2008. Items include (i) $105 million in mark-to-market losses on our PJM power contracts and (ii) $75 million in mark-to-market losses related to changes in fair value of our exploration and production derivatives that are not designated as hedges.

March 31, 2008. Items include $43 million in mark-to-market losses associated with the sale of a legacy ammonia facility.

155

Supplemental Natural Gas and Oil Operations (Unaudited)

Our Exploration and Production segment is engaged in the exploration for, and the acquisition, development and production of natural gas, oil and NGL, in the United States (U.S.), Brazil and Egypt.

Capitalized Costs. Capitalized costs relating to natural gas and oil producing activities and related accumulated depreciation, depletion and amortization were as follows at December 31 (in millions):


	Brazil and
	U.S.		Egypt⁽¹⁾		Worldwide
2009 Consolidated:
Natural gas and oil properties:
Costs subject to amortization	$	19,161	$	1,055	$	20,216
Costs not subject to amortization		256		214		470

		19,417		1,269		20,686
Less accumulated depreciation, depletion and amortization		16,921		867		17,788

Net capitalized costs	$	2,496	$	402	$	2,898


2009 Unconsolidated Affiliate — Four Star⁽²⁾:
Natural gas and oil properties	$	594	$	—	$	594
Less accumulated depreciation, depletion and amortization		436		—		436

Net capitalized costs	$	158	$	—	$	158


2008 Consolidated:
Natural gas and oil properties:
Costs subject to amortization	$	18,503	$	823	$	19,326
Costs not subject to amortization		326		187		513

		18,829		1,010		19,839
Less accumulated depreciation, depletion and amortization		14,692		756		15,448

Net capitalized costs	$	4,137	$	254	$	4,391


⁽¹⁾		Capitalized costs for Egypt were $70 million and $31 million as of December 31, 2009 and 2008.

⁽²⁾		Amounts represent our approximate 49 percent equity interest in the underlying assets of Four Star. Four Star applies the successful efforts method of accounting for its oil and gas properties.

Total Costs Incurred. Costs incurred in natural gas and oil producing activities, whether capitalized or expensed, were as follows for the year ended December 31 (in millions):


	Brazil and
	U.S.		Egypt⁽¹⁾		Worldwide
2009 Consolidated:
Property acquisition costs
Proved properties	$	87	$	—	$	87
Unproved properties		89		51		140
Exploration costs		355		67		422
Development costs		324		118		442

Costs expended		855		236		1,091
Asset retirement obligation costs		36		6		42

Total costs incurred	$	891	$	242	$	1,133


2009 Unconsolidated Affiliate — Four Star⁽²⁾:
Development costs expended	$	10	$	—	$	10


2008 Consolidated:
Property acquisition costs
Proved properties	$	51	$	—	$	51
Unproved properties		74		1		75
Exploration costs		438		104		542
Development costs		938		93		1,031

Costs expended		1,501		198		1,699
Asset retirement obligation costs		19		—		19

Total costs incurred	$	1,520	$	198	$	1,718

156


	Brazil and
	U.S.		Egypt⁽¹⁾		Worldwide
2007 Consolidated:
Property acquisition costs
Proved properties	$	964	$	—	$	964
Unproved properties		262		5		267
Exploration costs		398		199		597
Development costs		735		26		761

Costs expended		2,359		230		2,589
Asset retirement obligation costs		38		7		45

Total costs incurred	$	2,397	$	237	$	2,634


⁽¹⁾		Costs incurred for Egypt were $81 million, $26 million and $10 million for the years ended December 31, 2009, 2008 and 2007.

⁽²⁾		Amounts represent our approximate 49 percent equity interest in the underlying costs incurred by Four Star.

Pursuant to the full cost method of accounting, we capitalize certain general and administrative expenses directly related to property acquisition, exploration and development activities and interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. The table above includes capitalized internal general and administrative costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves of $80 million, $85 million and $69 million for the years ended December 31, 2009, 2008 and 2007. We also capitalized interest of $7 million, $29 million and $35 million for the years ended December 31, 2009, 2008 and 2007.

In our December 31, 2009 reserve report, the amounts estimated to be spent in 2010, 2011 and 2012 to develop our consolidated worldwide proved undeveloped reserves are $316 million, $290 million and $223 million.

Unevaluated Capitalized Costs. We exclude capitalized costs of natural gas and oil properties from amortization that are in various stages of evaluation. We expect a majority of these costs to be included in the amortization calculation in the next three years.

Presented below is an analysis of the capitalized costs of natural gas and oil properties by year of expenditures that are not being amortized as of December 31, 2009 pending determination of proved reserves (in millions):


	Cumulative		Costs Excluded						Cumulative
	Balance		for Years Ended						Balance
	December 31,		December 31⁽¹⁾						January 1,
	2009		2009		2008		2007		2007
U.S.
Acquisition	$	187	$	82	$	51	$	34	$	20
Exploration		69		44		21		3		1

Total U.S.		256		126		72		37		21

Brazil & Egypt⁽²⁾
Acquisition		52		47		—		3		2
Exploration		162		29		35		78		20

Total Brazil & Egypt		214		76		35		81		22

Worldwide	$	470	$	202	$	107	$	118	$	43


⁽¹⁾		Includes capitalized interest of $5 million, $24 million and $33 million for the years ended December 31, 2009, 2008 and 2007.

⁽²⁾		Includes $70 million and $31 million related to Egypt at December 31, 2009 and 2008.

Natural Gas and Oil Reserves. Net quantities of proved developed and undeveloped reserves of natural gas and NGL, oil and condensate, and changes in these reserves at December 31, 2009 presented in the tables below are based on our internal reserve report. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate. Our 2008 consolidated proved reserves were consistent with estimates of proved reserves filed with other federal agencies in 2009 except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.

Ryder Scott Company, L.P. (Ryder Scott), conducted an audit of the estimates of the proved reserves prepared by us as of December 31, 2009. In connection with its audit, Ryder Scott reviewed 87 percent of the properties associated with our proved reserves on a natural gas equivalent basis, representing 90 percent of the total discounted future net cash flows of these proved reserves. Ryder Scott also conducted an audit of the estimates we prepared of the proved reserves of Four Star as of December 31, 2009. In connection with the audit of these proved reserves, Ryder Scott reviewed 83 percent of the properties associated with Four Star’s total proved reserves on a natural gas equivalent basis, representing 85 percent of the total discounted future net cash flows. Based on our data, technical processes and interpretations and procedures and methodologies utilized by us in determining our proved reserves, we believe our reported proved reserve amounts are reasonable. Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

157


										Oil and Condensate									NGL
	Natural Gas (in Bcf)									(in MBbls)									(in MBbls)			Equivalent
																						Volumes
	U.S.			Brazil			Worldwide			U.S.			Brazil			Worldwide			U.S.			(in Bcfe)
Consolidated:
January 1, 2007		1,864			56			1,920			40,679			31,847			72,526			10,012			2,415
Revisions due to prices		28			—			28			2,336			10			2,346			154			43
Revisions other than price		(39	)		(1	)		(40	)		3,711			1,010			4,721			(35	)		(12	)
Extensions and discoveries⁽¹⁾		296			—			296			5,876			—			5,876			1,681			341
Purchases of reserves in place⁽¹⁾		339			—			339			3,111			—			3,111			—			357
Sales of reserves in place⁽¹⁾		(2	)		—			(2	)		(73	)		—			(73	)		—			(2	)
Production		(238	)		(4	)		(242	)		(5,966	)		(157	)		(6,123	)		(1,698	)		(289	)

December 31, 2007		2,248			51			2,299			49,674			32,710			82,384			10,114			2,853

Revisions due to prices		(136	)		(1	)		(137	)		(26,018	)		(29,406	)		(55,424	)		(985	)		(476	)
Revisions other than price		(52	)		—			(52	)		(2,546	)		—			(2,546	)		(891	)		(72	)
Extensions and discoveries⁽²⁾		475			—			475			16,468			—			16,468			456			577
Purchases of reserves in place⁽²⁾		10			—			10			1,295			—			1,295			68			18
Sales of reserves in place⁽²⁾		(224	)		—			(224	)		(10,440	)		—			(10,440	)		(2,754	)		(303	)
Production		(230	)		(3	)		(233	)		(4,523	)		(124	)		(4,647	)		(1,849	)		(272	)

December 31, 2008		2,091			47			2,138			23,910			3,180			27,090			4,159			2,325

Revisions due to prices		(138	)		(2	)		(140	)		13,336			(380	)		12,956			(3,552	)		(84	)
Revisions other than price		(36	)		(6	)		(42	)		3,477			(640	)		2,837			1,511			(16	)
Extensions and discoveries⁽³⁾		380			70			450			18,089			2,136			20,225			16			572
Purchases of reserves in place⁽³⁾		19			—			19			7,343			—			7,343			—			63
Sales of reserves in place⁽³⁾		(49	)		—			(49	)		(1,328	)		—			(1,328	)		(260	)		(59	)
Production		(215	)		(4	)		(219	)		(3,978	)		(100	)		(4,078	)		(1,570	)		(252	)

December 31, 2009		2,052			105			2,157			60,849			4,196			65,045			304			2,549


Unconsolidated Affiliate — Four Star⁽²⁾:
January 1, 2009		176			—			176			2,199			—			2,199			5,518			222
Revisions due to prices		(9	)		—			(9	)		23			—			23			(40	)		(9	)
Revisions other than price		10			—			10			100			—			100			456			13
Extensions and discoveries		1			—			1			4			—			4			8			1
Production		(20	)		—			(20	)		(419	)		—			(419	)		(678	)		(26	)

December 31, 2009		158			—			158			1,907			—			1,907			5,264			201

Total Combined:
December 31, 2009		2,210			105			2,315			62,756			4,196			66,952			5,568			2,750


Consolidated:
Proved developed reserves:
Beginning of year		1,564			12			1,576			19,799			615			20,414			3,619			1,720
End of year		1,441			91			1,532			26,588			3,212			29,800			304			1,713
Proved undeveloped reserves:
Beginning of year		528			35			563			4,111			2,565			6,676			541			606
End of year		610			14			624			34,261			984			35,245			—			836

158


							Oil and Condensate						NGL
	Natural Gas (in Bcf)						(in MBbls)						(in MBbls)		Equivalent
															Volumes
	U.S.		Brazil		Worldwide		U.S.		Brazil		Worldwide		U.S.		(in Bcfe)
Unconsolidated Affiliate — Four Star:
Proved developed reserves:
Beginning of year		149		—		149		2,151		—		2,151		4,516		189
End of year		135		—		135		1,860		—		1,860		4,295		172
Proved undeveloped reserves:
Beginning of year		27		—		27		48		—		48		1,002		33
End of year		23		—		23		47		—		47		969		29
Total Combined:
Proved developed reserves:
Beginning of year		1,712		12		1,724		21,950		615		22,565		8,134		1,908
End of year		1,577		91		1,668		28,448		3,212		31,660		4,599		1,885
Proved undeveloped reserves:
Beginning of year		555		35		590		4,159		2,565		6,724		1,543		639
End of year		633		14		647		34,308		984		35,292		969		865


⁽¹⁾		In 2007, of the 341 Bcfe of extensions and discoveries, 80 Bcfe related to the Raton area in northern New Mexico, 43 Bcfe related to the McCook area in south Texas, 34 Bcfe related to the Zapata area in south Texas, 26 Bcfe related to the success in the Niobrara and Johnson counties in Wyoming, 22 Bcfe related to the Mustang Island 739/740 block in the Gulf of Mexico and 20 Bcfe related to the Victoria area in south Texas. In 2007, we acquired operated natural gas and oil producing properties in south Texas. We also acquired Peoples Energy Production Company, an exploration and production company, with natural gas and oil properties located primarily in the Arklatex, Texas Gulf Coast and Mississippi areas and in the San Juan and Arkoma Basins.

⁽²⁾		In 2008, of the 577 Bcfe of extensions and discoveries, 201 Bcfe related to the Raton area in northern New Mexico and 132 Bcfe related to the Rockies. However, approximately 130 Bcfe of the 132 Bcfe related to the Rockies was also recorded as a pricing revision due to unfavorable commodity prices at December 31, 2008. We also had 99 Bcfe of extensions and discoveries related to the Arklatex area, 38 Bcfe related to the McCook area and 31 Bcfe related to the Zapata area, both in the south Texas area and 22 Bcfe related to High Island in the Gulf of Mexico. In 2008, we acquired interests in domestic natural gas and oil producing properties located in the Western and Central divisions. We also sold domestic natural gas and oil properties located primarily in the Gulf of Mexico.

⁽³⁾		In 2009, of the 572 Bcfe of extensions and discoveries, 301 Bcfe related to the Central division, of which, 208 Bcfe related to the Haynesville Shale and 70 Bcfe related to the Holly/Kingston fields. We also had 147 Bcfe of extensions and discoveries related to the Altamont-Bluebell-Cedar Rim Field in the Western division and 83 Bcfe related to the Camarupim Field in Brazil. In addition, 41 Bcfe of extensions and discoveries related to the Gulf Coast division, of which, 14 Bcfe related to Eugene Island 364/365 in the Gulf of Mexico and 12 Bcfe related to the Wilcox area in South Texas. In 2009, we acquired interests in domestic natural gas and oil producing properties located in the Western division. We also sold domestic natural gas producing properties located in the Central and Western divisions.

In January 2010, the Financial Accounting Standards Board updated accounting standards on extractive activities for oil and gas to align the oil and gas reserve estimation and disclosures with the requirements in the SEC’s final rule on Modernization of Oil and Gas Reserve Reporting, which was effective December 31, 2009. Among other things, the new standard revised the definition of proved reserves and required us to use a 12-month average price to estimate proved reserves rather than a period end spot price as required in prior periods. The 12-month average price is calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The first day 12-month average U.S. price used to estimate our proved reserves at December 31, 2009 was $3.87 per MMBtu for natural gas and $61.18 per barrel of oil, while the spot price at December 31, 2009 was $5.79 per MMBtu for natural gas and $79.36 per barrel of oil.

The adoption of this standard resulted in lower natural gas and oil prices used to estimate our proved reserves at December 31, 2009 than would have been required under the previous standard. Had we used the spot price rather than the first day 12-month average price, our consolidated proved reserves would have been approximately 227 Bcfe higher than our reported proved reserves at December 31, 2009. Also, our standardized measure of discounted future net cash flows would have been approximately $2 billion higher than the amounts reported at December 31, 2009 and we would not have recorded a ceiling test charge on our Brazilian full cost pool during the fourth quarter of 2009. Other than the first day 12-month average price change, the remaining provisions of the standard had minimal impact on the Company’s proved reserves.

All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond our control such as reservoir performance, prices, economic conditions and government restrictions. In addition, as a result of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate.

159

The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Subsequent to December 31, 2009, there have been no major discoveries or other events, favorable or otherwise, that may be considered to have caused a significant change in our estimated proved reserves.

160

Results of Operations. Results of operations for natural gas and oil producing activities by fiscal year were as follows at December 31 (in millions):


	Brazil
	U.S.			and Egypt			Worldwide
2009 Consolidated:
Net Revenues⁽¹⁾
Sales to external customers	$	534		$	25		$	559
Affiliated sales		538			—			538

Total		1,072			25			1,097
Cost of products and services⁽²⁾		(72	)		(5	)		(77	)
Production costs⁽³⁾		(226	)		(26	)		(252	)
Ceiling test charges⁽⁴⁾		(2,031	)		(92	)		(2,123	)
Depreciation, depletion and amortization		(415	)		(9	)		(424	)

		(1,672	)		(107	)		(1,779	)
Income tax benefit		605			—			605

Results of operations from producing activities	$	(1,067	)	$	(107	)	$	(1,174	)

Depreciation, depletion and amortization ($/Mcfe)⁽⁶⁾	$	1.67		$	2.13		$	1.68


2009 Unconsolidated Affiliate — Four Star⁽⁷⁾:
Net Revenues — Sales to external customers⁽¹⁾	$	100		$	—		$	100

Cost of products and services⁽²⁾		(6	)		—			(6	)
Production costs⁽³⁾		(37	)		—			(37	)
Depreciation, depletion and amortization		(29	)		—			(29	)

		28			—			28
Income tax expense		(10	)		—			(10	)

Results of operations from producing activities	$	18		$	—		$	18

Depreciation, depletion and amortization ($/Mcfe)⁽⁸⁾	$	1.09		$	—		$	1.09


2008 Consolidated:
Net Revenues⁽¹⁾
Sales to external customers	$	951		$	20		$	971
Affiliated sales		1,421			—			1,421

Total		2,372			20			2,392
Cost of products and services⁽²⁾		(79	)		—			(79	)
Production costs⁽³⁾		(354	)		(9	)		(363	)
Ceiling test charges⁽⁴⁾		(2,181	)		(488	)		(2,669	)
Depreciation, depletion and amortization		(768	)		(14	)		(782	)

		(1,010	)		(491	)		(1,501	)
Income tax benefit⁽⁵⁾		364			—			364

Results of operations from producing activities	$	(646	)	$	(491	)	$	(1,137	)

Depreciation, depletion and amortization ($/Mcfe)⁽⁶⁾	$	2.87		$	3.62		$	2.88


2007 Consolidated:
Net Revenues⁽¹⁾
Sales to external customers	$	1,085		$	25		$	1,110
Affiliated sales		1,149			(8	)		1,141

Total		2,234			17			2,251
Cost of products and services⁽²⁾		(72	)		—			(72	)
Production costs⁽³⁾		(327	)		(11	)		(338	)
Depreciation, depletion and amortization		(748	)		(16	)		(764	)

		1,087			(10	)		1,077
Income tax expense (benefit)		(392	)		4			(388	)

Results of operations from producing activities	$	695		$	(6	)	$	689

Depreciation, depletion and amortization ($/Mcfe)⁽⁶⁾	$	2.63		$	3.10		$	2.64


⁽¹⁾		Excludes the effects of natural gas and oil derivative contracts.

⁽²⁾		Cost of products and services consists of transportation costs and divisional general and administrative expenses of $11 million in 2009 and only transportation costs in 2008 and 2007.

⁽³⁾		Production costs include lease operating costs and production related taxes, including ad valorem and severance taxes.

⁽⁴⁾		Includes $34 million and $9 million related to Egypt for the years ended December 31, 2009 and 2008.

161


⁽⁵⁾		See Note 5 for a description of the deferred tax valuation allowance recorded in 2008 associated with our Brazil net operating losses and ceiling test charge.

⁽⁶⁾		These amounts represent depreciation, depletion and amortization for unit of production only and include accretion expense on asset retirement obligations of $0.06/Mcfe in 2009, $0.05/Mcfe in 2008 and $0.07/Mcfe in 2007.

⁽⁷⁾		Results do not include amortization of $48 million related to cost in excess of our equity interest in the underlying net assets of Four Star.

⁽⁸⁾		Includes accretion expense on asset retirement obligations of $0.13/Mcfe in 2009.

Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to our consolidated proved natural gas and oil reserves at December 31 is as follows (in millions):


	U.S.			Brazil			Worldwide
2009 Consolidated:
Future cash inflows⁽¹⁾	$	10,058		$	714		$	10,772
Future production costs		(3,531	)		(339	)		(3,870	)
Future development costs		(1,698	)		(108	)		(1,806	)
Future income tax expenses		(511	)		(17	)		(528	)

Future net cash flows		4,318			250			4,568
10% annual discount for estimated timing of cash flows		(1,744	)		(82	)		(1,826	)

Standardized measure of discounted future net cash flows	$	2,574		$	168		$	2,742


2009 Unconsolidated Affiliate — Four Star⁽²⁾:
Future cash inflows⁽¹⁾	$	855		$	—		$	855
Future production costs		(394	)		—			(394	)
Future development costs		(32	)		—			(32	)
Future income tax expenses		(157	)		—			(157	)

Future net cash flows		272			—			272
10% annual discount for estimated timing of cash flows		(110	)		—			(110	)

Standardized measure of discounted future net cash flows	$	162		$	—		$	162


2008 Consolidated:
Future cash inflows⁽¹⁾	$	11,667		$	242		$	11,909
Future production costs		(3,495	)		(45	)		(3,540	)
Future development costs		(1,406	)		(65	)		(1,471	)
Future income tax expenses		(1,152	)		(20	)		(1,172	)

Future net cash flows		5,614			112			5,726
10% annual discount for estimated timing of cash flows		(2,274	)		(56	)		(2,330	)

Standardized measure of discounted future net cash flows	$	3,340		$	56		$	3,396


2008 Unconsolidated Affiliate — Four Star⁽²⁾	$	396		$	—		$	396


2007 Consolidated:
Future cash inflows⁽¹⁾	$	19,329		$	3,226		$	22,555
Future production costs		(4,822	)		(560	)		(5,382	)
Future development costs		(1,805	)		(444	)		(2,249	)
Future income tax expenses		(3,144	)		(625	)		(3,769	)

Future net cash flows		9,558			1,597			11,155
10% annual discount for estimated timing of cash flows		(3,704	)		(617	)		(4,321	)

Standardized measure of discounted future net cash flows	$	5,854		$	980		$	6,834

Standardized measure of discounted future net cash flows, including effects of hedging activities	$	5,902		$	980		$	6,882


2007 Unconsolidated Affiliate — Four Star⁽²⁾	$	444		$	—		$	444


⁽¹⁾		The company had no commodity-based derivative contracts designated as accounting hedges at December 31, 2009 and 2008. U.S. excludes $61 million of future net cash inflows attributable to derivatives designated as accounting hedges in 2007. Amounts also exclude the impact on future net cash flows of derivatives not designated as accounting hedges.

⁽²⁾		Amounts represent our approximate 49 percent equity interest in Four Star.

162

For the calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves as of December 31, 2009 were computed using a first day 12-month average U.S. price of $3.87 per MMBtu for natural gas and $61.18 per barrel of oil. The 12-month average price is calculated as the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period. Year-end U.S. spot prices of $5.71 and $6.80 per MMBtu for natural gas and $44.60 and $95.98 per barrel of oil were used to compute the estimated future cash inflows from estimate future production of our proved reserves at December 31, 2008 and 2007 as required at that time. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including price and cost changes.

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following are the principal sources of change in our consolidated worldwide standardized measure of discounted future net cash flows (in millions):


	Years Ended December 31,⁽¹⁾
	2009			2008			2007
	(In millions)
Consolidated:
Sales and transfers of natural gas and oil produced net of production costs	$	(779	)	$	(2,059	)	$	(1,657	)
Net changes in prices and production costs		(1,455	)		(3,380	)		2,723
Extensions, discoveries and improved recovery, less related costs		646			1,136			910
Changes in estimated future development costs		45			342			(4	)
Previously estimated development costs incurred during the period		186			141			200
Revision of previous quantity estimates		(94	)		(887	)		117
Accretion of discount		310			622			501
Net change in income taxes		246			1,458			(1,333	)
Purchases of reserves in place		121			36			810
Sales of reserves in place		(79	)		(603	)		(7	)
Change in production rates, timing and other		199			(244	)		95

Net change	$	(654	)	$	(3,438	)	$	2,355


Unconsolidated Affiliate — Four Star:
Sales and transfers of natural gas and oil produced net of production costs	$	(137	)
Net changes in prices and production costs		(351	)
Extensions, discoveries and improved recovery, less related costs		1
Changes in estimated future development costs		22
Revision of previous quantity estimates		5
Accretion of discount		57
Net change in income taxes		137
Change in production rates, timing and other		32

Net change	$	(234	)


⁽¹⁾		This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

163

SCHEDULE II

EL PASO CORPORATION
VALUATION AND QUALIFYING ACCOUNTS

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


	Balance at		Charged to						Charged			Balance at
	Beginning		Costs and						to Other			End of
Description	of Period		Expenses			Deductions			Accounts			Period
2009
Allowance for doubtful accounts	$	9	$	—		$	—		$	(1	)	$	8
Valuation allowance on deferred tax assets		337		47	⁽²⁾		—			—			384
Legal reserves⁽¹⁾		73		20			(27	)		—			66
Environmental reserves		204		25			(40	)		—			189
Regulatory reserves⁽³⁾		—		74			—			—			74
2008
Allowance for doubtful accounts	$	17	$	(2	)	$	—		$	(6	)	$	9
Valuation allowance on deferred tax assets		137		202	⁽⁴⁾		—			(2	)		337
Legal reserves⁽¹⁾		460		(91	)		(16	)		(280	) ⁽⁵⁾		73
Environmental reserves		260		(11	)		(44	)		(1	)		204
Regulatory reserves⁽³⁾		10		—			(10	)		—			—
2007
Allowance for doubtful accounts	$	28	$	(4	)	$	(5	)⁽⁶⁾	$	(2	)	$	17
Valuation allowance on deferred tax assets		127		10			—			—			137
Legal reserves⁽¹⁾		548		36			(128	)⁽⁷⁾		4			460
Environmental reserves		314		21			(75	)		—			260
Regulatory reserves⁽³⁾		65		61			(116	)		—			10


⁽¹⁾		Amounts are net of related insurance receivables.

⁽²⁾		Amounts reflect valuation allowances primarily associated with Brazil net operating losses and ceiling test charges and the reversal of valuation allowances for state net operating losses and deferred tax assets.

⁽³⁾		Reflects rate refund and settlement activity.

⁽⁴⁾		Amounts reflect valuation allowances associated with Brazil net operating losses and ceiling test charges.

⁽⁵⁾		Amount reclassified as postretirement liability (see Note 14).

⁽⁶⁾		Relates primarily to the sale of our accounts receivable under an accounts receivable sales program.

⁽⁷⁾		Included is the settlement of our shareholder litigation lawsuits.

164

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 Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 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.

ITEM 9B. OTHER INFORMATION

None.

165

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information included under the captions “Corporate Governance”, “Proposal No. 1 — Election of Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance” and “Information about the Board of Directors and Committees” in our Proxy Statement for the 2010 Annual Meeting of Stockholders is incorporated herein by reference. Information regarding our executive officers is presented in Part I, Item 1, Business, of this Form 10-K under the caption “Executive Officers of the Registrant.”

ITEM 11. EXECUTIVE COMPENSATION

Information appearing under the captions “Information about the Board of Directors and Committees — Compensation Committee Interlocks and Insider Participation”, “Compensation Discussion and Analysis”, “Compensation Committee Report”, “Executive Compensation” and “Director Compensation” in our Proxy Statement for the 2010 Annual Meeting of Stockholders is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information appearing under the captions “Security Ownership of a Certain Beneficial Owner and Management” and “Equity Compensation Plan Information Table” in our Proxy Statement for the 2010 Annual Meeting of Stockholders is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information appearing under the captions “Corporate Governance — Independence of Board Members” and “Corporate Governance — Transactions with Related Persons” in our Proxy Statement for the 2010 Annual Meeting of Stockholders is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information appearing under the caption “Proposal No. 3 — Ratification of the Appointment of Ernst & Young, LLP as our Independent Registered Public Accounting Firm — Principal Accountant Fees and Services” and “Information about the Board of Directors and Committees — Policy for Approval of Audit and Non-Audit Fees,” in our Proxy Statement for the 2010 Annual Meeting of Stockholders is incorporated herein by reference.

166

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

1. Financial statements.

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


	Page
Reports of Independent Registered Public Accounting Firms		94
Consolidated Statements of Income		98
Consolidated Balance Sheets		99
Consolidated Statements of Cash Flows		101
Consolidated Statements of Equity		102
Consolidated Statements of Comprehensive Income		103
Notes to Consolidated Financial Statements		104
2. Financial statement schedules and supplementary information required to be submitted Schedule II — Valuation and Qualifying Accounts		164
3. Exhibits		169

The Exhibit Index, which index 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 management contracts or compensatory plans 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 agreements and:

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

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

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

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

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

Undertaking

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

167

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El Paso Corporation 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 CORPORATION
	By:	/s/ Douglas L. Foshee
		Douglas L. Foshee
		President and Chief Executive Officer

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 Corporation and in the capacities and on the dates indicated:


Signature	Title	Date
/s/ Douglas L. Foshee Douglas L. Foshee	President, Chief Executive Officer and Chairman of the Board (Principal Executive Officer)	March 1, 2010

/s/ John R. Sult John R. Sult	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	March 1, 2010

/s/ Francis C. Olmsted, III Francis C. Olmsted, III	Vice President and Controller (Principal Accounting Officer)	March 1, 2010

/s/ Juan Carlos Braniff Juan Carlos Braniff	Director	March 1, 2010

/s/ James L. Dunlap James L. Dunlap	Director	March 1, 2010

/s/ David W. Crane David W. Crane	Director	March 1, 2010

/s/ Robert W. Goldman Robert W. Goldman	Director	March 1, 2010

/s/ Anthony W. Hall, Jr. Anthony W. Hall, Jr.	Director	March 1, 2010

/s/ Thomas R. Hix Thomas R. Hix	Director	March 1, 2010

/s/ Ferrell P. McClean Ferrell P. McClean	Director	March 1, 2010

/s/ Timothy J. Probert Timothy J. Probert	Director	March 1, 2010

/s/ Steven J. Shapiro Steven J. Shapiro	Director	March 1, 2010

/s/ J. Michael Talbert J. Michael Talbert	Director	March 1, 2010

/s/ Robert F. Vagt Robert F. Vagt	Director	March 1, 2010

/s/ John L. Whitmire John L. Whitmire	Director	March 1, 2010

168

EL PASO CORPORATION

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. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement.


Exhibit
Number		Description
3.A		Second Amended and Restated Certificate of Incorporation (Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on May 31, 2005).

3.B		By-laws effective as of May 6, 2009 (Exhibit 3.B to our Current Report on Form 8-K filed with the SEC on May 6, 2009).

4.A		Indenture dated as of May 10, 1999, by and between El Paso and HSBC Bank USA, National Association (as successor-in-interest to JPMorgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 28, 2005).

4.B		Certificate of Designations of 4.99% Convertible Perpetual Preferred Stock (Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on May 31, 2005).

4.C		Tenth Supplemental Indenture dated as of December 28, 2005 between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on January 4, 2006).

4.D		Eleventh Supplemental Indenture dated as of August 31, 2006, between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our Quarterly Report on Form 10-Q for the period ended September 30, 2006, filed with the SEC on November 6, 2006).

4.E		Twelfth Supplemental Indenture dated as of June 18, 2007 between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our Quarterly Report on Form 10-Q for the period ended June 30, 2007, filed with the SEC on August 7, 2007).

4.F		Thirteenth Supplemental Indenture dated as of May 30, 2008 between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4 to our Quarterly Report on Form 10-Q for the period ended June 30, 2008, filed with the SEC on August 8, 2008).

4.G		Fourteenth Supplemental Indenture dated as of December 12, 2008 between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.H to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

4.H		Fifteenth Supplemental Indenture, dated as of February 9, 2009 between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.I to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

*+10.A		1995 Compensation Plan for Non-Employee Directors Amended and Restated effective as of December 4, 2003.

+10.A.1		Amendment No. 1 effective as of January 1, 2007 to the 1995 Compensation Plan for Non-Employee Directors Amended and Restated effective as of December 4, 2003 (Exhibit 10.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

+10.A.2		Amendment No. 2 effective as of January 1, 2008 to the 1995 Compensation Plan for Non-Employee Directors Amended and Restated effective as of December 4, 2003(Exhibit 10.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

169


Exhibit
Number		Description
+10.B		Stock Option Plan for Non-Employee Directors Amended and Restated effective as of January 20, 1999 (Exhibit 10.G to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 28, 2005); Amendment No. 1 effective as of July 16, 1999 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.G.1 to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 28, 2005); Amendment No. 2 effective as of February 7, 2001 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.B.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 3 effective as of October 26, 2006 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.N to our Quarterly Report on Form 10-Q for the period ended on September 30, 2006, filed with the SEC on November 6, 2006).

+10.C		2001 Stock Option Plan for Non-Employee Directors effective as of January 29, 2001(Exhibit 10.C to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009); Amendment No. 1 effective as of February 7, 2001 to the 2001 Stock Option Plan for Non-Employee Directors (Exhibit 10.C.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective as of December 4, 2003 to the 2001 Stock Option Plan for Non-Employee Directors (Exhibit 10.C.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 3 effective as of October 26, 2006 to the 2001 Stock Option Plan for Non-Employee Directors (Exhibit 10.O to our Quarterly Report on Form 10-Q for the period ended September 30, 2006, filed with the SEC on November 6, 2006).

+10.D		2001 Omnibus Incentive Compensation Plan effective as of January 29, 2001 (Exhibit 10.F. to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 1 effective as of February 7, 2001 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.F.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective as of April 1, 2001 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.F.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 3 effective as of July 17, 2002 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.F.3 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 4 effective as of May 1, 2003 to the 2001 Omnibus Incentive Compensation Plan. (Exhibit 10.F.4 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009); Amendment No. 5 effective as of March 8, 2004 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.F.5 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009);. Amendment No. 6 effective as of October 26, 2006 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.M to our Quarterly Report on Form 10-Q for the period ended September 30, 2006, filed with the SEC on November 6, 2006).

+10.E		Supplemental Benefits Plan Amended and Restated effective December 7, 2001 (Exhibit 10.G to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

+10.F.1		Amendment No. 1 effective as of November 7, 2002 to the Supplemental Benefits Plan (Exhibit 10.G.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

*+10.F.2		Amendment No. 2 effective as of June 1, 2004 to the Supplemental Benefits Plan.

*+10.F.3		Amendment No. 3 effective December 15, 2004 to the Supplemental Benefits Plan.

+10.F.4		Amendment No. 4 to the Supplemental Benefits Plan effective as of December 31, 2004 (Exhibit 10.I.1 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).

+10.F.5		Amendment No. 5 effective as of January 1, 2007 to the Supplemental Benefits Plan Amended and Restated effective December 7, 2001 (Exhibit 10.G.5 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

170


Exhibit
Number		Description
+10.G		Senior Executive Survivor Benefit Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.M to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 28, 2005); Amendment No. 1 effective as of February 7, 2001 to the Senior Executive Survivor Benefit Plan (Exhibit 10.H.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective as of October 1, 2002 to the Senior Executive Survivor Benefit Plan (Exhibit 10.H.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

*+10.H		Key Executive Severance Protection Plan Amended and Restated effective as of August 1, 1998.

+10.H.1		Amendment No. 1 effective as of February 7, 2001 to the Key Executive Severance Protection Plan (Exhibit 10.I.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

+10.H.2		Amendment No. 2 effective as of November 7, 2002 to the Key Executive Severance Protection Plan (Exhibit 10.I.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

+10.H.3		Amendment No. 3 effective as of December 6, 2002 to the Key Executive Severance Protection Plan (Exhibit 10.I.3 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

+10.H.4		Amendment No. 4 effective as of September 2, 2003 to the Key Executive Severance Protection Plan(Exhibit 10.I.4 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

+10.H.5		Amendment No. 5 effective as of January 1, 2007 to the Key Executive Severance Protection Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.I.5 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

*+10.I		2004 Key Executive Severance Protection Plan effective as of March 9, 2004.

+10.I.1		Amendment No. 1 effective as of January 1, 2007 to the 2004 Key Executive Severance Protection Plan effective as of March 9, 2004 (Exhibit 10.J.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

*+10.J		Director Charitable Award Plan Amended and Restated effective as of August 1, 1998.

+10.J.1		Amendment No. 1 effective as of February 7, 2001 to the Director Charitable Award Plan (Exhibit 10.K.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).

*+10.J.2		Amendment No. 2 effective as of December 4, 2003 to the Director Charitable Award Plan.

+10.K		Strategic Stock Plan Amended and Restated effective as of December 3, 1999 (Exhibit 10.L to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 1 effective as of February 7, 2001 to the Strategic Stock Plan (Exhibit 10.L.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective as of November 7, 2002 to the Strategic Stock Plan (Exhibit 10.L.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 3 effective as of December 6, 2002 to the Strategic Stock Plan (Exhibit 10.L.3 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 4 effective as of January 29, 2003 to the Strategic Stock Plan (Exhibit 10.L.4 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 5 effective as of October 26, 2006 to the Strategic Stock Plan (Exhibit 10.J to our Quarterly Report on Form 10-Q for the period ended September 30, 2006, filed with the SEC on November 6, 2006).

171


Exhibit
Number		Description
+10.L		Omnibus Plan for Management Employees Amended and Restated effective as of December 3, 1999 (Exhibit 10.O to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management Employees (Exhibit 10.O.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective as of February 7, 2001 to the Omnibus Plan for Management Employees (Exhibit 10.O.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 3 effective as of December 7, 2001 to the Omnibus Plan for Management (Exhibit 10.O.3 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 4 effective as of December 6, 2002 to the Omnibus Plan for Management Employees (Exhibit 10.O.4 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 5 effective as of October 26, 2006 to the Corporation Omnibus Plan for Management Employees (Exhibit 10.I to our Quarterly Report on Form-Q for the period ended September 30, 2006, filed with the SEC on November 6, 2006).

+10.M		Letter Agreement dated September 20, 2006 between El Paso Corporation and Brent J. Smolik (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC October 16, 2006).

+10.N		Letter Agreement dated July 15, 2003 between El Paso and Douglas L. Foshee(Exhibit 10.R to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

+10.O		Letter Agreement dated December 18, 2003 between El Paso and Douglas L. Foshee(Exhibit 10.S to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

+10.P		Form of Indemnification Agreement of each member of the Board of Directors effective November 7, 2002 or the effective date such director was elected to the Board of Directors, whichever is later(Exhibit 10.T to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

+10.Q		Form of Indemnification Agreement executed by El Paso for the benefit of each officer and effective the date listed in Schedule A thereto (Exhibit 10.F to our Quarterly Report on Form 10-Q for the period ended September 30, 2006, filed with the SEC on November 6, 2006).

*+10.R		Indemnification Agreement executed by El Paso for the benefit of Douglas L. Foshee, effective December 15, 2004.

+10.S		El Paso Corporation 2005 Compensation Plan for Non-Employee Directors effective as of May 26, 2005 (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC May 31, 2005); Amendment No. 1 to the El Paso Corporation 2005 Compensation Plan for Non-Employee Directors effective as of October 26, 2006 (Exhibit 10.P to our Quarterly Report on Form 10-Q for the period ended September 30, 2006, filed with the SEC on November 6, 2006); Amendment No. 2 effective as of January 1, 2007 to the El Paso Corporation 2005 Compensation Plan for Non-Employee Directors effective as of May 26, 2005 (Exhibit 10.Y.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 3 effective as of January 1, 2008 to the El Paso Corporation 2005 Compensation Plan for Non-Employee Directors effective as of May 26, 2005 (Exhibit 10.Y.1 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

+10.T		El Paso Corporation 2005 Omnibus Incentive Compensation Plan, as amended and restated effective May 6, 2009 (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on May 6, 2009).

*10.T.1		Amendment No. 1 effective as of October 14, 2009 to the El Paso Corporation 2005 Omnibus Incentive Compensation Plan, as amended and restated.

172


Exhibit
Number		Description
+10.U		2005 Supplemental Benefits Plan effective as of January 1, 2005 (Exhibit 10.KK to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 28, 2005); Amendment No. 1 effective as of January 1, 2007 to the 2005 Supplemental Benefits Plan effective as of January 1, 2005 (Exhibit 10.BB.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective as of January 1, 2008 to the 2005 Supplemental Benefits Plan effective as of January 1, 2005. (Exhibit 10.BB.1 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

*10.V		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.W		Third Amended 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.X		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).

*12		Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

*21		Subsidiaries of El Paso Corporation.

*23.A		Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.

*23.B		Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers, LLP (Four Star Oil & Gas Company and Citrus Corp. and Subsidiaries)

*23.D		Consent of Ryder Scott Company, L.P.

*31.A		Certification of Chief 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 Chief 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.

*99.A		Ryder Scott Company, L.P. reserve report for El Paso Exploration & Production Company and Four Star Oil & Gas Company as of December 31, 2009.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Schema Document.

*101.CAL		XBRL Calculation Linkbase Document.

*101.DEF		XBRL Definition Linkbase Document.

*101.LAB		XBRL Labels Linkbase Document.

*101.PRE		XBRL Presentation Linkbase Document.

173