10-K

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

OR

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.

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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.

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     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.

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		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.

6

     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		58	(1)	Louisiana
Young Gas Storage		48		6	(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.

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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.

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     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.

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     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.

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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.

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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.

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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.

13

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.

14

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.

15

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

16

     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

17

     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.

18

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.

19

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.

20

     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.

21

     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.

22

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

23

	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

24

	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.

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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.

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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.

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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.

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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		50		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		8		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.

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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.

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     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.

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ITEM 1A. RISK FACTORS

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

     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:

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• 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.

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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.

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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.

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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.

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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.

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     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.

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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.

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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.

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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.

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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.

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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.

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     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.

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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.

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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.

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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.

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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.

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     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.

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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.

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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.

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     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.

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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.

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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.

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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:

		Percent of 2009
Type	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.		79
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.		21

     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.

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     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		42	No	(1)
2011 and Beyond:
WIC System Expansion(3)	First Quarter of 2011		71		11	No	(1)
Ruby Pipeline(4)(5)	First Quarter of 2011		2,964		732	No	(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	No	(1)
South System III and Southeast Supply Header — Phase II(4)	2011-2012		421		21	Yes
TGP Northeast Upgrade Project	November 2013		416		—	No
Elba Expansion III and Elba Express (Phase B)	January 2014		261		5	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.

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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.

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     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.

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     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.

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     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.

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     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.

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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.

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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.

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     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.

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     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.}

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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.

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     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.

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			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.

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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.

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     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.

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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.

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     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.

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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.

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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.

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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.

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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.

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Commitments and Contingencies

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

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     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.

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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.

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     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.

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     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

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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.

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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.

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• 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.

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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.

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     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.

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     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.

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     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	)

88

     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.

89

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.

90

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}

91

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

92

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.

93

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

94

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

95

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

96

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

97

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.

98

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.

99

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.

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     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.

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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.

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     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.

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     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

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	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.

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     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:

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	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.

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     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.

149

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.

150

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

     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 they are 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 effects of governmental regulation. In addition, due to the 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.

     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

EX-10.A

Exhibit 10.A

EL PASO CORPORATION

1995 COMPENSATION PLAN
FOR
NON-EMPLOYEE DIRECTORS

Amended and Restated Effective as of December 4, 2003

TABLE OF CONTENTS

SECTION 1 PURPOSE	1
1.1 Purpose	1
SECTION 2 ADMINISTRATION	1
2.1 Management Committee	1
SECTION 3 PARTICIPATION	1
3.1 Participants	1
SECTION 4 DEFERRED COMPENSATION	2
4.1 Maximum Number of Shares	2
4.2 Adjustment to Number of Shares	2
SECTION 5 COMPENSATION	2
5.1 Amount of Compensation	2
5.2 Compensation Election	2
5.3 Plan Year	3
5.4 Plan Quarter	3
SECTION 6 DEFERRED COMPENSATION	3
6.1 Deferred Cash	3
6.2 Deferred Common Stock	3
6.3 Memorandum Deferred Account	4
6.4 Discretionary Investment by Company	4
6.5 Payment of Deferred Cash	5
6.6 Payment of Deferred Common Stock	5
6.7 Acceleration of Payment of Deferred Cash and Deferred Common Stock	6
SECTION 7 LONG-TERM EQUITY	7
7.1 Long-Term Equity Credit	7
7.2 Payment of Deferred Common Stock in the Event of Death	7
SECTION 8 PHANTOM STOCK OPTIONS	8
8.1 Phantom Stock Options	8
SECTION 9 GENERAL PROVISIONS	8
9.1 Issuance of Common Stock	8
9.2 Unfunded Obligation	9
9.3 Beneficiary	9
9.4 Permanent Disability	10
9.5 Incapacity of Participant or Beneficiary	10
9.6 Nonassignment	10
9.7 Termination and Amendment	11
9.8 Applicable Law	11
9.9 Effective Date and Term of the Plan	11

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors i Table of Contents

9.10 Compliance With Section 16(b) of the Exchange Act	11
9.11 Impact of Future Legislation or Regulations	12

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors ii Table of Contents

EL PASO CORPORATION
1995 COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS
Amended and Restated Effective as of December 4, 2003

SECTION 1 PURPOSE

1.1 Purpose

     The name of the Plan shall be the El Paso Corporation 1995 Compensation Plan for Non-Employee Directors, Amended and Restated Effective as of December 4, 2003 (the “Plan”). The purpose of the Plan is to provide a compensation program for non-employee Directors of El Paso Corporation (the “Company”), that will attract and retain highly qualified individuals to serve as members of the Company’s Board of Directors (the “Board”). The Plan permits non-employee Directors of the Company to receive their Compensation (as defined below) in the form of cash, deferred cash, deferred shares of Company common stock, par value $3 per share, (“Common Stock”) or any combination of the foregoing For purposes of the Plan, the term “Compensation” shall mean the Participant’s annual retainer and meeting fees, if any, for each regular or special meeting and for any committee meetings attended.

SECTION 2 ADMINISTRATION

2.1 Management Committee

     Subject to Section 9.7, the Plan shall be administered by a management committee (the “Management Committee”) consisting of the Chief Executive Officer of the Company and such other senior officers as the Chief Executive Officer shall designate. The Management Committee shall interpret the Plan, shall prescribe, amend and rescind rules relating to it from time to time as it deems proper and in the best interests of the Company, and shall take any other action necessary for the administration of the Plan. Any decision or interpretation adopted by the Management Committee shall be final and conclusive and shall be binding upon all Participants.

SECTION 3 PARTICIPATION

3.1 Participants

     Each person who is a non-employee Director of the Company on the Effective Date (as defined below) of the Plan shall become a participant in the Plan (a “Participant”) on the Effective Date. Thereafter, each non-employee Director of the Company shall become a Participant immediately upon election to the Board.

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 1

SECTION 4 DEFERRED COMPENSATION

4.1 Maximum Number of Shares

     Subject to Section 4.2, the maximum number of shares of Common Stock which may at any time be awarded under the Plan is three hundred thousand (300,000) shares of Common Stock. Awards may be from shares held in the Company’s treasury or issued out of authorized but unissued shares of the Company, or partly out of each, as shall be determined by the Management Committee, subject to, and reduced by (on a post-split basis), the number of shares of Common Stock awarded prior to the occurrence of a two-for-one stock split effected by the Company in the form of a 100% stock dividend on April 1, 1998.

4.2 Adjustment to Number of Shares

     In the event of recapitalization, stock split, stock dividend, exchange of shares, merger, reorganization, change in corporate structure or shares of the Company or similar event, the Board, upon recommendation of the Management Committee, may make appropriate adjustments to the number of shares (i) authorized for the Plan, and (ii) allocated under the Common Stock Deferral (as defined in Section 6.2).

SECTION 5 COMPENSATION

5.1 Amount of Compensation

     Each Director’s Compensation shall be determined in accordance with the Company’s By-laws and shall be paid, unless deferred pursuant to Section 6, in the Plan Year (as defined below) in which it is earned in four equal quarterly installments with each installment being made on or about the last day of the applicable Plan Quarter (as defined below) (the “Payment Date”), unless otherwise determined by the Management Committee.

5.2 Compensation Election

     Upon election to the Board and at the time of or prior to each annual stockholders’ meeting, or at such other time as may be determined by the Management Committee for the purposes of complying with applicable law, each Participant may elect to receive his or her Compensation for the following Plan Year (as defined below) in the form of cash, deferred cash, deferred Common Stock or any combination of the foregoing, by submitting a written notice to the Company in the manner prescribed by the Management Committee. Any combination of the alternatives may be elected, provided the aggregate of the alternatives elected may not exceed one hundred percent (100%) of the Participant’s Compensation, except as provided in Section 6.2(a). Unless otherwise provided under the terms of the Compensation, if no election is received by the Company, the Participant shall be deemed to have made an election to receive his or her

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 2

Compensation in undeferred cash. An election under this Section 5.2 shall be irrevocable and shall apply to the Compensation earned during the Plan Year (as defined below) for which the election is effective.

5.3 Plan Year

     The term “Plan Year” shall mean the period which begins on the day of the Company’s annual stockholders’ meeting and terminates the day before the succeeding annual stockholders’ meeting.

5.4 Plan Quarter

     The term “Plan Quarter” shall mean each calendar quarter except that (i) the first Plan Quarter of any Plan Year which normally shall be a “short” quarter beginning on the day of the annual stockholders’ meeting and ending on June 30, and (ii) the fourth Plan Quarter of any Plan Year normally shall be a “long” quarter beginning on January 1 and ending on the day before the annual stockholders’ meeting.

SECTION 6 DEFERRED COMPENSATION

6.1 Deferred Cash

     If a Participant elects pursuant to Section 5.2 to have all or a specified percentage of his or her Compensation deferred in cash, such amount (a “Cash Deferral”) shall be recorded in a Memorandum Deferred Account (as defined below) until the Participant ceases to be a Director. Compensation deferred under the Company’s Compensation Plan for Non-Employee Directors dated as of January 1, 1992 shall be paid in accordance with the terms of that plan.

6.2 Deferred Common Stock

     (a) If a Participant elects pursuant to Section 5.2 to have all or a specified percentage of his or her cash Compensation deferred in Common Stock, or if an amount is required to be taken in Common Stock pursuant to Section 5.1, an amount shall be recorded in a Memorandum Deferred Account, in the form of shares of Common Stock, as determined in subsection (b) below, until the Participant ceases to be a Director. The amount credited to the Participant’s Memorandum Deferred Account in such case (the “Common Stock Deferral”) shall be equal to the amount actually deferred plus a premium (the “Conversion Premium”). The Conversion Premium shall be twenty-five percent (25%) of the Compensation actually deferred.

     (b) The number of shares of Common Stock credited to a Participant’s Memorandum Deferred Account shall equal the Common Stock Deferral divided by the fair market value of the Common Stock on the applicable Payment Date. For purposes of this Plan, “fair market value” shall be the mean between the highest and lowest quoted

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 3

selling prices at which the Common Stock is sold on the applicable Payment Date as reported in the NYSE Composite Transactions by The Wall Street Journal on such date or any other comparable service the Management Committee may determine is reliable, or if no Common Stock was traded on such date, on the next preceding date on which Common Stock was so traded.

     (c) Subject to Section 9.1, each Participant who elects deferred Common Stock shall, once the shares of Common Stock have been credited to his or her Memorandum Deferred Account, have the right to vote the shares and receive dividends (or dividend equivalents) and other distributions on such shares, subject to applicable laws. Any such dividends, dividend equivalents and other distributions shall be deemed reinvested promptly in additional shares of Common Stock and such additional shares shall be credited to the Memorandum Deferred Account until the Memorandum Deferred Account is distributed.

6.3 Memorandum Deferred Account

     The Company shall establish a ledger account (the “Memorandum Deferred Account”) for each Participant for the purpose of recording the Company’s obligation to pay the Compensation as provided in Sections 6.5 and 6.6, and for recording the Long-Term Equity Credit, described below.

     (a) Except as provided in Section 6.4, interest shall accrue on all Cash Deferrals to the date of distribution and shall be credited to the Memorandum Deferred Account at the end of each calendar quarter or such other periods as may be determined by the Management Committee. Interest or earnings/losses, as applicable, shall be credited to the balance in each Participant’s Memorandum Deferred Account on a semi-monthly basis or at such other intervals as may be determined by the Management Committee. The Management Committee shall determine the rate of interest or earnings/losses periodically and in so doing may take into account the earnings, losses, appreciation or depreciation attributable to discretionary investments made pursuant to Section 6.4, and any other factors it deems appropriate.

     (b) The Company shall promptly credit each Participant’s Memorandum Deferred Account with the number of shares of Common Stock calculated in accordance with Section 6.2(b) and (c).

6.4 Discretionary Investment by Company

     The deferred amounts to be paid to the Participants are unfunded obligations of the Company. The Management Committee may direct that an amount equal to the deferred amount shall be invested by the Company as the Management Committee, in its sole discretion, shall determine. The Management Committee may in its sole discretion determine that all or some portion of an amount equal to the Common Stock Deferrals and Cash Deferrals, and (where appropriate) interest thereon, shall be paid into one or more grantor trusts to be established by the Company of which it shall be the beneficiary,

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 4

and to the assets of which it shall become entitled as and to the extent that Participants receive benefits under the Plan. The Management Committee may designate an investment advisor to direct investments and reinvestments of the funds, including investment of any grantor trusts hereunder.

6.5 Payment of Deferred Cash

     When a Participant ceases to be a Director, the Company shall pay to the Participant (or the Participant’s beneficiary in the case of the Participant’s death) an amount equal to the deferred cash balance of his or her Memorandum Deferred Account, plus interest (at a rate determined pursuant to Section 6.3) on the outstanding deferred cash account balance to the date of distribution and subject to approval of the Management Committee, as follows:

(a)	a lump sum cash payment, or
(b)	in periodic installments over a period of years as determined at the time the deferral election is made.

Payment of deferred cash shall commence or be made in the month following the date on which a Participant ceases to be a Director.

6.6 Payment of Deferred Common Stock

     Except as otherwise provided in Section 7.2, when a Participant ceases to be a Director, the Company shall distribute Common Stock to the Participant (or the Participant’s beneficiary in the case of the Participant’s death) in an amount equal to the number of whole shares of Common Stock in a Participant’s Memorandum Deferred Account, subject to approval of the Management Committee, as follows:

(a)	a lump sum distribution, or
(b)	in annual installments over a period of years as determined at the time the deferral election is made.

Any fractional shares of Common Stock held in the Participant’s account shall be paid to the Participant (or the Participant’s beneficiary in the case of the Participant’s death) in a lump sum cash payment based on the Common Stock’s fair market value on the day preceding the date of such payment.

     Payment of deferred Common Stock shall commence in the month following the date on which a Participant ceases to be a Director, or such later date as may be necessary to comply with Section 16(b) of the Exchange Act and rules promulgated thereunder.

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 5

6.7 Acceleration of Payment of Deferred Cash and Deferred Common Stock

     (a) The Management Committee, in its discretion, may accelerate the payment of the unpaid balance of a Participant’s Memorandum Deferred Account in the event of the Participant’s death or Permanent Disability, or upon its determination that the Participant (or his or her Beneficiary in the case of his or her death) has incurred a severe financial hardship. The Management Committee in making its determination may consider such factors and require such information as it deems appropriate.

     (b) All deferred cash and deferred Common Stock under this Plan shall be paid to a Participant (or his or her Beneficiary in the case of his or her death) in the event of a Change in Control within thirty (30) days after the date of the Change in Control, or at such later time as may be required to enable the Director to avoid liability under Section 16(b) of the Exchange Act. Notwithstanding the foregoing, no such deferred amounts shall be paid to a Participant who continues to serve as a Director of the Company or its successor, until such time said deferrals would otherwise be paid. For purposes of this Plan a “Change in Control” shall be deemed to occur: (a) if any person (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) is or becomes the “beneficial owner” (as defined in Rule 13d-3 of the Exchange Act), directly or indirectly, of securities of the Company representing twenty percent (20%) or more of the combined voting power of the Company’s then outstanding securities; (b) upon the first purchase of the Common Stock pursuant to a tender or exchange offer (other than a tender or exchange offer made by the Company); (c) upon the approval by the Company’s stockholders of a merger or consolidation, a sale, or disposition of all or substantially all the Company’s assets or a plan of liquidation or dissolution of the Company; or (d) if, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board cease for any reason to constitute at least a majority thereof, unless the election or nomination for the election by the Company’s stockholders of each new Director was approved by a vote of at least two-thirds (2/3) of the Directors then still in office who were Directors at the beginning of the period.

     Notwithstanding the foregoing, a Change in Control shall not be deemed to occur if the Company either merges or consolidates with or into another company or sells or disposes of all or substantially all of its assets to another company, if such merger, consolidation, sale or disposition is in connection with a corporate restructuring wherein the stockholders of the Company immediately before such merger, consolidation, sale or disposition own, directly or indirectly, immediately following such merger, consolidation, sale or disposition at least eighty percent (80%) of the combined voting power of all outstanding classes of securities of the company resulting from such merger or consolidation, or to which the Company sells or disposes of its assets, in substantially the same proportion as their ownership in the Company immediately before such merger, consolidation, sale or disposition.

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 6

SECTION 7 LONG-TERM EQUITY

7.1 Long-Term Equity Credit

     (a) In addition to elective deferrals under Section 6.2(a), each Participant’s Memorandum Deferred Account shall be credited on each Payment Date with an amount equal to one-fourth (1/4) of the annual Compensation (the “Long-Term Equity Credit”). The Long-Term Equity Credit shall be in the form of a Common Stock Deferral, but such credit shall not be entitled to the Conversion Premium. Except for the absence of the Conversion Premium, the Long-Term Equity Credit shall be treated the same as all other Common Stock Deferrals under this Plan.

     (b) Each Participant who was a member of the Board of Directors when the El Paso Natural Gas Company Retirement Income Plan for Non-Employee Directors, Amended and Restated Effective as of January 13, 1995 (the “Retirement Income Plan”) was terminated had his or her retirement benefit under the Retirement Income Plan credited as a Common Stock Deferral (as set forth in Section 6.2) in a Memorandum Deferred Account (the “Deferred Retirement Income Plan Credit”). The Deferred Retirement Income Plan Credit shall not be entitled to a Conversion Premium and such Participant shall not be entitled to any other benefit under the Retirement Income Plan. The number of shares of Common Stock credited as the Deferred Retirement Income Plan Credit equaled the value of such retirement benefit (as determined by the Management Committee), divided by the average of the fair market value (as determined by Section 6.2(b)) of the Common Stock traded during the last twenty business days preceding, and including, the date on which the Retirement Income Plan was terminated. Except for the absence of the Conversion Premium, the shares credited under this Section 7.1(b) shall be treated the same as all other Common Stock Deferrals under this Plan.

7.2 Payment of Deferred Common Stock in the Event of Death

     Notwithstanding any other provision of the Plan to the contrary, in the event of a Participant’s death while such Participant is still a Director of the Company, such Participant’s Beneficiary shall, with respect to amounts accrued under Section 7.1, be entitled to receive the Deferred Common Stock (with any accrued shares as a result of dividend reinvestment and other distributions attributable to such shares) in the Participant’s Memorandum Deferred Account which were credited as a result of Section 7.1.

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 7

SECTION 8 PHANTOM STOCK UNITS

8.1 Phantom Stock Units

     (a) Notwithstanding Section 5.2, the Management Committee may determine that the maximum number of shares of Common Stock which may at any time be awarded pursuant to Section 4.1 of the Plan (and, if appropriate, pursuant to Section 5.1 of the El Paso Corporation Strategic Stock Plan) have been issued and phantom stock units which shall have an accounting value equal to the fair market value of one (1) share of Common Stock (“PSUs”) shall be credited to the Participant’s Memorandum Deferred Account for his or her Common Stock Deferral and/or Long-Term Equity Credit for the Plan Year. The amount of PSUs credited to the Participant’s Memorandum Deferred Account for his or her Common Stock Deferral shall include the Conversion Premium.

     (b) Each Participant who receives PSUs shall, once the PSUs have been credited to his or her Memorandum Deferred Account, have the right to receive dividend equivalents and other distributions on such PSUs, subject to applicable laws. Any such dividend equivalents and other distributions shall be deemed reinvested promptly in additional PSUs and such additional PSUs shall be credited to the Memorandum Deferred Account until the Memorandum Deferred Account is distributed. Participants do not have the right to vote the PSUs.

     (c) PSUs shall be exchanged, on a pro rata basis, for an equivalent number of shares of deferred Common Stock when, and if, additional shares of Common Stock become available under the Plan or a successor plan. Such shares of deferred Common Stock shall be treated as all other Common Stock Deferrals under the Plan. If no additional shares of Common Stock become available under the Plan at the time of distribution of the PSUs to the Participant, an amount equal to the PSU balance of the Participant’s Memorandum Deferred Account shall be paid to the Participant (or the Participant’s beneficiary in the case of the Participant’s death) in a lump sum cash payment based on the Common Stock’s fair market value (as defined in Section 6.2(b)) on the day preceding the date of such payment. Payment of PSUs in cash shall be made in the month following the date on which the Participant ceases to be a Director. PSUs credited to the Participant’s Memorandum Deferred Account for the Participant’s Long-Term Equity Credit shall be subject to any additional restrictions of such other Long-Term Equity Credits under the Plan.

SECTION 9 GENERAL PROVISIONS

9.1 Issuance of Common Stock

     The Company shall not be required to issue any certificate for shares of Common Stock prior to:

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 8

     (a) obtaining any approval or ruling from the Securities and Exchange Commission, the Internal Revenue Service or any other governmental agency which the Company, in its sole discretion, deems necessary or advisable;

     (b) listing the shares on any stock exchange on which the Common Stock may then be listed; or

     (c) completing any registration or other qualification of such shares under any federal or state laws, rulings or regulations of any governmental body which the Company, in its sole discretion, determines to be necessary or advisable.

     All certificates for shares of Common Stock delivered under the Plan also shall be subject to such stop transfer orders and other restrictions as the Management Committee may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, any stock exchange upon which Common Stock is then listed and any applicable federal or state securities laws, and the Management Committee may cause a legend or legends to be placed on any such certificates to make appropriate reference to such restrictions. The foregoing provisions of this paragraph shall not be effective if and to the extent that the shares of Common Stock delivered under the Plan are covered by an effective and current registration statement under the Securities Act of 1933, as amended, or if and so long as the Management Committee determines that application of such provisions is no longer required or desirable. In making such determination, the Management Committee may rely upon an opinion of counsel for the Company.

9.2 Unfunded Obligation

     Any deferred amount to be paid to Participants pursuant to the Plan is an unfunded obligation of the Company. The Company is not required to segregate any monies from its general funds, to create any trusts, or to make any special deposits with respect to this obligation. Beneficial ownership of any investments, including trust investments that the Company may make to fulfill this obligation shall at all times remain in the Company. Any investments and the creation or maintenance of any trust or memorandum accounts shall not create or constitute a trust or a fiduciary relationship between the Management Committee or the Company and a Participant, or otherwise create any vested or beneficial interest in any Participant or the Participant’s Beneficiary or the Participant’s creditors in any assets of the Company whatsoever. The Participants shall have no claim against the Company for any changes in the value of any assets that may be invested or reinvested by the Company with respect to the Plan.

9.3 Beneficiary

     The term “Beneficiary” shall mean the person or persons to whom payments are to be paid pursuant to the terms of the Plan in the event of the Participant’s death. The designation shall be on a form provided by the Management Committee, executed by the

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 9

Participant, and delivered to the Management Committee. A Participant may change his or her Beneficiary designation at any time. A designation by a Participant under the El Paso Natural Gas Company Compensation Plan for Non-Employee Directors dated January 1, 1992 shall remain in effect under this Plan unless it is revoked or changed under this Plan. If no Beneficiary is designated, the designation is ineffective, or in the event the Beneficiary dies before the balance of the Memorandum Deferred Account is paid, the balance shall be paid to the Participant’s spouse, or if there is no surviving spouse, to his or her lineal descendants, pro rata, or if there is no surviving spouse or lineal descendants, to the Participant’s legal representatives, the Participant’s estate or the person or persons to whom the deceased’s rights under the Plan shall have passed by will or the laws of descent and distribution (unless the Management Committee for a given year has designated investment in an annuity, in which case the payment options selected by the Participant with respect thereto shall govern).

9.4 Permanent Disability

     A Participant shall be deemed to have become disabled for purposes of the Plan if the Management Committee finds, upon the basis of medical evidence satisfactory to it, that the Participant is totally disabled, whether due to physical or mental condition, so as to be prevented from engaging in further service to the Company or any of its subsidiaries and that such disability will be permanent and continuous during the remainder of the Participant’s life.

9.5 Incapacity of Participant or Beneficiary

     If the Management Committee finds that any Participant or Beneficiary to whom a payment is payable under the Plan is unable to care for his or her affairs because of illness or accident or is under a legal disability, any payment due (unless a prior claim therefor shall have been made by a duly appointed legal representative), at the discretion of the Management Committee, may be paid to the spouse, child, parent, brother or sister of such Participant or Beneficiary or to any person whom the Management Committee has determined has incurred expense for such Participant or Beneficiary. Any such payment shall be a complete discharge of the obligations of the Company under the provisions of the Plan.

9.6 Nonassignment

     The right of a Participant or Beneficiary to the payment of any amounts under the Plan may not be assigned, transferred, pledged or encumbered nor shall such right or other interest be subject to attachment, garnishment, execution or other legal process, except that any right of a Participant or Beneficiary to the payment of any amounts under the Plan may be waived, released or otherwise relinquished by a Participant to enable such Participant to receive similar benefits under another plan or program maintained by the Company.

9.7 Termination and Amendment

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 10

     The Board may from time to time amend, suspend or terminate the Plan, in whole or in part, and if the Plan is suspended or terminated, the Board may reinstate any or all of its provisions. No amendment, suspension or termination may impair the right of a Participant or the Participant’s designated Beneficiary to receive benefits accrued prior to the effective date of such amendment, suspension or termination. The Management Committee may amend the Plan, without Board approval, to ensure that the Company may obtain any regulatory approval or to accomplish any other reasonable purpose, provided that the Management Committee may not effect a change that would materially increase the cost of the Plan to the Company. Notwithstanding the foregoing, the Board and the Management Committee may not amend the Plan without the approval of the stockholders of the Company to: (i) materially increase the number of shares of Common Stock that may be issued under the Plan, (ii) materially modify the eligibility for participation in the Plan, or (iii) otherwise materially increase the benefits accruing to the Participants under the Plan.

9.8 Applicable Law

     The Plan shall be construed and governed in accordance with the laws of the State of Texas.

9.9 Effective Date and Term of the Plan

     The Plan was originally adopted by the Board effective as of January 13, 1995, and approved by the Company’s stockholders on March 16, 1995. The Board amended and restated the Plan on December 2, 1997, to be effective for the 1998-1999 Plan Year (the “Effective Date”), except Section 7, which is effective January 1, 1998. The Board amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Corporation became the publicly held company and El Paso Natural Gas Company became a wholly owned subsidiary. This Plan was assumed by El Paso Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Corporation and El Paso Natural Gas Company. The Board amended and restated the Plan effective as of January 29, 2002. The Board has amended and restated the Plan effective as of December 4, 2003. The Plan shall terminate ten (10) years after the approval of the Plan by the stockholders of the Company.

9.10 Compliance With Section 16(b) of the Exchange Act

     The Company’s intention is that, so long as any of the Company’s equity securities are registered pursuant to Section 12(b) or 12(g) of the Exchange Act, with respect to awards of Common Stock, the Plan shall comply in all respects with any exemption pursuant to Section 16(b) promulgated under Section 16 of the Exchange Act. If any Plan provision is later found not to be in compliance with such exemptions available pursuant to Section 16(b) of the Exchange Act, that provision shall be deemed modified as necessary to meet the requirements of Section 16(b).

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 11

Section 9.11 Impact of Future Legislation or Regulations

     (a) This Section 9.11 shall become operative upon the enactment of any change in applicable statutory law or the promulgation by the Secretary of the Treasury or the Internal Revenue Service of a final regulation or other pronouncement having the force of law, which statutory law, as changed, or final regulation or pronouncement, as promulgated, would cause any Participant to include in his or her federal gross income amounts recorded to the Participant’s Memorandum Deferred Account under the Plan on a date (an “Early Taxation Event”) prior to the date on which such amounts are otherwise distributed to the Participant under the Plan.

     (b) Notwithstanding any other Section of this Plan to the contrary (but subject to subsection (c), below), as of an Early Taxation Event, the feature or features of this Plan, or the act or acts taken under the Plan, that would cause the Early Taxation Event shall be null and void, to the extent, and only to the extent, required to prevent the Participant from being required to include in his federal gross income amounts recorded to the Participant’s Memorandum Deferred Account under the Plan prior to the date on which such amounts are required to be distributed to the Participant under the Plan. By way of example, but not by way of limiting the generality of the foregoing, if a statute is enacted that would require a Participant to include in his or her federal gross income amounts recorded to a Participant’s Memorandum Deferred Account under the Plan prior to the date on which such amounts are distributed to the Participant because of the Participant’s right to receive a distribution under Section 6.7(a) or (b) of the Plan, the right of all Participants to receive distributions under Section 6.7(a) or (b) shall be null and void as of the effective date of that statute. If only a portion of a Participant’s Memorandum Deferred Account is impacted by the change in the law, then only such portion shall be subject to this Section 9.11, with the remainder of the Memorandum Deferred Account not so affected being subject to such rights and features as if the law were not changed. If the law only impacts Participants who have a certain status with respect to the Company, then only such Participants shall be subject to this Section.

     (c) If a feature of, or act taken under the Plan, cannot be made null and void and, consequently, the taxation of an amount at the Early Taxation Event cannot be avoided, there shall be distributed to each Participant, as soon as practicable the amounts that became taxable on the Early Taxation Event.

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 12

     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of December 4, 2003.

		EL PASO CORPORATION
		By	/s/ Susan B. Ortenstone Senior Vice President
			Human Resources
ATTEST:
By	/s/ David L. Siddall Corporate Secretary

El Paso Corporation
1995 Compensation Plan for Non-Employee Directors Page 13

EX-10.F.2

EXHIBIT 10.F.2

AMENDMENT NO. 2 TO THE
EL PASO CORPORATION
SUPPLEMENTAL BENEFITS PLAN

     Pursuant to Section 6.7 of the El Paso Corporation Supplemental Benefits Plan, Amended and Restated effective as of December 7, 2001, as amended (the “Plan”), the Plan is hereby amended as follows, effective June 1, 2004:

     Section 5.4(a) is hereby deleted in its entirety and replaced with the following:

“(a) Supplemental Pension Benefit Payments. The payment of any supplemental pension benefits pursuant to Section 5.1 owed to a Participant (or his or her Surviving Spouse) shall be made in lump sum as soon as practicable after the Participant’s termination of employment with the Employer unless the Participant made a valid irrevocable election to receive such payment in a form other than a lump sum payment prior to the effective date of this Amendment. The amount of the payment under this subparagraph 5.4(a) shall be determined pursuant to Section 5.5; provided, however, no such payment shall be required to be made to the Participant if the amount of the payment the Participant is entitled to receive for supplement pension benefits under this Plan is less than $100.”

     Section 5.4(b) is hereby deleted in its entirety and replaced with the following:

“(b) Supplemental RSP Benefit Payments. The payment of any supplemental RSP benefits pursuant to Section 5.2 owed to a Participant (or his or her Beneficiary) shall be made in a lump sum as soon as practicable after the Participant’s termination of employment with the Employer and shall be in an amount equal to the Participant’s ledger account balance at the time of such payment; provided, however, no such payment shall be required to be made to the Participant if the amount of the payment the Participant is entitled to receive for supplemental RSP benefits under this Plan is less than $100.”

     Section 5.5 is hereby deleted in its entirety and replaced with the following:

“5.5 Determination of Supplemental Pension Benefit Payments

     Subject to Section 5.6 and 5.7, the amount of a payment of supplemental pension benefits pursuant to Section 5.1 to a Participant (or his or her Surviving Spouse in the event of the Participant’s termination of employment on account of death) shall be determined by calculating the benefit according to the terms of the Pension Plan as a single life annuity.”

     IN WITNESS WHEREOF, the Company has caused this amendment to be duly executed on this 1st day of June, 2004.

EL PASO CORPORATION
By:	/s/ Susan B. Ortenstone
	Susan B. Ortenstone
	Its Senior Vice President, Human Resources

Attest:

/s/ David L. Siddall

Corporate Secretary

EX-10.F.3

EXHIBIT 10.F.3

AMENDMENT NO. 3 TO THE
EL PASO CORPORATION
SUPPLEMENTAL BENEFITS PLAN

     Pursuant to Section 6.7 of the El Paso Corporation Supplemental Benefits Plan, Amended and Restated effective as of December 7, 2001, as amended (the “Plan”), the Plan is hereby amended as follows, effective December 15, 2004:

     Section 6.7 is hereby amended by adding the following new paragraph at the end thereof:

     “The American Jobs Creation Act of 2004 (the “Act”) imposes certain restrictions on deferred compensation plans such as the Plan, effective for 2005 and later years, which might result in unfavorable tax consequences to participants if the terms of the Plan do not comply with the Act. Specific guidance regarding the terms and effect of the Act is expected from the Internal Revenue Service, but may not be published in time to amend the Plan prospectively, before the Act becomes effective. Therefore, notwithstanding this or any other provision of the Plan to the contrary, the Board or the Compensation Committee and the Management Committee, as appropriate, reserve the right to amend the Plan in any manner that is determined to be appropriate, or to terminate the Plan and adopt a plan designed to replace this Plan and be in compliance with the Act, retroactively, to comply with the requirements imposed on nonqualified deferred compensation plans by the Act, as codified in Section 409A of the Code, and regulations to be promulgated thereunder.”

     IN WITNESS WHEREOF, the Company has caused this amendment to be duly executed on this 15th day of December, 2004.

EL PASO CORPORATION
By:	/s/ Susan B. Ortenstone
	Susan B. Ortenstone
	Its Senior Vice President, Human Resources

Attest:

/s/ David L. Siddall

Corporate Secretary

EX-10.H

Exhibit 10.H

EL PASO ENERGY CORPORATION

KEY EXECUTIVE SEVERANCE
PROTECTION PLAN

Amended and Restated Effective as of August 1, 1998

TABLE OF CONTENTS

SECTION 1 ESTABLISHMENT OF PLAN	1
SECTION 2 DEFINITIONS	1
2.1 Base Salary	1
2.2 Benefits Protection Trust	1
2.3 Board	2
2.4 Bonus Amount	2
2.5 Cause	2
2.6 Change in Control	3
2.7 Company	3
2.8 Effective Date	4
2.9 Executive Employee	4
2.10 Good Reason	4
2.11 Notice of Termination	5
2.12 Operating Companies	5
2.13 Participant	5
2.14 Permanent Disability	5
2.15 Severance Benefit	5
SECTION 3 ELIGIBILITY	6
3.1 Participation	6
3.2 Duration of Participation	6
SECTION 4 SEVERANCE BENEFITS	6
4.1 Right to Severance Benefit	6
4.2 Amount of Severance Benefit	6
SECTION 5 TERMINATION OF EMPLOYMENT	8
5.1 Written Notice Required	8
5.2 Termination Date	8
SECTION 6 ADDITIONAL PAYMENTS BY THE COMPANY	8
6.1 Gross-Up Payment	8
6.2 Determination By Accountant	9
6.3 Notification Required	9
6.4 Repayment	10
SECTION 7 SUCCESSORS TO COMPANY	11
7.1 Successors and Sale of Operating Companies	11
(a) Successors	11
(b) Sale of Operating Companies	11
SECTION 8 AMENDMENT AND PLAN TERMINATION	11

El Paso Energy Corporation
Key Executive Severance Protection Plan - i - Table of Contents

8.1 Amendment and Termination	11
8.2 Form of Amendment	12
SECTION 9 MISCELLANEOUS	12
9.1 Indemnification	12
9.2 Employment Status	12
9.3 Validity and Severability	12
9.4 Governing Law; Choice of Forum	12
9.5 Payment to Benefits Protection Trust	13

El Paso Energy Corporation
Key Executive Severance Protection Plan - ii - Table of Contents

EL PASO ENERGY CORPORATION
KEY EXECUTIVE SEVERANCE PROTECTION PLAN
Amended and Restated Effective as of August 1, 1998

     WHEREAS, the Board of Directors of El Paso Energy Corporation recognizes that the threat of an unsolicited takeover of the Company may occur which can result in significant distractions of its key executive personnel because of the uncertainties inherent in such a situation; and

     WHEREAS, the Board has determined that it is essential and in the best interest of the Company and its stockholders to retain the services of its key executive personnel in the event of a threat of a Change in Control of the Company and to ensure their continued dedication and efforts in such event without undue concern for their personal financial and employment security.

     NOW, THEREFORE, in order to fulfill the above purposes, the following plan has been developed and is hereby adopted.

SECTION 1 ESTABLISHMENT OF PLAN

     As of the Effective Date, the Company hereby establishes a severance compensation plan known as the El Paso Energy Corporation Key Executive Severance Protection Plan (the “Plan”) as set forth in this document.

SECTION 2 DEFINITIONS

     As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.

2.1 Base Salary

     The amount a Participant is entitled to receive as wages or salary on an annualized basis, calculated immediately prior to a Change in Control.

2.2 Benefits Protection Trust

     The El Paso Energy Corporation Benefits Protection Trust.

El Paso Energy Corporation
Key Executive Severance Protection Plan Page 1

2.3 Board

     The Board of Directors of El Paso Energy Corporation.

2.4 Bonus Amount

     The term “Bonus Amount” shall mean an amount equal to the Executive Employee’s maximum bonus which becomes payable to the Executive Employee in the event of a “change in control” under the Company’s 1995 Incentive Compensation Plan (or any other bonus plan or program then in effect) but excluding any single or one time “spot” award, for the fiscal year in which a Change in Control occurs had he or she continued in employment until the end of such fiscal year, assuming all performance targets and goals (if applicable) had been fully met by the Company and by the Executive Employee, as applicable, for such year.

2.5 Cause

     The Company may terminate the Executive Employee’s employment for “Cause.” A termination for Cause is a termination evidenced by a resolution adopted in good faith by two-thirds (2/3) of the Board that the Executive Employee (i) willfully and continually failed to substantially perform his or her duties with the Company (other than a failure resulting from the Executive Employee’s incapacity due to physical or mental illness) which failure continued for a period of at least thirty (30) days after a written notice of demand for substantial performance has been delivered to the Executive Employee specifying the manner in which the Executive Employee has failed to substantially perform, or (ii) willfully engaged in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise; provided, however, that no termination of the Executive Employee’s employment shall be for Cause as set forth in clause (ii) above until (A) there shall have been delivered to the Executive Employee a copy of a written notice setting forth that the Executive Employee was guilty of the conduct set forth in clause (ii) and specifying the particulars thereof in detail, and (B) the Executive Employee shall have been provided an opportunity to be heard by the Board (with the assistance of the Executive Employee’s counsel if the Executive Employee so desires). No act, nor failure to act, on the Executive Employee’s part shall be considered “willful” unless he or she has acted, or failed to act, with an absence of good faith and without a reasonable belief that his or her action or failure to act was in the best interest of the Company. Notwithstanding anything contained in this Plan to the contrary, no failure to perform by the Executive Employee after Notice of Termination is given by the Executive Employee shall constitute Cause.

2.6 Change in Control

El Paso Energy Corporation
Key Executive Severance Protection Plan Page 2

     A “Change in Control” shall be deemed to occur:

     (a) if any person (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) is or becomes the “beneficial owner” (as defined in Rule 13d-3 of the Exchange Act), directly or indirectly, of securities of El Paso Energy Corporation representing twenty percent (20%) or more of the combined voting power of El Paso Energy Corporation’s then outstanding securities;

     (b) upon the first purchase of El Paso Energy Corporation’s Common Stock pursuant to a tender or exchange offer (other than a tender or exchange offer made by El Paso Energy Corporation);

     (c) upon the approval by El Paso Energy Corporation stockholders of a merger or consolidation, a sale or disposition of all or substantially all of El Paso Energy Corporation’s assets or a plan of liquidation or dissolution of El Paso Energy Corporation; or

     (d) if, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of El Paso Energy Corporation cease for any reason to constitute at least a majority thereof, unless the election or nomination for the election by El Paso Energy Corporation’s stockholders of each new director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were directors at the beginning of the period.

Notwithstanding the foregoing, a Change in Control shall not be deemed to occur if El Paso Energy Corporation either merges or consolidates with or into another company or sells or disposes of all or substantially all of its assets to another company, if such merger, consolidation, sale or disposition is in connection with a corporate restructuring wherein the stockholders of El Paso Energy Corporation immediately before such merger, consolidation, sale or disposition own, directly or indirectly, immediately following such merger, consolidation, sale or disposition at least eighty percent (80%) of the combined voting power of all outstanding classes of securities of El Paso Energy Corporation resulting from such merger or consolidation, or to which El Paso Energy Corporation sells or disposes of its assets, in substantially the same proportion as their ownership in El Paso Energy Corporation immediately before such merger, consolidation, sale or disposition.

2.7 Company

     El Paso Energy Corporation and the Operating Companies.

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2.8 Effective Date

     The date the Plan is approved by the Board, or such other date as the Board shall designate in its resolution approving the Plan, or any amendment or restatement thereof.

2.9 Executive Employee

     All employees of the Company employed in an Executive Salary Grade Position.

2.10 Good Reason

     “Good Reason” shall mean the occurrence of any of the following events or conditions:

     (a) a change in the Executive Employee’s status, title, position or responsibilities (including reporting responsibilities) which, in the Executive Employee’s reasonable judgment, represents a substantial reduction of the status, title, position or responsibilities as in effect immediately prior thereto; the assignment to the Executive Employee of any duties or responsibilities which, in the Executive Employee’s reasonable judgment, are inconsistent with such status, title, position or responsibilities; or any removal of the Executive Employee from or failure to reappoint or reelect him or her to any of such positions, except in connection with the termination of his or her employment for Cause, Permanent Disability, as a result of his or her death, or by the Executive Employee other than for Good Reason;

     (b) a reduction in the Executive Employee’s annual base salary;

     (c) the requirement by the Company that the Executive Employee (without the consent of the Executive Employee) to be based at any place outside a thirty-five (35) mile radius of his or her place of employment prior to a Change in Control, except for reasonably required travel on the Company’s business which is not materially greater than such travel requirements prior to the Change in Control;

     (d) the failure by the Company to (i) continue in effect any material compensation or benefit plan, program or practice in which the Executive Employee was participating at the time of the Change in Control, including, but not limited to, the Company’s 1995 Omnibus Compensation Plan, the Pension Plan, the Supplemental Benefits Plan, the 1995 Incentive Compensation Plan, the Deferred Compensation Plan, and the Retirement Savings Plan, with any amendments and restatements of such plans made prior to such Change in Control, or (ii) provide the Executive Employee with compensation and benefits at least equal (in terms of benefit levels and/or reward opportunities) to those provided for under each employee benefit plan, program and practice as in effect

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immediately prior to the Change in Control (or as in effect following the Change in Control, if greater);

     (e) any material breach by the Company of any provision of this Plan; or

     (f) any purported termination of the Executive Employee’s employment for Cause by the Company which does not otherwise comply with the terms of this Plan as in effect at the time of a Change in Control.

2.11 Notice of Termination

     “Notice of Termination” shall mean a notice which indicates the specific provisions in this Plan relied upon as the basis for any termination of employment and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive Employee’s employment under the provision so indicated. No purported termination of employment shall be effective without such Notice of Termination.

2.12 Operating Companies

     Subsidiary companies of the Company designated by the Company.

2.13 Participant

     An Executive Employee who meets the eligibility requirements of Section 3.

2.14 Permanent Disability

     A Participant shall be deemed to have become permanently disabled for purposes of this Plan if the Chief Executive Officer of the Company (or, in the case of a determination with respect to the Chief Executive Officer, the Board) finds, upon the basis of medical evidence satisfactory to him or her, that the Participant is totally disabled, whether due to physical or mental condition, so as to be prevented from engaging in further employment by the Company and that such disability will be permanent and continuous during the remainder of his or her life.

2.15 Severance Benefit

     The benefit payable in accordance with Section 4 of the Plan.

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SECTION 3 ELIGIBILITY

3.1 Participation

     Each Executive Employee shall automatically be entitled to be a Participant in the Plan as of the Effective Date, or his or her date of hire by the Company, whichever occurs later.

3.2 Duration of Participation

     A Participant shall cease to be a Participant in the Plan if he or she ceases to be an Executive Employee at any time prior to a Change in Control or, if his or her employment is terminated following a Change in Control under circumstances where he or she is not entitled to a Severance Benefit under the terms of this Plan. A Participant entitled to payment of a Severance Benefit shall remain a Participant in the Plan until the full amount of the Severance Benefit has been paid to him or her.

SECTION 4 SEVERANCE BENEFITS

4.1 Right to Severance Benefit

     (a) A Participant shall be entitled to receive from the Company a Severance Benefit in the amount provided in Section 4.2 if (i) a Change in Control has occurred and (ii) within two years thereafter, the Participant’s employment with the Company terminates for any reason, except that notwithstanding the provisions of this paragraph (a), no benefits under this Plan will be payable should the Participant’s termination of employment be (A) for Cause, (B) by reason of Permanent Disability, (C) voluntarily initiated by the Participant for other than Good Reason, or (D) by reason of the Participant’s death.

     (b) Notwithstanding any other provision of the Plan, the sale, divestiture or other disposition of an Operating Company (or part thereof), shall not be deemed to be a termination of employment of employees employed by such Operating Company, and such employees shall not be entitled to benefits from the Company under this Plan as a result of such sale, divestiture, or other disposition, or as a result of any subsequent termination of employment, provided the provisions of Section 7.1(b) have been satisfied.

4.2 Amount of Severance Benefit

     If a Participant’s employment is terminated in circumstances entitling him or her to a Severance Benefit as provided in Section 4.1, such Participant shall be entitled to the following benefits:

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     (a) the Company shall pay to the Participant, as severance pay and in lieu of any further salary for periods subsequent to the Termination Date (as specified in Section 5.2), in a single payment (without any discount for accelerated payment), an amount in cash equal to three (3) times the sum of (A) the Participant’s Base Salary and (B) the Bonus Amount;

     (b) for a period of eighteen (18) months subsequent to the Participant’s termination of employment, the Company shall at its expense continue on behalf of the Participant and his or her dependents and beneficiaries, the basic life insurance, flexible spending account, medical and dental benefits which were being provided to the Participant at the time of termination of employment. The benefits provided in this Subsection 4.2(b) shall be no less favorable to the Participant, in terms of amounts and deductibles and costs to him or her, than the coverage provided the Participant under the plans providing such benefits at the time Notice of Termination is given. The Company’s obligation hereunder to provide the foregoing benefits shall terminate if the Participant obtains health benefits coverage under a subsequent employer’s benefit plans. The Company also shall pay a lump sum equal to the amount of any additional income tax payable by the Participant and attributable to the benefits provided under this subparagraph (b) at the time such tax is imposed upon the Participant;

     (c) the Company shall pay a lump sum pension supplement payable under the terms of the El Paso Energy Corporation Supplemental Benefit Plan (“Supplemental Plan”) equal to a pension calculated by adding three years of additional credited pension service to the Participant’s existing credited pension service as of the termination of the Participant’s employment, and then by calculating the Participant’s pension in accordance with the formula provided in the pension plan. A Participant who is entitled to a pension supplement under any other agreement between such Participant and the Company may elect, in writing, to receive the pension supplement provided under this subparagraph (c) in lieu of, but not in addition to, such other pension supplement as may be provided by such other agreement. In the event that no election is made, the Participant shall forego his or her right to receive the pension supplement provided under this subparagraph;

     (d) the Company shall transfer to the Participant, all right, title or other ownership interest it may have in any automobile, if any, then being provided by the Company for use by the Participant;

     (e) the Company shall transfer to the Participant, any right, title or ownership in any club memberships provided by the Company;

     The amounts provided for in Section 4.2(a), (c), (d) and (e) shall be paid or transferred within thirty (30) days after the Executive Employee’s termination of employment. The Participant shall not be required to mitigate the amount of any payment provided for in this Plan by seeking other employment or otherwise and no such

El Paso Energy Corporation
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payment shall be offset or reduced by the amount of any compensation or benefits provided to the Executive Employee in any subsequent employment.

SECTION 5 TERMINATION OF EMPLOYMENT

5.1 Written Notice Required

     Any purported termination of employment, either by the Company or by the Participant, shall be communicated by written Notice of Termination to the other.

5.2 Termination Date

     In the case of the Participant’s death, the Participant’s Termination Date shall be his her date of death. In all other cases, the Participant’s Termination Date shall be the date specified in the Notice of Termination subject to the following:

     (a) If the Participant’s employment is terminated by the Company for Cause or due to Permanent Disability, the date specified in the Notice of Termination shall be at least thirty (30) days from the date the Notice of Termination is given to the Participant, provided that in the case of Permanent Disability the Participant shall not have returned to the full-time performance of his or her duties during such period of at least thirty (30) days; and

     (b) If the Participant terminates his or her employment for Good Reason, the date specified in the Notice of Termination shall not be more than sixty (60) days from the date the Notice of Termination is given to the Company.

SECTION 6 ADDITIONAL PAYMENTS BY THE COMPANY

6.1 Gross-Up Payment

     In the event it shall be determined that any payment or distribution of any type by the Company to or for the benefit of the Participant, whether paid or payable or distributed or distributable pursuant to the terms of this Plan or otherwise (the “Total Payments”), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”) or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest and penalties, are collectively referred to as the “Excise Tax”), then the Participant shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Participant of all taxes (including any interest or penalties imposed with respect to such taxes), including any Excise Tax, imposed upon the Gross-Up Payment, the Participant retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Total Payments. Payment of the Gross-Up Payment shall be made in accordance with Section 6.3.

El Paso Energy Corporation
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6.2 Determination By Accountant

     All determinations required to be made under this Section 6, including whether a Gross-Up Payment is required and the amount of such Gross-Up Payment, shall be made by the independent accounting firm retained by the Company on the date of Change in Control (the “Accounting Firm”), which shall provide detailed supporting calculations both to the Company and the Participant within 15 business days of the date of termination, if applicable, or such earlier time as is requested by the Company. If the Accounting Firm determines that no Excise Tax is payable by the Participant, it shall furnish the Participant with an opinion that he or she has substantial authority not to report any Excise Tax on his or her federal income tax return. Any determination by the Accounting Firm shall be binding upon the Company and the Participant. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Gross-Up payments which will not have been made by the Company should have been made (“Underpayment”), consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 6.3 and the Participant thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Participant.

6.3 Notification Required

     The Participant shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten (10) business days after the Participant knows of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Participant shall not pay such claim prior to the expiration of the thirty (30) day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Participant in writing prior to the expiration of such period that it desires to contest such claim, the Participant shall:

     (a) give the Company any information reasonably requested by the Company relating to such claim,

     (b) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

     (c) cooperate with the Company in good faith in order to effectively contest such claim,

El Paso Energy Corporation
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     (d) permit the Company to participate in any proceedings relating to such claim, provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Participant harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of such representation and payment of costs and expenses. Without limitation on the foregoing provisions of this Section 6.3, the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Participant to pay the tax claimed and sue for a refund, or contest the claim in any permissible manner, and the Participant agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Participant to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Participant, on an interest-free basis and shall indemnify and hold the Participant harmless, on an after-tax basis, from any Excise Tax or income tax, including interest or penalties with respect thereto, imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Participant with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Participant shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

6.4 Repayment

     If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 6.3, the Participant becomes entitled to receive any refund with respect to such claim, the Participant shall (subject to the Company’s complying with the requirements of Section 6.3) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 6.3, a determination is made that the Participant shall not be entitled to any refund with respect to such claim and the Company does not notify the Participant in writing of its intent to contest such denial of refund prior to the expiration of thirty (30) days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof the amount of Gross-Up Payment required to be paid.

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SECTION 7 SUCCESSORS TO COMPANY

7.1 Successors and Sale of Operating Companies

(a) Successors

This Plan shall bind any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, in the same manner and to the same extent that the Company would be obligated under this Plan if no succession had taken place. In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the Company’s obligations under this Plan, in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place.

(b) Sale of Operating Companies

In the event that one or more Operating Companies (or part thereof) are sold, divested, or otherwise disposed of by the Company subsequent to a Change in Control, the Company shall require such purchaser or acquirer, as a condition precedent to such purchase or acquisition, to assume, and agree to perform the Company’s obligations under the Plan, in the same manner, and to the same extent that the Company would be required to perform if no such acquisition or purchase had taken place. In such circumstances, the purchaser or acquirer shall be solely responsible for providing any benefits payable under this Plan to such employees.

SECTION 8 AMENDMENT AND PLAN TERMINATION

8.1 Amendment and Termination

     This Plan may be terminated or amended in any respect by resolution adopted by two-thirds (2/3) of the Board, provided, however, that no such amendment or termination of the Plan may be made if such amendment or termination would adversely affect any right of an Executive Employee who became a Participant prior to the later of (a) the date of adoption of any such amendment or termination, or (b) the effective date of any such amendment or termination, and provided further, that the Plan no longer shall be subject to amendment, change, substitution, deletion, revocation or termination in any respect whatsoever following a Change in Control. The Board of Directors amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Energy Corporation became the publicly held company and El Paso Natural Gas Company became a wholly

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owned subsidiary. This Plan was assumed by El Paso Energy Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Energy Corporation and El Paso Natural Gas Company.

8.2 Form of Amendment

     The form of any amendment or termination of the Plan shall be a written instrument signed by a duly authorized officer or officers of the Company, certifying that the amendment or termination has been approved by the Board.

SECTION 9 MISCELLANEOUS

9.1 Indemnification

     If, after a Change in Control, a Participant institutes any legal action in seeking to obtain or enforce, or is required to defend in any legal action the validity or enforceability of, any right or benefit provided by this Plan, the Company will pay for all actual legal fees and expenses as they are incurred by such Participant.

9.2 Employment Status

     This Plan does not constitute a contract of employment or impose on the Company any obligation to retain the Participant as an Employee, to change the status of the Participant’s employment as an Executive Employee, or to change any employment policies of the Company.

9.3 Validity and Severability

     The invalidity or unenforceability of any provision of the Plan shall not affect the validity or enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

9.4 Governing Law; Choice of Forum

     The validity, interpretation, construction and performance of the Plan shall in all respects be governed by the laws of the State of Texas. A Participant shall be entitled to enforce the provisions of this Plan in any state or federal court located in the State of Texas, in addition to any other appropriate forum.

9.5 Payment to Benefits Protection Trust

     Notwithstanding any other provision of the Plan, the Company shall not be required to make any payment to a Participant under the terms of this Plan if such

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payment is otherwise made to the Participant by the Benefits Protection Trust in accordance with the provisions of said Benefits Protection Trust.

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     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of August 1, 1998.

		EL PASO ENERGY CORPORATION
		By Title:	/s/ Joel Richards, III Executive Vice President
ATTEST:
By Title:	/s/ David L. Siddall Corporate Secretary

El Paso Energy Corporation
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EX-10.I

Exhibit 10.I

EL PASO CORPORATION

2004 KEY EXECUTIVE SEVERANCE
PROTECTION PLAN

Effective as of March 9, 2004

TABLE OF CONTENTS

SECTION 1 ESTABLISHMENT OF PLAN	1
SECTION 2 DEFINITIONS	1
2.1 Base Salary	1
2.2 Benefits Protection Trust	1
2.3 Board	1
2.4 Bonus Amount	2
2.5 Cause	2
2.6 Change in Control	2
2.7 Company	4
2.8 Effective Date	4
2.9 Employer	5
2.10 Executive Employee	5
2.11 Good Reason	5
2.12 Notice of Termination	6
2.13 Operating Companies	6
2.14 Participant	6
2.15 Permanent Disability	6
2.16 Plan	6
2.17 Severance Benefit	6
SECTION 3 ELIGIBILITY	6
3.1 Participation	6
3.2 Duration of Participation	7
SECTION 4 SEVERANCE BENEFITS	7
4.1 Right to Severance Benefit	7
4.2 Amount of Severance Benefit	8
SECTION 5 TERMINATION OF EMPLOYMENT	9
5.1 Written Notice Required	9
5.2 Termination Date	9
SECTION 6 ADDITIONAL PAYMENTS BY THE COMPANY	10
6.1 Gross-Up Payment	10
6.2 Determination By Accountant	10
6.3 Notification Required	11
6.4 Repayment	12
SECTION 7 SUCCESSORS TO COMPANY	12
7.1 Successors	12
7.2 Sale of Operating Companies	13

El Paso Corporation
2004 Key Executive Severance Protection Plan - i - Table of Contents

SECTION 8 AMENDMENT AND PLAN TERMINATION	13
8.1 Amendment and Termination	13
8.2 Form of Amendment	14
SECTION 9 MISCELLANEOUS	14
9.1 Indemnification	14
9.2 Employment Status	14
9.3 Validity and Severability	14
9.4 Governing Law; Choice of Forum	15
9.5 Payment to Benefits Protection Trust	15
APPENDIX I	16
APPENDIX II	17

El Paso Corporation
2004 Key Executive Severance Protection Plan - ii - Table of Contents

EL PASO CORPORATION
2004 KEY EXECUTIVE SEVERANCE PROTECTION PLAN

Effective as of March 9, 2004

     WHEREAS, the Board of Directors of El Paso Corporation recognizes that the threat of a change in ownership or control of the Company may occur which can result in significant distractions of its key executive personnel because of the uncertainties inherent in such a situation; and

     WHEREAS, the Board has determined that it is essential and in the best interest of the Company and its stockholders to retain the services of its key executive personnel in the event of a threat of a Change in Control of the Company and to ensure their continued dedication and efforts in such event without undue concern for their personal financial and employment security.

     NOW, THEREFORE, in order to fulfill the above purposes, the following plan has been developed and is hereby adopted.

SECTION 1 ESTABLISHMENT OF PLAN

     As of the Effective Date, the Company hereby establishes a severance compensation plan known as the El Paso Corporation 2004 Key Executive Severance Protection Plan as set forth in this document.

SECTION 2 DEFINITIONS

     As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.

2.1 Base Salary

     As to any Participant the amount that the Participant is entitled to receive as wages or salary from his or her Employer on an annualized basis, as in effect immediately prior to a Change in Control or, if greater, at any time following the Change in Control.

2.2 Benefits Protection Trust

     The El Paso Corporation Benefits Protection Trust.

2.3 Board

     The Board of Directors of the Company.

2.4 Bonus Amount

     The term “Bonus Amount” shall mean, as to any Participant, an amount equal to the Participant’s target bonus opportunity that becomes payable to the Participant in the event of a “qualifying change in control” under the Company’s 2001 Omnibus Incentive Compensation Plan (or under the same or similar terms of any successor bonus plan or program thereto) for the fiscal year in which a Change in Control occurs, determined as if the Participant had continued in employment until the end of such fiscal year and as if the Company and the Participant had fully met all performance targets and goals (if applicable) for such year, but excluding any single or one time “spot” award.

2.5 Cause

     A termination of a Participant by his or her Employer shall be for “Cause” if evidenced by a resolution adopted in good faith by two-thirds (2/3) of the Board that the Participant (i) willfully and continually failed to substantially perform his or her duties with his or her Employer (other than a failure resulting from the Participant’s incapacity due to physical or mental illness) which failure continued for a period of at least thirty (30) days after a written notice of demand for substantial performance has been delivered to the Participant specifying the manner in which the Participant has failed to substantially perform, or (ii) willfully engaged in conduct which is demonstrably and materially injurious to the Company or any of its affiliates, monetarily or otherwise; provided, however, that no termination of the Participant’s employment shall be for Cause as set forth in clause (ii) above until (A) there shall have been delivered to the Participant a copy of a written notice setting forth that the Participant was guilty of the conduct set forth in clause (ii) and specifying the particulars thereof in detail, and (B) the Participant shall have been provided an opportunity to be heard by the Board (with the assistance of the Participant’s counsel if the Participant so desires). No act, nor failure to act, on the Participant’s part shall be considered “willful” unless he or she has acted, or failed to act, with an absence of good faith and without a reasonable belief that his or her action or failure to act was in the best interest of the Company or any of its affiliates. Notwithstanding anything contained in this Plan to the contrary, no failure to perform by the Participant after Notice of Termination is given by the Participant shall constitute Cause.

2.6 Change in Control

     A “Change in Control” shall mean the occurrence of any of the following after the Effective Date:

     (a) An acquisition (other than directly from the Company) of any voting securities of the Company (the “Voting Securities”) by any “Person” (as the term “person” is used for purposes of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), immediately after which such Person has “Beneficial Ownership” (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of more than twenty percent (20%) of (1) the then-outstanding shares of common stock of the Company (or any other securities into which such shares of

2

common stock are changed or for which such shares of common stock are exchanged) (the “Shares”) or (2) the combined voting power of the Company’s then-outstanding Voting Securities; provided, however, that in determining whether a Change in Control has occurred pursuant to this paragraph (a), the acquisition of Shares or Voting Securities in a “Non-Control Acquisition” (as hereinafter defined) shall not constitute a Change in Control. A “Non-Control Acquisition” shall mean an acquisition by (i) an employee benefit plan (or a trust forming a part thereof) maintained by (A) the Company or (B) any corporation or other Person the majority of the voting power, voting equity securities or equity interest of which is owned, directly or indirectly, by the Company (for purposes of this definition, a “Related Entity”), (ii) the Company or any Related Entity, or (iii) any Person in connection with a “Non-Control Transaction” (as hereinafter defined);

     (b) The individuals who, as of the Effective Date, are members of the board of directors of the Company (the “Incumbent Board”), cease for any reason to constitute at least a majority of the members of the board of directors of the Company or, following a Merger (as hereinafter defined), the board of directors of (x) the corporation resulting from such Merger (the “Surviving Corporation”), if fifty percent (50%) or more of the combined voting power of the then-outstanding voting securities of the Surviving Corporation is not Beneficially Owned, directly or indirectly, by another Person (a “Parent Corporation”) or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation; provided, however, that, if the election, or nomination for election by the Company’s common stockholders, of any new director was approved by a vote of at least two-thirds of the Incumbent Board, such new director shall, for purposes of the Plan, be considered a member of the Incumbent Board; and provided, further, however, that no individual shall be considered a member of the Incumbent Board if such individual initially assumed office as a result of an actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the board of directors of the Company (a “Proxy Contest”), including by reason of any agreement intended to avoid or settle any Proxy Contest; or

     (c) The consummation of:

          (i) A merger, consolidation or reorganization (1) with or into the Company or (2) in which securities of the Company are issued (a “Merger”), unless such Merger is a “Non-Control Transaction.” A “Non-Control Transaction” shall mean a Merger in which:

     (A) the stockholders of the Company immediately before such Merger own directly or indirectly immediately following such Merger at least fifty percent (50%) of the combined voting power of the outstanding voting securities of (x) the Surviving Corporation, if there is no Parent Corporation or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation;

     (B) the individuals who were members of the Incumbent Board immediately prior to the execution of the agreement providing for such Merger constitute at least a majority of the members of the board of directors of (x) the

3

Surviving Corporation, if there is no Parent Corporation, or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation; and

     (C) no Person other than (1) the Company, (2) any Related Entity, or (3) any employee benefit plan (or any trust forming a part thereof) that, immediately prior to the Merger, was maintained by the Company or any Related Entity, or (4) any Person who, immediately prior to the Merger had Beneficial Ownership of twenty percent (20%) or more of the then outstanding Shares or Voting Securities, has Beneficial Ownership, directly or indirectly, of twenty percent (20%) or more of the combined voting power of the outstanding voting securities or common stock of (x) the Surviving Corporation, if fifty percent (50%) or more of the combined voting power of the then outstanding voting securities of the Surviving Corporation is not Beneficially Owned, directly or indirectly by a Parent Corporation, or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation;

          (ii) A complete liquidation or dissolution of the Company; or

          (iii) The sale or other disposition of all or substantially all of the assets of the Company and its subsidiaries taken as a whole to any Person (other than (x) a transfer to a Related Entity, (y) a transfer under conditions that would constitute a Non-Control Transaction, with the disposition of assets being regarded as a Merger for this purpose or (z) the distribution to the Company’s stockholders of the stock of a Related Entity or any other assets).

Notwithstanding the foregoing, a Change in Control shall not be deemed to occur solely because any Person (the “Subject Person”) acquired Beneficial Ownership of more than the permitted amount of the then outstanding Shares or Voting Securities as a result of the acquisition of Shares or Voting Securities by the Company which, by reducing the number of Shares or Voting Securities then outstanding, increases the proportional number of shares Beneficially Owned by the Subject Persons; provided, that if a Change in Control would occur (but for the operation of this sentence) as a result of the acquisition of Shares or Voting Securities by the Company and, after such share acquisition by the Company, the Subject Person becomes the Beneficial Owner of any additional Shares or Voting Securities and such Beneficial Ownership increases the percentage of the then outstanding Shares or Voting Securities Beneficially Owned by the Subject Person, then a Change in Control shall occur.

2.7 Company

     “Company” shall mean El Paso Corporation.

2.8 Effective Date

     The “Effective Date” of this Plan is March 9, 2004.

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2.9 Employer

     “Employer” shall mean, as to any Participant on any date, the Company or the affiliate of the Company that employs the Participant on such date.

2.10 Executive Employee

     All employees of the Employer employed in an Executive Salary Grade Position.

2.11 Good Reason

     “Good Reason” shall mean, as to any Participant, the occurrence of any of the following events or conditions following a Change in Control:

     (a) a change in the Participant’s status, title, position or responsibilities (including reporting responsibilities) which, in his or her reasonable judgment, represents a substantial reduction of his or her status, title, position or responsibilities as in effect immediately prior thereto; the assignment to the Participant of any duties or responsibilities which, in the Participant’s reasonable judgment, are inconsistent with such status, title, position or responsibilities; or any removal of the Participant from or failure to reappoint or reelect him or her to any of such positions, except in connection with the termination of his or her employment for Cause, Permanent Disability, as a result of his or her death, or by the Participant other than for Good Reason;

     (b) a reduction in the Participant’s annual base salary;

     (c) the requirement by the Participant’s Employer (without the consent of the Participant) that he or she have a principal place of employment which is outside a thirty-five (35) mile radius of his or her principal place of employment immediately prior to a Change in Control, except for reasonably required travel on the Employer’s business which is not materially greater than such travel requirements prior to the Change in Control;

     (d) the failure by the Company or any of its affiliates to (i) continue in effect any material compensation or benefit plan, program or practice in which the Participant was participating immediately prior to the Change in Control, including, without limitation, the Company’s 2001 Omnibus Incentive Compensation Plan, Pension Plan, Supplemental Benefits Plan and Retirement Savings Plan, with any amendments and restatements of such plans made prior to such Change in Control, or (ii) provide the Participant with compensation and benefits at least equal (in terms of benefit levels and/or reward opportunities) to those provided for under each compensation or employee benefit plan, program and practice of the Company and its affiliates as in effect immediately prior to the Change in Control (or as in effect following the Change in Control, if greater);

     (e) any material breach by the Company of any provision of this Plan; or

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     (f) any purported termination of the Participant’s employment for Cause by the Employer which does not otherwise comply with the terms of this Plan.

2.12 Notice of Termination

     “Notice of Termination” shall mean a notice which indicates the specific provisions in this Plan relied upon as the basis for any termination of employment and which sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Participant’s employment under the provision so indicated. No purported termination of employment shall be effective without such Notice of Termination.

2.13 Operating Companies

     Subsidiary companies of the Company designated by the Company on Appendix I of the Plan.

2.14 Participant

     An Executive Employee who meets the eligibility requirements of Section 3.

2.15 Permanent Disability

     A Participant shall be deemed to have become permanently disabled for purposes of this Plan if the Chief Executive Officer of the Company (or, in the case of a determination with respect to the Chief Executive Officer, the Board) finds, upon the basis of medical evidence satisfactory to him or her, that the Participant is totally disabled, whether due to physical or mental condition, so as to be prevented from engaging in further employment by the Employer and that such disability will be permanent and continuous during the remainder of his or her life.

2.16 Plan

     This El Paso Corporation 2004 Key Executive Severance Protection Plan.

2.17 Severance Benefit

     The benefit payable in accordance with Section 4 of the Plan.

SECTION 3 ELIGIBILITY

3.1 Participation

     Executive Employees shall become Participants in the Plan if they are designated by the Board or Compensation Committee thereof as Participants; provided, however, that an Executive Employee who is a participant in the Company’s Key Executive Severance Protection Plan or Employee Severance Protection Plan must waive participation therein (in form satisfactory to the Company) as a condition to becoming a

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Participant in this Plan. Participants shall be identified on Appendix II of the Plan. The Company shall amend Appendix II from time to time as necessary to include new Participants in the Plan or remove Participants from the Plan who are no longer eligible to participate in the Plan, in each case in accordance with the terms and conditions of the Plan.

3.2 Duration of Participation

     A Participant shall cease to be a Participant in the Plan if he or she ceases to be an Executive Employee at any time prior to a Change in Control (but subject to Section 4.1(b)) or if his or her employment is terminated following a Change in Control under circumstances where he or she is not entitled to a Severance Benefit under the terms of this Plan. A Participant whose termination of employment entitles him or her to payment of a Severance Benefit shall remain a Participant in the Plan until the full amount of the Severance Benefit has been paid to him or her.

SECTION 4 SEVERANCE BENEFITS

4.1 Right to Severance Benefit

     (a) A Participant shall be entitled to receive from the Company a Severance Benefit in the amount provided in Section 4.2 if (i) a Change in Control has occurred and (ii) within two years thereafter, the Participant’s employment with the Employer terminates for any reason, except that notwithstanding the provisions of this Section 4.1(a), no benefits under this Plan will be payable should the Participant’s termination of employment be (A) by the Employer for Cause, (B) by reason of Permanent Disability, (C) voluntarily initiated by the Participant other than for Good Reason, or (D) by reason of the Participant’s death.

     (b) If (i) a Participant’s employment is terminated by the Employer without Cause prior to the date of a Change in Control or (ii) an action is taken with respect to the Participant prior to the date of a Change in Control that would constitute Good Reason if taken after a Change in Control, and the Participant reasonably demonstrates that such termination or action (A) was at the request of a third party that has indicated an intention or taken steps reasonably calculated to effect a Change in Control or (B) otherwise arose in connection with, or in anticipation of, a Change in Control that has been threatened or proposed, such termination or action shall be deemed to have occurred after such Change in Control for purposes of the Plan, so long as such Change in Control actually occurs.

     (c) Notwithstanding any other provision of the Plan, the sale, divestiture or other disposition of an Operating Company (or part thereof) before the execution of an agreement providing for a transaction or transactions which, if consummated, would constitute a Change in Control or before a Change in Control shall not be deemed to be a termination of employment of Participants employed by such Operating Company (or whose employment relates to such Operating Company, if applicable), and such Participants shall not be entitled to benefits from the Company under this Plan as a result of such sale, divestiture or other disposition. The sale, divestiture or other disposition of

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an Operating Company (or part thereof) after the execution of an agreement providing for a transaction or transactions which, if consummated, would constitute a Change in Control or after a Change in Control shall not be deemed to be a termination of employment of Participants employed by such Operating Company (or whose employment relates to such Operating Company, if applicable), and such Participants shall not be entitled to benefits from the Company under this Plan as a result of such sale, divestiture or other disposition, in each case so long as the provisions of Section 7.2 have been satisfied.

4.2 Amount of Severance Benefit

     If a Participant’s employment is terminated in circumstances entitling him or her to a Severance Benefit as provided in Section 4.1, such Participant shall be entitled to the following benefits:

     (a) the Company shall pay to the Participant, as severance pay and in lieu of any further salary for periods subsequent to the Termination Date (as specified in Section 5.2), in a single payment (without any discount for accelerated payment), an amount in cash equal to a formula, as described below, and based upon a multiplier, as assigned in the table below to the Participant according to the Participant’s salary grade level (“Executive Grade Level”):

	Executive	Corporate Title
Multiplier	Grade Level	(or Equivalent Position at Subsidiary Level)
3 X	XA	President and Chief Executive Officer
2 X	XB – XE; XF	Executive Vice President and Senior Vice President
1 X	XG – XI	Vice President

(X) times the sum of (A) the Participant’s Base Salary and (B) the Bonus Amount. The Company shall also pay to the Participant the prorated portion of the Participant’s Bonus Amount for the year in which the Participant’s employment is terminated;

     (b) for the period of months, as specified for each Executive Grade Level in the table below, subsequent to the Participant’s termination of employment, the Company shall at its expense continue on behalf of the Participant and his or her dependents and beneficiaries, the basic life insurance, flexible spending account, medical and dental benefits which were being provided to the Participant immediately prior to the Change in Control (or, if greater, at any time thereafter). The benefits provided in this Subsection 4.2(b) shall be no less favorable to the Participant, in terms of amounts and deductibles and costs to him or her, than the coverage provided the Participant under the plans providing such benefits at the time Notice of Termination is given. The Company’s obligation hereunder to provide the foregoing benefits shall terminate to the extent the Participant obtains replacement coverage under a subsequent employer’s benefit plans at an equal or higher level. The Company also shall pay a lump sum equal to the amount of any additional income tax payable by the Participant and attributable to the benefits

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provided under this subparagraph (b) at the time such tax is imposed upon the Participant;

Number of Months of	Executive	Corporate Title
Continued Coverage	Grade Level	(or Equivalent Position at Subsidiary Level)
36 months	XA	President and Chief Executive Officer
24 months	XB – XE; XF	Executive Vice President and Senior Vice President
12 months	XG – XI	Vice President

     The amounts provided for in Section 4.2(a) shall be paid or transferred within thirty (30) days after the Participant’s termination of employment (or, if Section 4.1(b) applies to the termination, then within 30 days after the Change in Control). The Participant shall not be required to mitigate the amount of any payment provided for in this Plan by seeking other employment or otherwise and no such payment shall be offset or reduced by the amount of any compensation or benefits provided to the Participant in any subsequent employment.

SECTION 5 TERMINATION OF EMPLOYMENT

5.1 Written Notice Required

     Any purported termination of employment, either by the Employer or by the Participant, shall be communicated by written Notice of Termination to the other.

5.2 Termination Date

     In the case of the Participant’s death, the Participant’s Termination Date shall be his or her date of death. In all other cases, the Participant’s Termination Date shall be the date specified in the Notice of Termination subject to the following:

     (a) If the Participant’s employment is terminated by the Employer for Cause or due to Permanent Disability, the date specified in the Notice of Termination shall be at least thirty (30) days from the date the Notice of Termination is given to the Participant, provided that in the case of Permanent Disability the Participant shall not have returned to the full-time performance of his or her duties during such period of at least thirty (30) days; and

     (b) If the Participant terminates his or her employment for Good Reason, the date specified in the Notice of Termination shall not be more than sixty (60) days from the date the Notice of Termination is given to the Employer.

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SECTION 6 ADDITIONAL PAYMENTS BY THE COMPANY

6.1 Gross-Up Payment

     (a) Subject only to Section 6.1(b) hereof, in the event it shall be determined that any payment or distribution of any type by the Company or any of its affiliates to or for the benefit of the Participant, whether paid or payable or distributed or distributable pursuant to the terms of this Plan or otherwise (the “Payments”), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”), or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest and penalties, are collectively referred to as the “Excise Tax”), then the Participant shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Participant of all taxes (including any interest or penalties imposed with respect to such taxes), including any income taxes, employment taxes and Excise Tax, imposed upon the Gross-Up Payment, the Participant retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. Payment of the Gross-Up Payment shall be made in accordance with Section 6.3.

     (b) Notwithstanding Section 6.1(a), in the event that a reduction to the Payments in respect of a Participant of 10% or less would cause no Excise Tax to be payable, the Participant will not be entitled to a Gross-Up Payment and the Payments shall be reduced (but not below zero) to the extent necessary so that the Payments shall not be subject to the Excise Tax. Unless the Participant shall have given prior written notice specifying a different order to the Company to effectuate the foregoing, the Company shall reduce or eliminate the Payments, by first reducing or eliminating the portion of the Payments which are not payable in cash and then by reducing or eliminating cash payments, in each case in reverse order beginning with payments or benefits which are to be paid the farthest in time from the date of the Change in Control. Any notice given by the Participant pursuant to the preceding sentence shall take precedence over the provisions of any other plan, arrangement or agreement governing the Participant’s rights and entitlements to any benefits or compensation.

6.2 Determination By Accountant

     All determinations required to be made under this Section 6, including whether a Gross-Up Payment is required and the amount of such Gross-Up Payment, shall be made by the independent accounting firm retained by the Company on the date of Change in Control (the “Accounting Firm”), which shall provide detailed supporting calculations both to the Company and the Participant within 15 business days of the date of termination, if applicable, or such earlier time as is requested by the Company. If the Accounting Firm determines that no Excise Tax is payable by the Participant, it shall furnish the Participant with an opinion that he or she has substantial authority not to report any Excise Tax on his or her federal income tax return. Any determination by the Accounting Firm shall be binding upon the Company and the Participant. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial

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determination by the Accounting Firm hereunder, it is possible that Gross-Up payments which will not have been made by the Company should have been made (“Underpayment”), consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 6.3 and the Participant thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Participant.

6.3 Notification Required

     The Participant shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten (10) business days after the Participant knows of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Participant shall not pay such claim prior to the expiration of the thirty (30) day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Participant in writing prior to the expiration of such period that it desires to contest such claim, the Participant shall:

(a) give the Company any information reasonably requested by the Company relating to such claim,

(b) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

(c) cooperate with the Company in good faith in order to effectively contest such claim, and

(d) permit the Company to participate in any proceedings relating to such claim; provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Participant harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of such representation and payment of costs and expenses. Without limitation on the foregoing provisions of this Section 6.3, the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Participant to pay the tax claimed and sue for a refund, or contest the claim in any permissible manner, and the Participant agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or

11

more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Participant to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Participant (unless otherwise prohibited by applicable law), on an interest-free basis and shall indemnify and hold the Participant harmless, on an after-tax basis, from any Excise Tax or income tax, including interest or penalties with respect thereto, imposed with respect to such advance or with respect to any imputed income with respect to such advance; and provided, further, that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Participant with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Participant shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

6.4 Repayment

     If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 6.3, the Participant becomes entitled to receive any refund with respect to such claim, the Participant shall (subject to the Company’s complying with the requirements of Section 6.3) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 6.3, a determination is made that the Participant shall not be entitled to any refund with respect to such claim and the Company does not notify the Participant in writing of its intent to contest such denial of refund prior to the expiration of thirty (30) days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof the amount of Gross-Up Payment required to be paid.

SECTION 7 SUCCESSORS TO COMPANY

7.1 Successors

     This Plan shall bind any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, in the same manner and to the same extent that the Company would be obligated under this Plan if no succession had taken place. In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the Company’s obligations under this Plan, in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place.

7.2 Sales of Operating Companies

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     If a Participant’s employment with his or her Employer terminates in connection with the sale, divestiture or other disposition of the stock or assets of any Operating Company (or part thereof) (a “Transaction”) after the execution of an agreement providing for a transaction or transactions which, if consummated, would constitute a Change in Control or after a Change in Control, such termination shall not be a termination of employment of the Participant for purposes of the Plan, and (notwithstanding the rights provided to the Participant by Section 4.1(a)) the Participant shall not be entitled to a Severance Benefit as a result of such termination of employment if (i) the Participant is offered continued employment, or continues in employment, with the divested Operating Company (or part thereof) or the purchaser of the stock or assets of the Operating Company (or part thereof), as the case may be, or one of their respective affiliates (the “Post-Transaction Employer”) on terms and conditions that would not constitute Good Reason and (ii) the Company obtains an agreement from the acquiror of the stock or assets of the divested Operating Company (or part thereof), enforceable by the Participant, to provide or cause the Post-Transaction Employer to provide severance pay and benefits, if the Participant accepts the offered employment or continues in employment with the Post-Transaction Employer or its affiliates following the Transaction, (A) at least equal to the Severance Benefit and (B) payable upon a termination of the Participant’s employment with the Post-Transaction Employer and its affiliates within the period described in Section 4.1(a)(ii) (or such part of it as is then remaining) for any reason other than Cause, Permanent Disability, the Participant’s death or a termination by the Participant without Good Reason. For purposes of this Section 7.2, the terms Cause, Good Reason and Permanent Disability shall have the meanings ascribed to them in Sections 2.5, 2.11 and 2.15 respectively, but the term Employer as it is used in those Sections shall be deemed to refer to the entity employing the Participant after the Transaction, the term Company shall mean such employer or, if there is an ultimate parent corporation of such employer, such ultimate parent corporation, and the terms Board and Chief Executive Officer as used in those Sections shall be deemed to refer to the individuals or bodies serving those functions for such employer or, if applicable, such ultimate parent corporation.

SECTION 8 AMENDMENT AND PLAN TERMINATION

8.1 Amendment and Termination

     Prior to a Change in Control, the Plan may be amended or modified in any respect, and may be terminated, in any such case, by resolution adopted by two-thirds of the Board; provided, however, that no such amendment, modification or termination which would adversely affect the benefits or protections hereunder of any individual who is a Participant as of the date such amendment, modification or termination is adopted shall be effective as it relates to such individual unless no Change in Control occurs within one year after such adoption, any such attempted amendment, modification or termination adopted within one year prior to a Change in Control being null and void ab initio as it relates to all such individuals who were Participants prior to such adoption (it being understood that the removal of Participants from participation in the Plan shall, for purposes of this proviso, constitute an adverse action for the Participants so removed);

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provided, further, however, that the Plan may not be amended, modified or terminated, (i) at the request of a third party who has indicated an intention or taken steps to effect a Change in Control and who effectuates a Change in Control or (ii) otherwise in connection with, or in anticipation of, a Change in Control which actually occurs, any such attempted amendment, modification or termination being null and void ab initio. Any action taken to amend, modify or terminate the Plan which is taken after the execution of an agreement providing for a transaction or transactions which, if consummated, would constitute a Change in Control shall conclusively be presumed to have been taken in connection with a Change in Control. From and after the occurrence of a Change in Control, the Plan may not be amended or modified in any manner that would in any way adversely affect the benefits or protections provided hereunder to any individual who is a Participant in the Plan on the date the Change in Control occurs.

8.2 Form of Amendment

     The form of any amendment or termination of the Plan shall be a written instrument signed by a duly authorized officer or officers of the Company, certifying that the amendment or termination has been approved by the Board.

SECTION 9 MISCELLANEOUS

9.1 Indemnification

     If, after a Change in Control, a Participant institutes any legal action in seeking to obtain or enforce, or is required to defend in any legal action the validity or enforceability of, any right or benefit provided by this Plan, the Company will pay for all actual legal fees and expenses (including, without limitation, attorneys’ fees, filing fees and the costs of experts) as they are incurred by such Participant.

9.2 Employment Status

     This Plan does not constitute a contract of employment or impose on any Employer any obligation to retain the Participant as an employee, to change the status of the Participant’s employment as an Executive Employee, or to change any employment policies of any Employer. Without limiting the generality of the immediately preceding sentence, the Employer of a Participant may terminate the employment of the Participant at any time following a Change in Control, with or without Cause, subject to Section 5 hereof.

9.3 Validity and Severability

     The invalidity or unenforceability of any provision of the Plan shall not affect the validity or enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

9.4 Governing Law; Choice of Forum

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     The validity, interpretation, construction and performance of the Plan shall in all respects be governed by the laws of the State of Texas. A Participant shall be entitled to enforce the provisions of this Plan in any state or federal court located in the State of Texas, in addition to any other appropriate forum.

9.5 Payment to Benefits Protection Trust

     Notwithstanding any other provision of the Plan, the Company shall not be required to make any payment to a Participant under the terms of this Plan if such payment is otherwise made to the Participant by the Benefits Protection Trust in accordance with the provisions of said Benefits Protection Trust.

     IN WITNESS WHEREOF, the Company has caused the Plan to be effective as of the Effective Date.

EL PASO CORPORATION
By	/s/ Susan B. Ortenstone
Title:	Senior Vice President,
	Human Resources

ATTEST:

By	/s/ David L. Siddall
	Corporate Secretary

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APPENDIX I

Operating Companies under the
El Paso Corporation
2004 Key Executive Severance Protection Plan

“Operating Companies” as defined in Section 2.13 shall include the following subsidiaries during the specified time periods.

Employer	Beginning	Ending
ANR Pipeline Company	03/09/2004
Colorado Interstate Gas Company	03/09/2004
El Paso Energy Service Company	03/09/2004
El Paso Global Networks	03/09/2004
El Paso Merchant Energy North America	03/09/2004
El Paso Merchant Energy-Petroleum	03/09/2004
El Paso Natural Gas Company	03/09/2004
El Paso Power Operations Company	03/09/2004
El Paso Production Company	03/09/2004
Sandbar Petroleum Company	03/09/2004
Southern Natural Gas Company	03/09/2004
Tennessee Gas Pipeline Company	03/09/2004

Acknowledged and Accepted this 9th day of March, 2004.

By:
	Susan B. Ortenstone
	Senior Vice President,
	Human Resources

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APPENDIX II

Eligible Employees Covered by the
El Paso Corporation
2004 Key Executive Severance Protection Plan
(as of March 9, 2004)

Executive Employees in Executive Grade Levels XA – XI as of the effective date of the Plan shall be eligible to become Participants in the Plan; provided, however, that an Executive Employee who is a participant in the Company’s Key Executive Severance Protection Plan or Employee Severance Protection Plan must waive participation therein as a condition to becoming a Participant in this Plan.

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EX-10.J

Exhibit 10.J

EL PASO ENERGY CORPORATION

DIRECTOR CHARITABLE AWARD PLAN

Amended and Restated Effective as of August 1, 1998

TABLE OF CONTENTS

SECTION 1 ESTABLISHMENT, PURPOSE, AND DURATION	1
1.1 Establishment of the Plan	1
1.2 Purpose of the Plan	1
1.3 Duration of the Plan	1
SECTION 2 DEFINITIONS AND CONSTRUCTION	1
SECTION 3 ADMINISTRATION	3
3.1 Management Committee	3
3.2 Decisions Binding	4
SECTION 4 ELIGIBILITY AND PARTICIPATION	4
4.1 Eligibility	4
4.2 Actual Participation	4
SECTION 5 CHARITABLE AWARDS	4
5.1 Size of Charitable Awards	4
5.2 Designation of Donees	4
5.3 Changes in Designations of Donees	5
5.4 Security for Donations	5
5.5 Change in Control	5
5.6 Payment of Charitable Awards	6
SECTION 6 AMENDMENT, MODIFICATION, AND TERMINATION	6
SECTION 7 INDEMNIFICATION	6
SECTION 8 MISCELLANEOUS	7
8.1 Successors	7
8.2 Nontransferability	7
8.3 Gender and Number	7
8.4 Severability	7
8.5 Governing Law	7

El Paso Energy Corporation
Director Charitable Award Plan - i - Table of Contents

EL PASO ENERGY CORPORATION
DIRECTOR CHARITABLE AWARD PLAN
Amended and Restated Effective as of August 1, 1998

SECTION 1 ESTABLISHMENT, PURPOSE, AND DURATION

1.1 Establishment of the Plan

     El Paso Energy Corporation, a Delaware corporation (hereinafter referred to as the “Company”), hereby establishes a charitable award program for Directors (as defined below), to be known as the “El Paso Energy Corporation Director Charitable Award Plan” (hereinafter referred to as the “Plan”), as set forth in this document. The Plan provides for the contribution by the Company of one million dollars ($1,000,000) on behalf of each Director, to Charitable Organizations (as defined below)of each Director’s choice subject to the terms and provisions of this Plan.

     The Board of Directors of the Company amended and restated effective as of August 1, 1998. The term “Effective Date” shall mean January 15, 1992.

1.2 Purpose of the Plan

     The purpose of the Plan is to promote the mutual interest of the Directors and the Company to support worthy Charitable Organizations, and to enhance the positive image of the Company.

     The Plan is further intended to acknowledge the service of the Company’s Directors, and to aid the Company in its ability to attract, motivate, and retain the services of highly qualified Directors, upon whose judgment, interest, and special effort the continued successful operation of the Company largely is dependent.

1.3 Duration of the Plan

     The Plan commenced on the Effective Date and shall remain in effect until terminated by the Board of Directors.

SECTION 2 DEFINITIONS AND CONSTRUCTION

     Whenever used in this Plan, the following terms shall have the meanings set forth below and, when the meaning is intended, the initial letter of the word is capitalized.

     (a) “Board” or “Board of Directors” means the Board of Directors of the Company.

El Paso Energy Corporation
Director Charitable Award Plan Page 1

     (b) “Change in Control” of the Company shall be deemed to have occurred if the conditions set forth in any one or more of the following paragraphs shall have been satisfied:

     (i) any person (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) being or becoming the “beneficial owner” (as defined in Rule 13d-3 of the Exchange Act) directly or indirectly, of securities of the Company representing twenty percent (20%) or more of the combined voting power of the then outstanding securities of the Company,

     (ii) the first purchase of the Company’s Common Stock pursuant to a tender or exchange offer (other than a tender or exchange offer made by the Company),

     (iii) the approval by the Company’s stockholders of a merger or consolidation, a sale or disposition of all or substantially all of the Company’s assets or a plan of liquidation or dissolution of the Company, or

     (iv) during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of the Company ceasing for any reason to constitute at least a majority thereof, unless the election or nomination for the election by the Company’s stockholders of each new director was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of the period.

Notwithstanding the foregoing, a Change in Control shall not be deemed to occur if the Company either merges or consolidates with or into another company or sells or disposes of all or substantially all of its assets to another company, if such merger, consolidation, sale or disposition is in connection with a corporate restructuring wherein the stockholders of the Company immediately before such merger, consolidation, sale or disposition own, directly or indirectly, immediately following such merger, consolidation, sale or disposition at least eighty percent (80%) of the combined voting power of all outstanding classes of securities of the company resulting from such merger or consolidation, or to which the Company sells or disposes of its assets, in substantially the same proportion as their ownership in the Company immediately before such merger, consolidation, sale or disposition.

     (c) “Charitable Award” means, individually or collectively, a donation to be made to a Charitable Organization chosen by a Participant pursuant to the terms of Section 5 herein.

     (d) “Charitable Organization” means any public or private charitable organization in the United States or its possessions which is a corporation, trust, community chest, fund, foundation, or association, provided contributions to such entity are deductible under Section 170(c) of the Code.

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     (e) “Code” means the Internal Revenue Code of 1986, as amended, or any successor statute, and the Treasury Regulations promulgated thereunder.

     (f) “Committee” means the management committee as specified in Section 3 herein.

     (g) “Company” means El Paso Energy Corporation, a Delaware corporation, or any successor thereto as provided in Section 8.1 herein.

     (h) “Director” means any individual who is a member of the Board of Directors of the Company.

     (i) “Effective Date” means the date on which the Plan became effective, as designated by the Board of Directors pursuant to Section 1.1 herein.

     (j) “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, or any successor Act thereto.

     (k) “Participant” means a Director of the Company who has been notified of his or her eligibility to participate in this Plan, pursuant to Section 4.2 herein.

     (l) “Person” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act, and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d).

     (m) “Qualified Donee” means any Charitable Organization which has not been denied status as a Qualified Donee by the Board of Directors, pursuant to Section 5.2 herein.

SECTION 3 ADMINISTRATION

3.1 Management Committee

     The Plan shall be administered by the Board of Directors and a management committee (the “Committee”) consisting of the Chief Executive Officer and such other senior officers as he or she shall designate. The Committee shall interpret the Plan, prescribe, amend, and rescind rules relating to it, select eligible Participants, and take all other actions necessary for its administration. No member of the Committee shall vote on any matter that pertains solely to himself or herself.

3.2 Decisions Binding

     All determinations and decisions made by the Board of Directors and/or the Committee pursuant to the administration of this Plan shall be final, conclusive, and

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binding on all parties, including the Company, its stockholders, employees, Participants, and their estates and beneficiaries.

SECTION 4 ELIGIBILITY AND PARTICIPATION

4.1 Eligibility

     Persons who are elected to serve on the Board of Directors on or after the Effective Date shall be eligible to participate in this Plan on the second anniversary of the date of their election to the Board; provided, however, that such Directors must have continuously served on the Board throughout such two-year period.

4.2 Actual Participation

     Subject to the terms and conditions of this Plan, the Committee shall notify each eligible Director of his or her eligibility to participate in this Plan as soon as practicable following the date that each such Director first becomes eligible for participation.

SECTION 5 CHARITABLE AWARDS

5.1 Size of Charitable Awards

     Each Participant shall have the right to designate Qualified Donees to which an aggregate of up to one million dollars ($1,000,000) shall be donated by the Company on behalf of the Participant. Participants may designate up to four Qualified Donees; provided, however, that the total funds which shall be donated by the Company on behalf of any one Participant shall not exceed one million dollars ($1,000,000).

5.2 Designation of Donees

     Each Participant shall nominate Charitable Organizations to receive Charitable Awards by providing formal notice of such nominations to the Committee. Following the receipt of the nominations of organizations, the Committee will approve the nomination or recommend to the Board that the nomination be denied. In the event the Committee does not recommend to the Board that the nomination be denied within six months of receipt of such nomination, the nomination shall be deemed accepted by the Committee. Further, if the Participant should die before the Committee, or the Board in the case of denials, acts on the nominations, such nomination shall be deemed accepted provided the nominee is a qualified Charitable Organization, as defined herein. The Board of Directors, by majority vote, shall have the authority to deny status as a Qualified Donee to any organization nominated by a Participant. In the event one or more organizations nominated by a Participant for status as a Qualified Donee are denied such status by the Board of Directors, the Participant may nominate additional organizations to receive a Charitable Award, subject to the approval of the Committee (or

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the denial by the Board, as applicable). If a Participant fails to designate a Qualified Donee, the Charitable Award to be made on behalf of such Participant shall lapse.

     All nominations of organizations to receive Charitable Awards shall be made on a Charitable Award Nomination Form, which shall specify the following: (i) the name of the nominated organization; (ii) the amount desired by the Participant to be donated to the organization; (iii) the name under which the donation is to be made; and (iv) any other terms and provisions deemed necessary by the Board of Directors or the Committee. Each completed Charitable Award Nomination Form shall be submitted to the Executive Vice President, Human Resources and Administration.

5.3 Changes in Designations of Donees

     Participants may, at any time, nominate an alternative Charitable Organization to receive a Charitable Award (subject to Committee approval, as described in Section 5.2 herein). In addition, Participants may, at any time, request a change in the amount of money to be donated to each such Qualified Donee, or a change in the name under which the donation is to be made, subject to approval (as described in Section 5.2 herein).

     Changes in the designation of Qualified Donees or in any other terms applicable to the Charitable Awards, shall be made on a Charitable Award Nomination Form, which shall specify the new or additional organizations nominated to receive a Charitable Award, the amount of money to be donated in the name of the Participant to each Qualified Donee, and any other terms or provisions deemed necessary by the Board of Directors or the Committee.

5.4 Security for Donations

     The Company’s obligations under this Plan may be unfunded and unsecured promises to donate money in the future. No Qualified Donee shall have the right to a donation solely by virtue of the designation of such Qualified Donee by a Participant. Following the death of a Participant, the rights of each Qualified Donee designated by the Participant shall be those of a general unsecured creditor of the Company.

5.5 Change in Control

     Notwithstanding any other provision of this Plan, upon a Change in Control of the Company, the commitment of the Company to donate the Charitable Awards to the Qualified Donees shall become an irrevocable obligation. Following a Change in Control, the Board of Directors may not amend, modify, or terminate the Charitable Awards of the Participants in a way which would decrease the value of the donations. In addition, following a Change in Control, the Participants shall retain the right to change the designations of their Qualified Donees, pursuant to Section 5.3 herein, without Board or Committee review.

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5.6 Payment of Charitable Awards

     As soon as practicable following the death of a Participant, the Company shall donate the Charitable Awards to the Qualified Donees, in the amounts requested by the Participant and approved by the Board of Directors or Committee. Such payment shall be made in one lump sum. No contribution will be made under this Plan to an otherwise Qualified Donee if the payment thereof will result in the receipt of property or other direct economic benefits to the Company or its subsidiaries or to the Participants or to the family members of any Participant.

SECTION 6 AMENDMENT, MODIFICATION, AND TERMINATION

     Except as set forth in Section 5.5, the Board may from time to time amend, suspend, or terminate the Plan, in whole or in part, and if the Plan is suspended or terminated, the Board may reinstate any or all of its provisions. The Committee may amend the Plan provided that it may not suspend or terminate the Plan or substantially increase the administrative cost of the Plan or the obligations of the Company. The Board of Directors amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Energy Corporation became the publicly held company and El Paso Natural Gas Company became a wholly owned subsidiary. This Plan was assumed by El Paso Energy Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Energy Corporation and El Paso Natural Gas Company.

SECTION 7 INDEMNIFICATION

     Each individual who is or shall have been a member of the Committee, or of the Board, shall be indemnified and held harmless by the Company against and from any loss, cost, liability, or expense that may be imposed upon or reasonably incurred by him or her in connection with or resulting from any claim, action, suit, or proceeding to which he or she may be a party or in which he or she may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by him or her in settlement thereof, with the Company’s approval, or paid by him or her in satisfaction of any judgment in any such action, suit, or proceeding against him or her, provided he or she shall give the Company an opportunity, at its own expense, to handle and defend the same before he or she undertakes to handle and defend it on his or her own behalf.

     The foregoing right in indemnification shall not be exclusive of any other rights of indemnification to which such individuals may be entitled under the Company’s Restated Certificate of Incorporation or By-laws, as a matter of law, or otherwise, or any power that the Company may have to indemnify them or hold them harmless.

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SECTION 8 MISCELLANEOUS

8.1 Successors

     All obligations of the Company under this Plan shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, or otherwise, of all or substantially all of the business and/or assets of the Company.

8.2 Nontransferability

     The right to nominate organizations to receive Charitable Awards under this Plan shall be personal to Participants, and may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated.

8.3 Gender and Number

     Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine; the plural shall include the singular, and the singular shall include the plural.

8.4 Severability

     In the event any provision of this Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of this Plan, and this Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

8.5 Governing Law

     To the extent not preempted by Federal law, this Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the State of Texas.

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     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of August 1, 1998.

EL PASO ENERGY CORPORATION
By	/s/ Joel Richards, III
Title:	Executive Vice President

ATTEST:

By	/s/ David L. Siddall
Title: Corporate Secretary

El Paso Energy Corporation
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EX-10.J.2

Exhibit 10.J.2

AMENDMENT NO. 2 TO THE
EL PASO CORPORATION
DIRECTOR CHARITABLE AWARD PLAN

     Pursuant to authorization by the El Paso Corporation Board of Directors (the “Board”) and Section 6 of the El Paso Corporation Director Charitable Award Plan, Amended and Restated effective as of August 1, 1998, as amended (the “Plan”), the Plan is hereby amended as follows, effective December 4, 2003:

     WHEREAS, the Board, based upon a recommendation from its Compensation Committee, has determined it is in the best interests of the Company to terminate the Plan.

     NOW THEREFORE, the Plan is hereby terminated, effective December 4, 2003. The termination of the Plan does not affect the designation of Charitable Awards under the Plan by a Participant who has met the two-year service requirement on the Board and has been notified of his or her eligibility to participate in the Plan prior to the effective date of this amendment.

     IN WITNESS WHEREOF, the Company has caused this amendment to be duly executed on this 4^th day of December, 2003.

EL PASO CORPORATION
By:	/s/ Susan B. Ortenstone
	Susan B. Ortenstone
	Senior Vice President, Human Resources

Attest:

/s/ David L. Siddall

Corporate Secretary

EX-10.R

EXHIBIT 10.R

INDEMNIFICATION AGREEMENT

     This Indemnification Agreement (this “Agreement”) is made and delivered this 15th day of December, 2004, by El Paso Corporation (the “Company”), to and for the benefit of Douglas L. Foshee (“Foshee”).

RECITALS

     WHEREAS, the Company executed an Indemnification Agreement dated September 2, 2003, for the benefit of Foshee upon Foshee’s election to the Company’s Board of Directors (“Board”) and it is the Company’s intent that this Indemnification Agreement shall replace the Indemnification Agreement dated September 2, 2003. Notwithstanding the foregoing, to the extent any claims for indemnification or advancement of expenses existed under his prior agreement, such claims shall be governed by the terms of that agreement.

     WHEREAS, in order to induce Foshee to continue as a member of the Company’s Board and as an officer of the Company (“Officer”), the Company is executing and delivering to Foshee this Indemnification Agreement.

     NOW, THEREFORE, in consideration of the foregoing, the mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Company hereby agrees as follows:

SECTION 1. Right To Indemnification

     If Foshee is made a party or is threatened to be made a party to or is involved (including, without limitation, as a witness) in any actual or threatened action, suit or proceeding, whether civil, criminal, administrative or investigative (hereinafter a “proceeding”), by reason of the fact that he is or was a Director or Officer of the Company (or of any subsidiary of the Company) or is or was serving at the request of the Company or the Board of Directors, including service with respect to any employee benefit plan or any subsidiary of the Company, whether the basis of such proceeding is alleged action in an official capacity as a Director or Officer or in any other capacity while serving as a Director or Officer, he shall be indemnified and held harmless by the Company to the fullest extent permitted by the General Corporation Law of the State of Delaware, as the same exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Company to provide broader indemnification rights than said law permitted the Company to provide prior to such amendment), or by other applicable law as then in effect, against all expense, liability and loss (including attorneys’ fees, judgments, fines, ERISA excise taxes or penalties and amounts to be paid in settlement) actually and reasonably incurred or suffered by him in connection therewith and such indemnification shall continue after Foshee has ceased to be a Director or Officer and shall inure to the benefit of Foshee’s heirs, executors and administrators; provided, however, that except as provided in Section 2 of this Agreement with respect to proceedings seeking to enforce

rights to indemnification or to advancement of expenses, the Company shall be required to indemnify Foshee in connection with a proceeding (or part thereof) initiated by Foshee only if such proceeding (or part thereof) was authorized by the Board. The right to indemnification conferred in this Agreement shall include the right to be paid by the corporation the reasonable expenses (including attorneys’ fees) incurred in defending any such proceeding in advance of its final disposition (hereinafter an “advancement of expenses”); further provided, however, that, if the General Corporation Law of the State of Delaware requires, an advancement of expenses incurred by Foshee in his capacity as a Director or Officer (and not in any other capacity in which service was or is rendered by Foshee while a Director or Officer, including, without limitation, service to an employee benefit plan) shall be made only upon delivery to the Company of an undertaking, if permitted by Federal Law, by or on behalf of Foshee, to repay all amounts so advanced if it shall ultimately be determined that he is not entitled to be indemnified under this Agreement, or otherwise, and provided further that except as provided in Section 2 of this Agreement with respect to proceedings seeking to enforce rights to indemnification or an advancement of expenses, the Company shall be required to advance expenses to Foshee in connection with a proceeding initiated by him only if such proceeding was authorized by the Board.

SECTION 2. Right To Bring Suit

     If a claim under Section 1 of this Agreement is not paid in full by the Company (following the final disposition of the proceeding) within sixty (60) days after a written claim has been received by the Company, except in the case of a claim for an advancement of expenses, in which case final disposition of the proceeding is not required and the applicable period shall be twenty (20) days, Foshee may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim and, to the extent successful in whole or in material part, Foshee shall be entitled to be paid the expense of prosecuting such suit. Foshee shall be presumed to be entitled to indemnification under this Agreement upon submission of a written claim (and, in an action brought to enforce a claim for an advancement of expenses, where the required undertaking, if any is required, has been tendered to the Company), and thereafter the Company shall have the burden of proof to overcome the presumption that Foshee is not so entitled. Neither the failure of the Company (including its Board, independent legal counsel, or its stockholders), to have made a determination prior to the commencement of such suit that indemnification of Foshee is proper in the circumstances, nor an actual determination by the Company (including its Board, independent legal counsel or its stockholders) that Foshee is not entitled to indemnification, shall be a defense to the suit or create a presumption that Foshee is not so entitled.

SECTION 3. Nonexclusivity of Rights

     The rights to indemnification and to the advancement of expenses conferred in this Agreement are in addition to and shall not be exclusive of any other right Foshee may have or hereafter acquire under any statute, provision of the Restated Certificate of Incorporation of the Company or its By-laws, or under any other plan, program, arrangement, agreement, vote of stockholders or disinterested Directors or otherwise.

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SECTION 4. Insurance, Contracts and Funding

     The Company may maintain insurance, at its expense, to protect itself and Foshee against any expense, liability or loss, whether or not the Company would have the power to indemnify Foshee against such expense, liability or loss under the General Corporation Law of the State of Delaware. The Company may enter into contracts with Foshee in furtherance of the provisions of this Agreement and may create a trust fund, grant a security interest or use other means (including, without limitation, a letter of credit) to ensure the payment of such amounts as may be necessary to effect indemnification as provided in this Agreement. To the extent the Company maintains an insurance policy or policies providing directors’ and officers’ liability insurance, Foshee shall be covered by such policy or policies, in accordance with its or their terms, to the maximum extent of the coverage available for any Company director or officer.

SECTION 5. Change of Control

     (a) A “Change in Control” shall mean the occurrence of any of the following:

(I) An acquisition (other than directly from the Company) of any voting securities of the Company (the “Voting Securities”) by any “Person” (as the term “person” is used for purposes of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), immediately after which such Person has “Beneficial Ownership” (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of more than twenty percent (20%) of (1) the then-outstanding shares of common stock of the Company (or any other securities into which such shares of common stock are changed or for which such shares of common stock are exchanged) (the “Shares”) or (2) the combined voting power of the Company’s then-outstanding Voting Securities; provided, however, that in determining whether a Change in Control has occurred pursuant to this paragraph (I), the acquisition of Shares or Voting Securities in a “Non-Control Acquisition” (as hereinafter defined) shall not constitute a Change in Control. A “Non-Control Acquisition” shall mean an acquisition by (i) an employee benefit plan (or a trust forming a part thereof) maintained by (A) the Company or (B) any corporation or other Person the majority of the voting power, voting equity securities or equity interest of which is owned, directly or indirectly, by the Company (for purposes of this definition, a “Related Entity”), (ii) the Company or any Related Entity, or (iii) any Person in connection with a “Non-Control Transaction” (as hereinafter defined);

(II) The individuals who, as of the Effective Date, are members of the board of directors of the Company (the “Incumbent Board”), cease for any reason to constitute at least a majority of the members of the board of directors of the Company or, following a Merger (as hereinafter defined), the board of directors of (x) the corporation resulting from such Merger (the “Surviving Corporation”), if fifty percent (50%) or more of the combined voting power of the then-outstanding voting securities of the Surviving Corporation is not Beneficially Owned, directly or indirectly, by another Person (a “Parent Corporation”) or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation; provided, however, that, if the election, or nomination for election by the Company’s common stockholders, of any new director was approved by a

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vote of at least two-thirds of the Incumbent Board, such new director shall, for purposes of the Plan, be considered a member of the Incumbent Board; and provided, further, however, that no individual shall be considered a member of the Incumbent Board if such individual initially assumed office as a result of an actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the board of directors of the Company (a “Proxy Contest”), including by reason of any agreement intended to avoid or settle any Proxy Contest; or

(III) The consummation of:

          (i) A merger, consolidation or reorganization (1) with or into the Company or (2) in which securities of the Company are issued (a “Merger”), unless such Merger is a “Non-Control Transaction.” A “Non-Control Transaction” shall mean a Merger in which:

     (A) the stockholders of the Company immediately before such Merger own directly or indirectly immediately following such Merger at least fifty percent (50%) of the combined voting power of the outstanding voting securities of (x) the Surviving Corporation, if there is no Parent Corporation or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation;

     (B) the individuals who were members of the Incumbent Board immediately prior to the execution of the agreement providing for such Merger constitute at least a majority of the members of the board of directors of (x) the Surviving Corporation, if there is no Parent Corporation, or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation; and

     (C) no Person other than (1) the Company, (2) any Related Entity, or (3) any employee benefit plan (or any trust forming a part thereof) that, immediately prior to the Merger, was maintained by the Company or any Related Entity, or (4) any Person who, immediately prior to the Merger had Beneficial Ownership of twenty percent (20%) or more of the then outstanding Shares or Voting Securities, has Beneficial Ownership, directly or indirectly, of twenty percent (20%) or more of the combined voting power of the outstanding voting securities or common stock of (x) the Surviving Corporation, if fifty percent (50%) or more of the combined voting power of the then outstanding voting securities of the Surviving Corporation is not Beneficially Owned, directly or indirectly by a Parent Corporation, or (y) if there is one or more than one Parent Corporation, the ultimate Parent Corporation;

          (ii) A complete liquidation or dissolution of the Company; or

          (iii) The sale or other disposition of all or substantially all of the assets of the Company and its subsidiaries taken as a whole to any Person (other than (x) a transfer to a Related Entity, (y) a transfer under conditions that would constitute a Non-Control Transaction, with the disposition of assets being regarded as a Merger for this

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purpose or (z) the distribution to the Company’s stockholders of the stock of a Related Entity or any other assets).

Notwithstanding the foregoing, a Change in Control shall not be deemed to occur solely because any Person (the “Subject Person”) acquired Beneficial Ownership of more than the permitted amount of the then outstanding Shares or Voting Securities as a result of the acquisition of Shares or Voting Securities by the Company which, by reducing the number of Shares or Voting Securities then outstanding, increases the proportional number of shares Beneficially Owned by the Subject Persons; provided, that if a Change in Control would occur (but for the operation of this sentence) as a result of the acquisition of Shares or Voting Securities by the Company and, after such share acquisition by the Company, the Subject Person becomes the Beneficial Owner of any additional Shares or Voting Securities and such Beneficial Ownership increases the percentage of the then outstanding Shares or Voting Securities Beneficially Owned by the Subject Person, then a Change in Control shall occur.

     (b) Change in Control of the Company. The Company agrees that if there is a Change in Control of the Company, then with respect to all matters thereafter arising concerning the rights of Foshee to indemnity payments and expense advances under this Agreement, any other agreements, the Restated Certificate of Incorporation or the By-laws now or hereafter in effect relating to a proceeding, the Company shall seek legal advice only from special independent counsel selected by Foshee and approved by the Company (which approval shall not be unreasonably withheld), and who has not otherwise performed services for the Company (other than in connection with such matters) or Foshee. In the event that Foshee and the Company are unable to agree on the selection of the special independent counsel, such special independent counsel shall be selected by lot from among at least five law firms in New York City, New York or Houston, Texas selected by Foshee, each having no less than 50 partners. Such selection shall be made in the presence of Foshee (and his legal counsel or either of them, as Foshee may elect). Such special independent counsel, among other things, shall determine whether and to what extent Foshee would be permitted to be indemnified under applicable law and shall render its written opinion to the Company and Foshee to such effect.

     The Company agrees to pay the reasonable fees of the special independent counsel referred to above and to fully indemnify such counsel against any and all expenses (including attorneys’ fees), claims, liabilities and damages arising out of or relating to this Agreement or its engagement pursuant hereto.

SECTION 6. No Modification

     No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by both of the parties hereto. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provisions hereof (whether or not similar) nor shall such waiver constitute a continuing waiver. Any waiver to this agreement shall be in writing.

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SECTION 7. Subrogation

     In the event of payment under this Agreement, the Company shall be subrogated to the extent of such payment to all of the rights of recovery of Foshee, who shall execute all papers required and shall do everything that may be necessary to secure such rights, including the execution of such documents necessary to enable the Company effectively to bring suit to enforce such rights.

SECTION 8. No Duplication of Payments

     The Company shall not be liable under this Agreement to make any payment in connection with any proceeding against Foshee to the extent Foshee has otherwise actually received payment (under any insurance policy or otherwise) of the amounts otherwise indemnifiable hereunder.

SECTION 9. Notification and Defense of Proceedings

     Foshee agrees that he will use all reasonable efforts to notify the Company promptly after receipt by Foshee of notice of the commencement of any proceeding if he anticipates that a request for indemnification in respect thereof is to be made against the Company under this Agreement; but failure to so notify the Company will not relieve the Company from any indemnification or other obligation or liability which it may have to Foshee. With respect to any such proceeding as to which Foshee notifies the Company of the commencement thereof:

     (a) the Company will be entitled to participate therein at its own expense; and

     (b) except as otherwise provided below, to the extent that it may wish, the Company jointly with any other indemnifying party similarly notified will be entitled to assume the defense thereof, with counsel satisfactory to Foshee. After notice from the Company to Foshee of its election to assume the defense thereof, the Company will not be liable to Foshee under this Agreement for any legal or other expenses subsequently incurred by Foshee in connection with the defense thereof other than reasonable costs of investigation or as otherwise provided below. Foshee shall have the right to employ its counsel in such proceeding, but the fees and expenses of such counsel incurred after notice from the Company of its assumption of the defense thereof shall be at the expense of Foshee unless (i) the employment of counsel by Foshee has been authorized by the Company, (ii) Foshee shall have reasonably concluded that there may be a conflict of interest between the Company and Foshee in the conduct of the defense of such proceeding or (iii) the Company shall not in fact have employed counsel to assume the defense of such proceeding, in each of which cases the fees and expenses of counsel shall be at the expense of the Company. The Company shall not be entitled to assume the defense of any proceeding brought by or on behalf of the Company or as to which Foshee shall have made the conclusion provided for in clause (ii) of this subsection 9(b).

     (c) The Company shall not be liable to indemnify Foshee under this Agreement for any amounts paid in settlement of any proceeding effected by Foshee without the Company’s prior written consent. The Company shall not settle any proceeding in any manner which would

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impose any penalty or limitation on Foshee without Foshee’s prior written consent. Neither the Company nor Foshee will unreasonably withhold their consent to any proposed settlement.

SECTION 10. No Presumptions

     For purposes of this Agreement, the termination of any proceeding against Foshee by judgment, order, settlement (whether with or without court approval) or conviction, or upon a plea of nolo contendere, or its equivalent, shall not create a presumption that Foshee did not meet any particular standard of conduct or have any particular belief or that a court has determined that indemnification is not permitted by applicable law. In addition, neither the failure of the Company to have made a determination as to whether Foshee has met any particular standard of conduct or had any particular belief, nor an actual determination by the Company that Foshee has not met such standard of conduct or did not have such belief, prior to the commencement of legal proceedings by Foshee to secure a judicial determination that Foshee should be indemnified under applicable law shall be a defense to Foshee’s claim for indemnification or create a presumption that Foshee has not met any particular standard of conduct or did not have any particular belief.

SECTION 11. Acknowledgment of Reliance

     The Company acknowledges that Foshee is relying on this Agreement and the promises and agreements of the Company herein in continuing his service as a Director and an Officer and in agreeing to undertake and in undertaking his responsibilities, duties and services to and for the Company in connection therewith.

SECTION 12. Miscellaneous

     This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware. Each provision hereof is intended to be severable and the invalidity or illegality of any portion of this Agreement shall not affect the validity or legality of the remainder.

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     Executed as an instrument under seal as of the day and year first above written.

EL PASO CORPORATION
By:	/s/ Susan B. Ortenstone
Name:	Susan B. Ortenstone
Title:	Senior Vice President Human Resources
Hereunto duly authorized
By:	/s/ Ronald L. Kuehn, Jr.
Name:	Ronald L. Kuehn, Jr.
Title:	Chairman of the Board
Hereunto duly authorized

- 8 -

EX-10.T.1

Exhibit 10.T.1

AMENDMENT NO. 1 TO THE

EL PASO CORPORATION

2005 OMNIBUS INCENTIVE COMPENSATION PLAN

(as amended and restated)

     WHEREAS, El Paso Corporation (the “Company”) maintains the El Paso Corporation 2005 Omnibus Incentive Compensation Plan, as amended and restated effective May 6, 2009 (the “Plan”); and

     WHEREAS, pursuant to Section 19.1 of the Plan, the Board of Directors may amend the Plan, in whole or in part; and

     WHEREAS, it is hereby intended that the Plan be amended to permit the settlement of stock appreciation rights in cash and to incorporate minimum vesting restrictions applicable to Other Stock-Based Awards (as such term is defined in the Plan).

     NOW, THEREFORE, the Plan is amended as follows:

1.	Section 7.2 is amended by revising the second sentence thereof to read as follows:
	“Upon exercise of a stock appreciation right, a Participant shall be entitled to receive payment from the Company in an amount determined by multiplying (i) the difference between the Fair Market Value of a share of Common Stock on the date of exercise of the stock appreciation right over the price fixed at the date of grant (which price shall not be less than 100% of the Fair Market Value of a share of Common Stock on the date of grant) times (ii) the number of shares of Common Stock with respect to which the stock appreciation right is exercised.”
2.	Section 7.2 is further amended by replacing the final sentence thereof with the following:
	“At the discretion of the Plan Administrator, the payment upon stock appreciation right exercise may be in cash, in shares of Common Stock of equivalent value, or in some combination thereof.”
3.	Section 12.2 is amended by adding the following sentences to the end thereof:
	“Notwithstanding the above, the minimum vesting period for Other Stock-Based Awards with no performance-based vesting characteristics shall be three (3) years (vesting may occur ratably each month, quarter or anniversary of the grant date over such vesting period), and the minimum vesting period for Other Stock-Based Awards subject to restrictions based upon the achievement of specific Performance Goals or performance measures shall be one (1) year; provided, however, that the Plan Administrator may grant a “de minimis” number of Other Stock-Based Awards that do not comply with the foregoing minimum vesting

standards. For this purpose “de minimis” means five percent (5%) or less of the maximum number of shares of Common Stock that may be issued under the Plan pursuant to Section 5.2(b) herein, subject to adjustment under Section 5.3.”

     IN WITNESS WHEREOF, this amendment has been executed by the undersigned, thereunto duly authorized, effective as of October 14, 2009.

EL PASO CORPORATION
By:	/s/ Susan B. Ortenstone
	Its Senior Vice President, Human Resources

ATTEST:

By: /s/ Marguerite Woung-Chapman   Corporate Secretary

-2-

EX-10.V

EXHIBIT 10.V

EXECUTION VERSION

THIRD AMENDED AND RESTATED
CREDIT AGREEMENT

dated as of

November 16, 2007

among

EL PASO CORPORATION,

EL PASO NATURAL GAS COMPANY and
TENNESSEE GAS PIPELINE COMPANY,
as Borrowers

The Lenders Party Hereto

and

JPMORGAN CHASE BANK, N.A.,
as Administrative Agent and Collateral Agent

CITICORP NORTH AMERICA, INC.,
Syndication Agent

ABN AMRO BANK N.V., BANK OF AMERICA, N.A. and
DEUTSCHE BANK SECURITIES INC.,
Co-Documentation Agents

CITIGROUP GLOBAL MARKETS INC. and J.P. MORGAN SECURITIES INC.,
as Joint Bookrunners and Co-Lead Arrangers

TABLE OF CONTENTS

	Page
ARTICLE 1
Definitions
Section 1.01. Defined Terms		1
Section 1.02. Terms Generally		22
Section 1.03. Accounting Terms; GAAP		22
ARTICLE 2
The Credits
Section 2.01. Commitments		23
Section 2.02. Loans and Borrowings		23
Section 2.03. Requests for Borrowings		23
Section 2.04. Letters of Credit		24
Section 2.05. Funding Of Borrowings		28
Section 2.06. Interest Elections		29
Section 2.07. Optional and Mandatory Termination and Reduction of Commitments		30
Section 2.08. Repayment of Loans; Evidence of Debt		31
Section 2.09. Optional and Mandatory Prepayment of Loans		32
Section 2.10. Fees		32
Section 2.11. Interest		33
Section 2.12. Alternate Rate of Interest		34
Section 2.13. Increased Costs		34
Section 2.14. Break Funding Payments		36
Section 2.15. Taxes		36
Section 2.16. Payments Generally; Pro Rata Treatment; Sharing of Set-Offs		37
Section 2.17. Mitigation Obligations; Replacement of Lenders		39
ARTICLE 3
Conditions
Section 3.01. Effective Date; Conditions to Initial Credit Event		40
Section 3.02. Each Credit Event		42
Section 3.03. Changes In Lenders And Commitments		43
ARTICLE 4
Representations and Warranties
Section 4.01. Organization; Powers		44
Section 4.02. Authorization		44
Section 4.03. Governmental Approvals; No Conflicts		44
Section 4.04. Binding Obligation; Enforceability		44
Section 4.05. Financial Condition		44

Third Amended and Restated Credit Agreement

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	Page
Section 4.06. Compliance with Laws and Agreements		45
Section 4.07. Litigation		45
Section 4.08. Taxes		46
Section 4.09. Properties		46
Section 4.10. ERISA		46
Section 4.11. Investment Company Act		47
Section 4.12. Federal Reserve Regulations		47
Section 4.13. Collateral		47
Section 4.14. Environmental Matters		47
Section 4.15. Disclosure		47
Section 4.16. Subsidiaries		47
ARTICLE 5
Affirmative Covenants
Section 5.01. Preservation of Existence		48
Section 5.02. Compliance with Laws		48
Section 5.03. Visitation Rights		48
Section 5.04. Books and Records		48
Section 5.05. Maintenance of Properties		48
Section 5.06. Maintenance of Insurance		48
Section 5.07. Security Interests in Collateral		49
Section 5.08. Reporting Requirements		49
Section 5.09. Collateral Reporting		51
ARTICLE 6
Negative Covenants
Section 6.01. Liens		51
Section 6.02. Financial Covenants		53
Section 6.03. Debt		53
Section 6.04. Disposition of Property or Assets		54
Section 6.05. Mergers		56
Section 6.06. Use of Proceeds		57
Section 6.07. Transactions with Affiliates		57
Section 6.08. Restrictive Agreements		57
ARTICLE 7
Events of Default
ARTICLE 8
Company Guarantee
Section 8.01. Company Guarantee		61
Section 8.02. No Subrogation		62
Section 8.03. Amendments, etc. with Respect to the Obligations		62
Section 8.04. Guarantee Absolute and Unconditional		62

Third Amended and Restated Credit Agreement

ii

	Page
Section 8.05. Reinstatement		63
ARTICLE 9
The Agents
ARTICLE 10
Miscellaneous
Section 10.01. Notices		65
Section 10.02. Waivers; Amendments		67
Section 10.03. Expenses; Indemnity; Damage Waiver		69
Section 10.04. Successors and Assigns		70
Section 10.05. Survival		74
Section 10.06. Counterparts; Integration; Effectiveness		74
Section 10.07. Severability		74
Section 10.08. Right of Setoff		74
Section 10.09. Governing Law; Jurisdiction; Consent to Service of Process		75
Section 10.10. Waiver Of Jury Trial		75
Section 10.11. Headings		76
Section 10.12. Confidentiality		76
Section 10.13. Security Agreement		77
Section 10.14. Amendment and Restatement and Continuing Effect		77
Section 10.15. USA Patriot Act		77
Section 10.16. Releases		78

SCHEDULES:

Schedule 1	Lender Commitments
Schedule 2	Letter of Credit Commitments
Schedule 3	Pricing Schedule
Schedule 4.05	Disclosure Update
Schedule 4.14	Environmental Matters
Schedule 4.16	Subsidiaries
Schedule 6.08	Existing Restrictive Agreements
Schedule 10.16(a)	Released Subsidiary Guarantors

EXHIBITS:

Exhibit A	Form of Assignment and Assumption
Exhibit B	Form of Borrowing Request
Exhibit C	Form of Note
Exhibit D	Form of Security Agreement
Exhibit E	Form of Subsidiary Guarantee Agreement
Exhibit F-1	Form of Opinion of Bracewell & Giuliani LLP, special New York counsel to the Company

Third Amended and Restated Credit Agreement

iii

Exhibit F-2	Form of Opinion of General Counsel or Associate General Counsel to the Company
Exhibit G	Acceptable Subordination Provisions

Third Amended and Restated Credit Agreement

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     THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of November 16, 2007, among EL PASO CORPORATION, a Delaware corporation (the “Company”), EL PASO NATURAL GAS COMPANY, a Delaware corporation (“EPNGC”), TENNESSEE GAS PIPELINE COMPANY, a Delaware corporation (“TGPC”), the several banks and other financial institutions from time to time parties to this Agreement (the “Lenders”), and JPMORGAN CHASE BANK, N.A. (“JPMCB”), as administrative agent (in such capacity, the “Administrative Agent”) and as collateral agent (in such capacity, the “Collateral Agent”).

W I T N E S S E T H :

     WHEREAS, the Company, Colorado Interstate Gas Company, a Delaware general partnership (“CIG”), EPNGC, TGPC, the Administrative Agent and certain of the Lenders are parties to the Amended and Restated Credit Agreement (as the same has been amended, supplemented and modified, the “Existing Facility”) dated as of July 31, 2006;

     WHEREAS, certain of the borrowers under the Existing Facility have requested that the Existing Facility be amended and restated in its entirety as more fully set forth herein;

     WHEREAS, the Lenders (who constitute the “Majority Lenders” as defined in the Existing Facility) and the Administrative Agent are willing to so amend and restate the Existing Facility, on the terms and subject to the conditions set forth in this Agreement;

     NOW, THEREFORE, in consideration of the premises and the mutual covenants contained herein, the parties hereto hereby agree that, on the Effective Date, the Existing Facility shall be amended and restated in its entirety as follows:

ARTICLE 1
Definitions

     Section 1.01. Defined Terms. As used in this Agreement, the following terms have the meanings specified below:

     “ABR”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

     “Acceptable Subordination Provisions” means subordination provisions substantially in the form of Exhibit G hereto or otherwise acceptable to the Administrative Agent.

     “Adjusted LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/100th of 1%) equal to (a) the LIBO Rate for such Interest Period multiplied by (b) the Statutory Reserve Rate.

     “Administrative Agent” has the meaning assigned to such term in the preamble hereof.

Third Amended and Restated Credit Agreement

1

     “Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

     “Affiliate” means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

     “Agents” means the Administrative Agent, the Collateral Agent, the Syndication Agent, the Co-Documentation Agents and the Lead Arrangers.

     “Agreement” means the Existing Facility, as amended and restated by this Third Amended and Restated Credit Agreement, as amended, supplemented or otherwise modified from time to time.

     “Alternate Base Rate” means, for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day and (b) the Federal Funds Effective Rate in effect on such day plus ¹/2 of 1%. Any change in the Alternate Base Rate due to a change in the Prime Rate or the Federal Funds Effective Rate shall be effective from and including the effective date of such change in the Prime Rate or the Federal Funds Effective Rate, respectively.

     “Alternate Program” means any program providing for the sale or other Disposition of trade or other receivables entered into by the Company or a Subsidiary of the Company on terms customary for such financing transactions.

     “Applicable Rate” means, for any day, with respect to commitment fees and any Loan, the applicable rate specified in the Pricing Schedule for such day.

     “Approved Fund” has the meaning assigned to such term in Section 10.04.

     “Assets” means, with respect to any Person, all or any part of its business, property, rights, interests and assets, both tangible and intangible (including Equity Interests in any Person), wherever situated.

     “Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by Section 10.04), and accepted by the Administrative Agent, in the form of Exhibit A or any other form approved by the Administrative Agent.

     “Availability Period” means the period from and including the Effective Date to but excluding the earlier of the Maturity Date and the date of termination of the Commitments.

     “Board of Directors” means with respect to any Person the Board of Directors or equivalent governing body of such Person as it may be constituted from time to time.

     “Board of Governors” means the Board of Governors of the Federal Reserve System of the United States of America.

     “Borrower” means the Company and each Pipeline Company Borrower, as applicable.

Third Amended and Restated Credit Agreement

2

     “Borrowing” means Loans of the same Type to the same Borrower, made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

     “Borrowing Request” means a request substantially in the form of Exhibit B by a Borrower for a Borrowing in accordance with Section 2.03.

     “Business Day” means any day that is not a Saturday, Sunday or other day on which commercial banks in New York City are authorized or required by law to remain closed; provided that, when used in connection with a Eurodollar Loan, the term “Business Day” shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

     “Business Entity” means a partnership, limited partnership, limited liability partnership, corporation (including a business trust), limited liability company, unlimited liability company, joint stock company, trust, unincorporated association, joint venture or other entity.

     “Capital Lease Obligations” of any Person means the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as a capital lease on a balance sheet of such Person under GAAP, and the amount of such obligations at any time shall be the capitalized amount thereof at such time determined in accordance with GAAP.

     “Cash Collateral Account” has the meaning assigned to such term in the Security Agreement.

     “Cash Collateralize” means, with respect to any LC Exposure at any date, to deposit in the Cash Collateral Account, in the name of the Collateral Agent and for the benefit of the applicable Lenders, an amount in cash equal to 105% of such LC Exposure as of such date plus any accrued and unpaid interest thereon.

     “Cash Equivalents” means (a) marketable direct obligations issued or unconditionally guaranteed by the United States Government or issued by any agency thereof and backed by the full faith and credit of the United States, in each case maturing within one year from the date of acquisition thereof; (b) marketable direct obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition, having the highest rating obtainable from either S&P or Moody’s; (c) certificates of deposit or banker’s acceptances maturing within one year from the date of acquisition thereof issued by (x) any Lender, or (y) any commercial bank organized under the laws of the United States of America or any state thereof or the District of Columbia having combined capital and surplus of not less than $500,000,000 (any such Lender or bank, a “Qualifying Lender”); (d) eurodollar time deposits having a maturity of less than one year purchased directly from any Lender (whether such deposit is with such Lender or any other Lender hereunder) or issued by any Qualifying Lender; (e) repurchase agreements and reverse repurchase agreements with a term of not more than 14 days with any Qualifying Lender relating to marketable direct obligations

Third Amended and Restated Credit Agreement

3

issued or unconditionally guaranteed by the United States; and (f) money market funds that (i) comply with the criteria set forth in SEC Rule 2a-7 under the Investment Company Act of 1940, (ii) invest solely in the assets described in clauses (a) through (e) above and (iii) have portfolio assets of at least $5,000,000,000.

     “Casualty Event” means an event that causes any property of a Credit Party or a Restricted Subsidiary to be damaged, destroyed or rendered unfit for normal use for any reason whatsoever.

     “CGMI” means Citigroup Global Markets Inc.

     “Change in Law” means (a) the adoption of any law, rule or regulation after the date of this Agreement, (b) any change in any law, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the date of this Agreement or (c) compliance by any Lender or any Issuing Bank (or, for purposes of Section 2.13(b), by any lending office of such Lender or by such Lender’s or such Issuing Bank’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement.

     “CIG” has the meaning assigned to such term in the recitals hereto.

     “Citibank” means Citibank, N.A.

     “CNA” means Citicorp North America, Inc.

     “CLO” has the meaning assigned to such term in Section 10.04.

     “Co-Documentation Agents” means ABN AMRO Bank N.V., Bank of America, N.A. and Deutsche Bank Securities Inc., in their capacity as co-documentation agents.

     “Code” means the Internal Revenue Code of 1986, as amended from time to time.

     “Collateral” has the meaning assigned to such term in the Security Agreement.

     “Collateral Account” has the meaning assigned to such term in the Security Agreement.

     “Collateral Agent” has the meaning assigned to such term in the Security Agreement.

     “Collateral Permitted Liens” means Liens (a) for Taxes or other obligations or requirements owing to or imposed by Governmental Authorities existing or having priority, as applicable, by operation of law, in each case either (i) not yet overdue or (ii) being contested in good faith by appropriate proceedings by the Company or any of its Subsidiaries, as the case may be, provided that adequate reserves with respect to such contested Taxes or other obligations or requirements are maintained on the books of the Company or the applicable Subsidiary of the Company, as the case may be, to the extent required by and in conformity with GAAP, and no enforcement action shall have been taken toward foreclosure on the Collateral pursuant to such Liens; (b) for judgments or orders that do not constitute an Event of Default

Third Amended and Restated Credit Agreement

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under paragraph (g) of Article 7; (c) created under the Security Documents; or (d) in existence on the Effective Date.

     “Commitment” means, with respect to each Lender, the commitment of such Lender to make Loans and to acquire participations in Letters of Credit hereunder, as such commitment may be (a) reduced from time to time pursuant to Section 2.07 and (b) reduced or increased from time to time pursuant to assignments by or to such Lender pursuant to Section 10.04. The initial amount of each Lender’s Commitment is set forth on Schedule 1 or in the Assignment and Assumption pursuant to which such Lender shall have assumed its Commitment, as applicable. The initial aggregate amount of the Commitments is $1,500,000,000.

     “Company” has the meaning assigned to such term in the preamble hereof.

     “Company Guaranteed Obligations” has the meaning assigned to such term in Section 8.01.

     “Condemnation” means the taking, by right of eminent domain, or a conveyance in lieu thereof, of property of a Credit Party or a Restricted Subsidiary.

     “Consolidated EBITDA” means, with respect to any Person for the applicable period, the sum (without duplication and determined as to such Person and its consolidated Subsidiaries on a consolidated basis) of (i) earnings before interest, taxes on income, depreciation and amortization (exclusive of extraordinary items and gains or losses on sales of assets outside the ordinary course of business), plus (ii) any nonrecurring noncash charges deducted in the determination of clause (i), plus or minus (iii) any charge or credit related to mark-to-market provisions for derivatives exposures plus (iv) the net cash received for any put options entered into for the purpose of mitigating the commodity price risk of the hydrocarbon production owned by the Company or any of its Subsidiaries, minus (v) cash payments during such period not deducted in the determination of clause (i) on account of charges or reserves taken in a prior period, minus (vi) income of entities accounted for on the equity method (including for this purpose MLP and its consolidated Subsidiaries), plus (vii) distributions of cash to such Person or any of its consolidated Subsidiaries by any entity accounted for on the equity method (including for this purpose MLP and its consolidated Subsidiaries), provided that the aggregate amount included pursuant to this clause (vii) during the term of this Agreement shall not exceed the aggregate amount excluded pursuant to clause (vi) in respect of periods commencing on or after January 1, 2006, plus (viii) for purposes of determining the Consolidated EBITDA of any Pipeline Company Borrower, all non-recurring losses or expenses deducted from the determination of earnings for such period to the extent such losses or expenses were funded from capital contributions from any holder of Equity Interests in such Person plus (ix) for any period, the amount of insurance proceeds received in such period or determined by such Person in such period to be receivable in a future period, but not to exceed the amount by which Consolidated EBITDA for such period or any prior period is reduced on account of the loss to which such insurance proceeds relate; plus (x) any charges taken during such period in connection with the payment, repayment, redemption, defeasance, early retirement or refinancing of any debt; provided that if such Person or any of its Subsidiaries shall have consummated any material acquisition or Disposition during such period, Consolidated EBITDA shall be determined on a pro forma basis as if such acquisition or Disposition had occurred on the first day of such period.

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     “Contingent Guaranty” has the meaning assigned to such term in the definition of the term “Guaranty” contained in this Section 1.01.

     “Control” means, at any time of determination, the possession, directly or indirectly, at such time, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. “Controlling” and “Controlled” have meanings correlative thereto.

     “Covered Asset” means any Asset owned by a Restricted Subsidiary, the Disposition of which is subject to subclause (i) or (ii) of Section 6.04(b).

     “Credit Contact” has the meaning assigned to such term in clause (ii)(D) of Section 10.04(b).

     “Credit Exposure” means, with respect to any Lender at any time, (i) the amount of such Lender’s Commitment, if the Commitments are still in existence, or (ii) if the Commitments have terminated or expired, the amount of its Outstandings.

     “Credit Party” means each Borrower and each Guarantor.

     “Credit Party Guarantee” means (a) the Subsidiary Guarantee Agreement and (b) the Guaranty of the Company set forth in Article 8 in favor of the Administrative Agent for the ratable benefit of the Lenders.

     “Credit Related Party” means each Borrower, each Guarantor and each Restricted Subsidiary.

     “Debt” means, as to any Person, all Indebtedness of such Person other than (a) any Project Financing of such Person, (b) in the case of the Company or a Subsidiary of the Company, any liabilities of the Company or such Subsidiary, as the case may be, under any Alternate Program, or any document executed by the Company or such Subsidiary, as the case may be, in connection therewith, (c) in the case of the Company or a Subsidiary of the Company, any obligations of the Company or a Subsidiary of the Company with respect to lease payments for the headquarters building of the Company located in Houston, Texas, (d) to the extent paid on or prior to the fifth Business Day after the due date therefor, the aggregate amount of all LC Disbursements that have not yet been reimbursed by or on behalf of such Person and all unpaid, non-contingent obligations of such Person to reimburse a bank or other Person in respect of amounts paid under a letter of credit or similar instrument, and (e) in the case of the Company, those items included as “securities of consolidated subsidiaries” (or analogous line item) as listed in the consolidated balance sheet of the Company as of December 31, 2006, and regardless of any change thereafter in accounting treatment thereof, so long as the terms and conditions of any financing associated with any such items referred to in this clause (e) (or successive extensions or refinancings thereof) are not amended so as to become more restrictive to the Company or its Subsidiaries than the terms and conditions of this Agreement.

     “Default” means any event or condition which constitutes an Event of Default or which upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

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     “Departing Lender” means (i) a Deposit Lender party to (and as defined in) the Existing Facility or (ii) a Revolving Lender party to the Existing Facility not listed in Schedule 1 hereto.

     “Disposition” means with respect to any asset or property of any Person, any sale, transfer or other disposition of ownership thereof by such Person, including any casualty with respect thereto or condemnation thereof or foreclosure thereon (but shall not include the granting or existence of a Lien permitted hereunder, or the granting or existence of any other encumbrance not prohibited hereunder, with respect thereto, or the issuance by such Person of indebtedness or equity). “Dispose” shall have a correlative meaning. For the avoidance of doubt, the issuance of (i) Equity Interests (x) by the Company or (y) by any of the Company’s Subsidiaries to the Company or any of its other Subsidiaries or (ii) Debt by the Company or any of its Subsidiaries, in each case that is not prohibited under the Credit Agreement shall not constitute a Disposition.

     “dollars” or “$” refers to lawful money of the United States of America.

     “Effective Date” has the meaning assigned such term in Section 3.01.

     “El Paso Tennessee” means El Paso Tennessee Pipeline Co., a Delaware corporation.

     “Environmental Laws” means all laws, rules, regulations, codes, ordinances, orders, decrees, judgments, injunctions, notices or binding agreements issued, promulgated or entered into by any Governmental Authority, regulating or imposing liability or standards of conduct concerning protection of the environment, preservation or reclamation of natural resources, the management, release or threatened release of any Hazardous Material or to health and safety matters.

     “Environmental Liability” means any liability, contingent or otherwise (including any liability for damages, costs of environmental remediation, fines, penalties or indemnities), of any Borrower or any Subsidiary of a Borrower resulting from or based upon (a) violation of any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the release or threatened release of any Hazardous Materials into the environment or (e) any contract, agreement or other consensual arrangement pursuant to which liability is assumed or imposed with respect to any of the foregoing.

     “EPNG Holding” means El Paso EPNG Investments, L.L.C., a Delaware limited liability company.

     “EPNGC” has the meaning assigned to such term in the preamble hereof.

     “Equity Interests” means (i) any capital stock, partnership, joint venture, member or limited liability or unlimited liability company interest, beneficial interest in a trust or similar entity, or other equity interest in another Person of whatever nature, and (ii) any warrants, options or other rights to acquire such stock or interests.

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     “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated and rulings issued from time to time thereunder.

     “ERISA Affiliate” means any Person who is a member of the Company’s controlled group within the meaning of Section 4001(a)(14)(A) of ERISA.

     “Eurodollar”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted LIBO Rate.

     “Event of Default” has the meaning assigned to such term in Article 7.

     “Excluded Taxes” means, with respect to the Administrative Agent, any Lender, any Issuing Bank or any other recipient of any payment to be made by or on account of any obligation of a Borrower hereunder, (a) income, franchise, branch profits or similar taxes imposed on (or measured by) its net income by the United States of America, or by the jurisdiction under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, and (b) in the case of a Foreign Lender (other than an assignee pursuant to a request by a Borrower under Section 2.17(b)), any withholding tax that is imposed on amounts payable to such Foreign Lender (i) at the time such Foreign Lender becomes a party to this Agreement (or designates a new lending office), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts from a Borrower with respect to such withholding tax pursuant to Section 2.15(a) or (ii) that is attributable to such Foreign Lender’s failure to comply with Section 2.15(e).

     “Exempted Guarantor” means El Paso Tennessee.

     “Existing Facility” has the meaning set forth in the recitals hereof.

     “Existing Letters of Credit” means the Deposit Letters of Credit and Revolving Letters of Credit (as each such term is defined under the Existing Facility) outstanding as of the Effective Date under the Existing Facility.

     “Federal Funds Effective Rate” means, for any day, the weighted average (rounded upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

     “Fee Letter” means the Letter Agreement dated as of October 18, 2007, among the Company, JPMorgan, JPMCB and CGMI.

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     “FERC” means the Federal Energy Regulatory Commission, or any agency or authority of the United States from time to time succeeding to its function.

     “FERC-Regulated Restricted Subsidiary” means any Restricted Subsidiary whose principal business purpose is the ownership of and operation of assets and properties, including without limitation natural gas pipelines, that are subject to regulations promulgated by FERC.

     “Final Payment Date” means the date on which all Loans, interest, fees and other amounts (other than obligations for taxes, costs, indemnifications, reimbursements and damages in respect of which no assertion of liability (whether oral or written) and no claim or demand for payment (whether oral or written) has been made (and, in the case of obligations for indemnification, no notice for indemnification has been issued by the indemnitee) at such time) payable by any Borrower hereunder or under any Note shall have been paid, all LC Disbursements shall have been reimbursed, no Lender shall have any Commitment (including any LC Commitment) hereunder and all Letters of Credit shall have expired or terminated.

     “Financial Officer” means the chief financial officer, principal accounting officer, treasurer or controller of the Company.

     “Financing Document” has the meaning assigned such term in the Security Agreement.

     “Foreign Lender” means any Lender that is organized under the laws of a jurisdiction other than the United States of America, any State thereof or the District of Columbia.

     “GAAP” means generally accepted accounting principles in the United States of America, as in effect from time to time.

     “Governmental Authority” means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government.

     “Guarantor” means each of the Company and the Subsidiary Guarantors.

     “Guaranty”, “Guaranteed” and “Guaranteeing” each means any act by which any Person assumes, guarantees, endorses or otherwise incurs direct or contingent liability in connection with, or agrees to purchase or otherwise acquire or otherwise assures a creditor against loss in respect of, any Debt or any Project Financing of any Person (other than any such liability existing on the Original Effective Date in respect of Debt or Project Financing of the Company or any of its consolidated Subsidiaries outstanding on the Original Effective Date or any extensions or renewals thereof that do not increase the liability of such Person)(excluding (a) any liability by endorsement of negotiable instruments for deposit or collection or similar transactions in the ordinary course of business, (b) any liability in connection with obligations of the Company or any of its consolidated Subsidiaries, including obligations under any conditional sales agreement, equipment trust financing or equipment lease, and (c) any such act in connection with a Project Financing that either (i) guarantees to the provider of such Project Financing or any other Person performance of the acquisition, improvement, installation, design,

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engineering, construction, development, completion, maintenance or operation of, or otherwise affects any such act in respect of, all or any portion of the project that is financed by such Project Financing or performance by a Project Financing Subsidiary of certain obligations to Persons other than the provider of such Project Financing, except during any period, and then only to the extent, that such guaranty is a guaranty of payment of such Project Financing (other than a guaranty of payment of the type referred to in subclause (ii) below) or (ii) is contingent upon, or the obligation to pay or perform under which is contingent upon, the occurrence of any event other than or in addition to the passage of time or any Project Financing becoming due (any such act referred to in this clause (c) being a “Contingent Guaranty”)).

     “Hazardous Materials” means all explosive or radioactive substances or wastes and all hazardous or toxic substances, wastes or other pollutants, including petroleum or petroleum distillates, asbestos or asbestos containing materials, polychlorinated biphenyls, radon gas, infectious or medical wastes and all other substances or wastes of any nature, in each case above to the extent regulated pursuant to any Environmental Law.

     “Hedging Agreement” means any interest rate swap agreement, interest rate cap agreement, interest rate collar agreement or interest rate insurance, foreign exchange contract, currency swap or option agreement, forward contract or any other similar agreement or arrangement designed to alter the risks of any Person arising from fluctuations in interest rates or currency values.

     “Indebtedness” of any Person means, without duplication (a) indebtedness of such Person for borrowed money, (b) obligations of such Person (other than any portion of any trade payable obligation of such Person) to pay the deferred purchase price of property or services, and (c) Capital Lease Obligations of such Person.

     “Indemnified Taxes” means Taxes other than Excluded Taxes.

     “Interest Election Request” means a request by a Borrower to convert or continue a Borrowing in accordance with Section 2.06.

     “Interest Payment Date” means (a) with respect to any ABR Loan, the last day of each March, June, September and December, and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.

     “Interest Period” means, with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing, or on the last day of the immediately preceding Interest Period therefor, as applicable, and ending one week or two weeks thereafter or on the numerically corresponding day in the calendar month that is one, two, three or six months thereafter, as the applicable Borrower may elect; provided, that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless, in the case of a one, two, three or six month Interest Period, such next succeeding Business Day would fall in the next calendar month, in which case such

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Interest Period shall end on the next preceding Business Day and (b) any one, two, three or six month Interest Period that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period.

     “ISP” means International Standby Practices, International Chamber of Commerce Publication No. 590 as the same may be amended or replaced from time to time.

     “Issuing Bank” means each of JPMCB and Citibank and, at any time and from time to time, up to three other Lenders that are designated in writing by the Company and that agree to issue one or more Letters of Credit hereunder, in each case in its capacity as the issuer of each Letter of Credit issued by it hereunder, and its successors in such capacity as provided in Section 2.04(i); provided that with respect to the Existing Letters of Credit, the Lender which issued the same shall be the initial Issuing Bank with respect thereto. Each Issuing Bank may, in its discretion, arrange for one or more Letters of Credit to be issued by Affiliates of such Issuing Bank acceptable to the Company, in which case the term “Issuing Bank” shall include any such Affiliate with respect to Letters of Credit issued by such Affiliate.

     “JPMCB” has the meaning assigned to such term in the preamble hereof.

     “JPMorgan” means J.P. Morgan Securities Inc.

     “LC Commitment” means, with respect to each Issuing Bank, the commitment of such Issuing Bank to issue Letters of Credit hereunder, as such commitment may be reduced or increased from time to time pursuant to a writing signed by the Company, such Issuing Bank and the Administrative Agent. The initial amount of each Issuing Bank’s LC Commitment is set forth on Schedule 2, or in the documentation pursuant to which such Issuing Bank shall have assumed its LC Commitment, as applicable.

     “LC Disbursement” means a payment made by an Issuing Bank pursuant to a Letter of Credit issued by such Issuing Bank.

     “LC Exposure” means, at any time, the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit at such time plus (b) the aggregate amount of all LC Disbursements in respect of Letters of Credit that have not yet been reimbursed by or on behalf of the Borrowers at such time, whether directly, through a Borrowing, or otherwise. The LC Exposure of any Lender at any time shall be its Percentage of the total LC Exposure at such time.

     “Lead Arrangers” means CGMI and JPMorgan, in their capacity as Joint Lead Arrangers and Joint Bookrunners.

     “Lenders” means the Persons listed on Schedule 1 and any other Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.

     “Letter of Credit” means any letter of credit issued by an Issuing Bank pursuant to this Agreement, including, after the Effective Date, all Existing Letters of Credit.

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     “LIBO Rate” means, with respect to any Interest Period, the rate per annum equal to the British Bankers Association LIBOR Rate (“BBA LIBOR”) from Reuters Reference LIBOR01 page (or any successor thereto or substitute therefor provided by Reuters providing rate quotations comparable to those currently provided on such pages, as designated by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason, then the “LIBO Rate” with respect to such Eurodollar Borrowing for such Interest Period shall be the rate at which dollar deposits of $5,000,000 and for a maturity comparable to such Interest Period are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period.

     “Lien” means any lien, security interest or other charge or encumbrance, or any assignment of the right to receive income, or any other type of preferential arrangement, in each case to secure any Indebtedness or any Guaranty of any Person.

     “Loan” means a loan made pursuant to Section 2.01.

     “Loan Documents” means, collectively, this Agreement, the Security Agreement, the Subsidiary Guarantee Agreement, the other Security Documents, any Letter of Credit, the Notes (as applicable), and any other agreement entered into in connection with the transactions contemplated by this Agreement.

     “Majority Lenders” means, at any time, Lenders having more than 50% of the aggregate Credit Exposures at such time.

     “Mandatory Asset Reduction Amount” means:

   (a) with respect to a Mandatory Asset Reduction Event described in clause (a) of the definition thereof, 100% of the Net Cash Proceeds thereof;

   (b) with respect to a Mandatory Asset Reduction Event described in clause (b) of the definition thereof, (i) if such Mandatory Asset Reduction Event does not occur concurrently with, or during the pendency of, an Event of Default, an amount equal to 80% of the Net Cash Proceeds thereof, or (ii) if such Mandatory Asset Reduction Event occurs concurrently with, or during the pendency of, an Event of Default, an amount equal to 100% of the Net Cash Proceeds thereof;

   (c) with respect to a Mandatory Asset Reduction Event described in clause (c) of the definition thereof, (i) if such Mandatory Asset Reduction Event does not occur concurrently with, or during the pendency of, an Event of Default, an amount equal to 80% of the cash dividend or other distribution described in clause (c) of the definition of “Mandatory Asset Reduction Event”, or (ii) if such Mandatory Asset Reduction Event occurs concurrently with, or during the pendency of, an Event of Default, an amount equal to 100% of such cash dividend or other distribution; and

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   (d) with respect to a Mandatory Asset Reduction Event described in clause (d) of the definition thereof, (i) if such Mandatory Asset Reduction Event does not occur concurrently with, or during the pendency of, an Event of Default, an amount equal to 80% of the portion of the Net Cash Proceeds thereof that is not either (x) paid to the applicable Restricted Subsidiary’s Parent (or to such Parent’s designee) as a cash dividend or distribution or (y) invested in Qualified Investments within the time period required pursuant to such clause (d), or (ii) if such Mandatory Asset Reduction Event occurs concurrently with, or during the pendency of, an Event of Default, an amount equal to 100% of the Net Cash Proceeds thereof.

     “Mandatory Asset Reduction Event” means:

     (a) the receipt by the Company or any Subsidiary Guarantor or its designee of Net Cash Proceeds from any Disposition of Collateral (other than a Disposition pursuant to Section 6.04(a)(iv));

     (b) with respect to any Restricted Subsidiary that is a Guarantor, the receipt by such Restricted Subsidiary or its designee of Net Cash Proceeds from any Disposition of any Covered Asset owned by such Restricted Subsidiary;

     (c) with respect to any Restricted Subsidiary that is not a Guarantor, the receipt by the Parent of such Restricted Subsidiary (or by such Parent’s designee) of a cash dividend or distribution of any amount received by such Restricted Subsidiary from any Disposition of any of its Covered Assets; and

     (d) with respect to any Pipeline Company Borrower or Subsidiary of a Pipeline Company Borrower (i) if an Event of Default or a Default which is not capable of being cured before becoming an Event of Default has occurred and is continuing at the time of any receipt by such Pipeline Company Borrower or Subsidiary of a Pipeline Company Borrower of Net Cash Proceeds from any Disposition of any of its Covered Assets, such receipt of Net Cash Proceeds, and (ii) if no Event of Default or Default which is not capable of being cured before becoming an Event of Default has occurred and is continuing at the time of any receipt by such Pipeline Company Borrower or Subsidiary of a Pipeline Company Borrower of Net Cash Proceeds from any Disposition of any of its Covered Assets, the failure of such Pipeline Company Borrower or Subsidiary of a Pipeline Company Borrower to, within 365 days of such receipt (or, in the case of clause (y) below, if a binding contract to make a Qualified Investment with respect to all or any portion of such Net Cash Proceeds has been entered into within such 365 day period, then as to the amount of such Qualified Investment, the failure to invest such amount in such Qualified Investment within 540 days of such receipt), take either of the following actions: (x) make a cash dividend or distribution to its Parent (or to such Parent’s designee) in an amount equal to such Net Cash Proceeds or (y) invest the portion of such Net Cash Proceeds that is not paid as a cash dividend or distribution under clause (x) above in one or more Qualified Investments; provided that, for the avoidance of doubt, if Net Cash Proceeds from a Disposition of a single Covered Asset are received by the applicable Pipeline Company Borrower or Subsidiary of a Pipeline Company Borrower in installments, the 365- and 540-day periods shall apply to each individual installment and commence for each installment on the date of receipt by the applicable

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Pipeline Company Borrower or Subsidiary of a Pipeline Company Borrower of such installment.

     “Margin Stock” means “margin stock” as defined in Regulation U of the Board of Governors, as in effect from time to time.

     “Material Adverse Effect” means a material adverse effect on (i) the business, assets, operations or financial condition of the Company and its consolidated Subsidiaries on a consolidated basis, (ii) the ability of the Credit Parties to perform their obligations under the Loan Documents or (iii) the validity or enforceability of the Loan Documents or the validity, perfection, priority or enforceability of the Liens created thereunder.

     “Material Credit Related Party” has the meaning set forth in paragraph (f) of Article 7.

     “Maturity Date” means November 19, 2012.

     “MLP” means El Paso Pipeline Partners, L.P., a Delaware limited partnership.

     “Moody’s” means Moody’s Investors Service, Inc.

     “Multiemployer Plan” means a “multiemployer plan” as defined in Section 4001(a)(3) of ERISA to which the Company or an ERISA Affiliate is making or accruing an obligation to make contributions, or has within any of the preceding five plan years made or accrued an obligation to make contributions and in respect of which the Company or an ERISA Affiliate has any liability (contingent or otherwise), such plan being maintained pursuant to one or more collective bargaining agreements.

     “Multiple Employer Plan” means a single employer plan, as defined in Section 4001(a)(15) of ERISA, which (a) is maintained for employees of the Company or an ERISA Affiliate and at least one Person other than the Company and its ERISA Affiliates, or (b) was so maintained and in respect of which the Company or an ERISA Affiliate could have liability under Section 4064 or 4069 of ERISA in the event such plan has been or were to be terminated.

     “Net Cash Proceeds” means, with respect to the Disposition of any asset or property, an amount equal to one hundred percent (100%) of the cash proceeds from such Disposition, net of any Taxes, indemnity obligations, purchase price adjustments and analogous items, related transaction fees (including legal fees), commissions and expenses and, if applicable, amounts required to satisfy Indebtedness or other obligations secured by Permitted Liens, or other Liens permitted under, or other encumbrances not prohibited by, this Agreement, on the related property or asset, and net of all costs reasonably estimated to be associated with terminating all Hedging Agreements, if any, entered into in connection with such related property or assets, which Hedging Agreements are not being sold as part of such Disposition, in each case paid or reasonably reserved against; provided that if Net Cash Proceeds from the Disposition of Covered Assets resulting from any Casualty Event or Condemnation either (x) do not exceed $1,000,000 for any single Casualty Event or any single Condemnation with respect to a Covered Asset, or (y) are both (i) equal to or less than $5,000,000 on an individual basis, and (ii) equal to or less than $10,000,000 in the aggregate during any fiscal year of the Company, then such Net Cash Proceeds shall not be considered Net Cash Proceeds for purposes of the application of Section

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2.07 and the definitions of “Mandatory Asset Reduction Amount” and “Mandatory Asset Reduction Event”; and provided, further, if Net Cash Proceeds from the Disposition of Covered Assets (other than Dispositions described in the preceding proviso) are both (a) equal to or less than $5,000,000 on an individual basis, and (b) equal to or less than $10,000,000 in the aggregate during any fiscal year of the Company, then such Net Cash Proceeds shall not be considered Net Cash Proceeds for purposes of the application of Section 2.07 and the definitions of “Mandatory Asset Reduction Amount” and “Mandatory Asset Reduction Event”.

     “Notes” means the promissory notes, if any, of any Borrower evidencing Loans under this Agreement in the form of Exhibit C.

     “Obligations” means, collectively, (a) all Indebtedness, liabilities under Guaranties and other obligations of each Borrower owing to the Administrative Agent, the Collateral Agent, each Issuing Bank and each Lender, of whatsoever nature and howsoever evidenced, due or to become due, now existing or hereafter arising, whether direct or indirect, absolute or contingent, which may arise under, out of, or in connection with this Agreement or the other Loan Documents, including the full and punctual payment when due of any unpaid principal of the Loans and LC Exposure, interest, fees, reimbursement obligations, guaranty obligations, penalties, indemnities, legal and other fees, charges and expenses, and amounts advanced by and expenses incurred in order to preserve any collateral or security interest, whether due by acceleration or otherwise, and (b) any and all obligations owed by each Borrower under a Secured Hedging Agreement, including any amounts payable in respect of an early termination under any Secured Hedging Agreement, and (c) any amendment, restatement or modification of any of the foregoing, including, with respect to each of clauses (a) through (c), interest accruing at any post-default rate and Post-Petition Interest.

     “Original Effective Date” means November 23, 2004.

     “Other Taxes” means any and all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement.

     “Outstandings” means, with respect to any Lender at any time, the aggregate outstanding amount of such Lender’s Loans and its LC Exposure at such time.

     “Parent” means, with respect to any Restricted Subsidiary, the holder of the Equity Interests of such Restricted Subsidiary, and any Person to whom such Equity Interests are assigned in accordance with the Loan Documents.

     “Participant” has the meaning set forth in Section 10.04.

     “Patriot Act” means the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)).

     “PBGC” means the Pension Benefit Guaranty Corporation established pursuant to Title IV of ERISA and any successor entity performing similar functions.

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     “Percentage” means, with respect to any Lender, the percentage of the total Credit Exposures represented by such Lender’s Credit Exposure.

     “Permitted Execution Actions” has the meaning set forth in paragraph (g) of Article 7.

     “Permitted Liens” means:

     (a) inchoate Liens and charges imposed by law and incidental to construction, maintenance, development or operation of properties, or the operation of business, in the ordinary course of business if payment of the obligation secured thereby is not yet overdue or if the validity or amount of which is being contested in good faith by the Company or any of its Subsidiaries;

     (b) Liens for Taxes, assessments, obligations under workers’ compensation or other social security legislation or other requirements, charges or levies of any Governmental Authority, in each case not yet overdue, or which are being contested in good faith by appropriate proceedings;

     (c) Liens reserved in any oil, gas or other mineral lease entered into in the ordinary course of business for rent, royalty or delay rental under such lease and for compliance with the terms of such lease;

     (d) easements, servitudes, rights-of-way and other rights, exceptions, reservations, conditions, limitations, covenants and other restrictions that do not materially interfere with the operation, value or use of the properties affected thereby;

     (e) conventional provisions contained in any contracts or agreements affecting properties under which the Company or any of its Subsidiaries is required immediately before the expiration, termination or abandonment of a particular property to reassign to such Person’s predecessor in title all or a portion of such Person’s rights, titles and interests in and to all or portion of such property;

     (f) pledges and deposits to secure the performance of bids, tenders, trade or government contracts (other than for repayment of borrowed money), leases, licenses, statutory obligations, surety bonds, performance bonds, completion bonds and other obligations of a like kind incurred in the ordinary course of business;

     (g) any Lien reserved in a grant or conveyance in the nature of a farm-out or conditional assignment to the Company or any of its Subsidiaries entered into in the ordinary course of business on reasonable terms to secure undertakings of the Company or any such Subsidiary in such grant or conveyance;

     (h) any Lien consisting of (i) landlord’s liens under leases to which the Company or any of its Subsidiaries is a party or other Liens on leased property reserved in leases thereof for rent or for compliance with the terms of such leases, (ii) rights reserved to or vested in any municipality or governmental, statutory or public authority to control or regulate any property of the Company or any of its Subsidiaries, or to use such property in any manner which does not materially impair the use of such property for the purposes for which it is held by the Company

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or any such Subsidiary, (iii) obligations or duties to any municipality or public authority with respect to any franchise, grant, license, lease or permit and the rights reserved or vested in any governmental authority or public utility to terminate any such franchise, grant, license, lease or permit or to condemn or expropriate any property, and (iv) zoning laws and ordinances and municipal regulations;

     (i) the creation of interests in property of the character commonly referred to as a “royalty interest” or “overriding royalty interest”, production payments, farmouts, leases, subleases, rights of way and other easements, participations, joint venture, joint operating, unitization, pooling and communitization agreements, or other similar transactions in the ordinary course of business; and

     (j) any judgment lien in respect of any judgment or order that does not constitute an Event of Default under paragraph (g) of Article 7.

     “Person” means an individual, a Business Entity, or a country or any political subdivision thereof or any agency or instrumentality of such country or subdivision.

     “Pipeline Company Borrower” means each of EPNGC and TGPC.

     “Plan” means a Single Employer Plan or a Multiple Employer Plan.

     “Pledged Company” has the meaning assigned to such term in the Security Agreement.

     “Post-Petition Interest” means interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding.

     “Pricing Schedule” means Schedule 3 attached hereto.

     “Prime Rate” means the rate of interest per annum publicly announced from time to time by JPMCB as its prime rate in effect at its principal office in New York City; each change in the Prime Rate shall be effective from and including the date such change is publicly announced as being effective.

     “Project Financing” means any Indebtedness (a) incurred to finance or refinance the acquisition, improvement, installation, design, engineering, construction, development, completion, maintenance or operation of, or otherwise in respect of, all or any portion of any project, or any asset related thereto (including, with respect to transactions in connection with the power and gas contract restructuring business of the Company) and any Guaranty with respect thereto, other than any portion of such Indebtedness or Guaranty permitting or providing for recourse against the Company or any of its Subsidiaries, which recourse is other than (i) recourse to the Equity Interests in, Indebtedness or other obligations of, or assets of, one or more Project Financing Subsidiaries, and (ii) such recourse as exists under any Contingent Guaranty or (b) of any Project Financing Subsidiary, or any Guaranty with respect thereto, that is secured solely by, or recourse for which is limited solely to, the Equity Interests in, Indebtedness or other obligations of, or assets of, one or more Project Financing Subsidiaries.

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     “Project Financing Subsidiary” means any Subsidiary of the Company whose principal purpose is to incur Project Financing, or to become a direct or indirect partner, member or other equity participant or owner in a Business Entity so created, and substantially all the assets of which Subsidiary or Business Entity are limited to (a) those assets being financed (or to be financed), or the operation of which is being financed (or to be financed), in whole or in part by a Project Financing, (b) power contracts, gas contracts, administrative or other related service agreements and swap agreements related to gas or power, or (c) Equity Interests in, or Indebtedness or other obligations of, one or more other such Subsidiaries or Business Entities or to Indebtedness or other obligations of the Company or its Subsidiaries or other Persons. For purposes of this definition, “swap agreement” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions.

     “Qualified Investments” means:

     (a) for any FERC-Regulated Restricted Subsidiary, (i) expenditures that would constitute maintenance or expansion capital expenditures or other investments or reinvestments to repair, construct, purchase, or otherwise acquire Assets that would, following such repair, construction, purchase, or other acquisition, become eligible for rate coverage under regulations promulgated by FERC, (ii) other than repayments of such Indebtedness during the pendency of an Event of Default, repayments of Indebtedness incurred by such Restricted Subsidiary for the purpose of financing expenditures or other investments or reinvestments described in clause (a)(i) above, (iii) other than such payments (or retention of funds) during the pendency of an Event of Default, payments (or retention of funds) to reimburse such Restricted Subsidiary for amounts paid from such Restricted Subsidiary’s operating cash flow within the previous 365 days for expenditures or other investments or reinvestments of the type described in clause (a)(i) or (a)(ii) above (if, in the case of clause (a)(ii), a repayment of Indebtedness described in such clause was made during the pendency of an Event of Default that was subsequently cured and no other Event of Default is then pending), to the extent such expenditures or such other investments or reinvestments have not previously been reimbursed to such Restricted Subsidiary pursuant to this clause (a)(iii), or (iv) a loan subject to Acceptable Subordination Provisions, to any other FERC-Regulated Restricted Subsidiary, the proceeds of which shall be used by such FERC-Regulated Restricted Subsidiary for any of the expenditures or other investments or reinvestments of the type described in clauses (a)(i), (a)(ii) or (a)(iii) above; and

     (b) for any Unregulated Restricted Subsidiary, (i) maintenance or expansion capital expenditures or other investments or reinvestments in Assets that are useful to the business conducted by such Restricted Subsidiary, (ii) other than repayments of such Indebtedness during the pendency of an Event of Default, repayments of Indebtedness incurred by such Restricted Subsidiary for the purpose of financing expenditures or other investments or reinvestments described in clause (b)(i) above, and (iii) other than such payments (or retention of funds) during the pendency of an Event of Default, payments (or retention of funds) to reimburse such Restricted Subsidiary for amounts paid from

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such Restricted Subsidiary’s operating cash flow within the previous 365 days for expenditures or other investments or reinvestments of the type described in clause (b)(i) or (b)(ii) above (if, in the case of clause (b)(ii), a repayment of Indebtedness described in such clause was made during the pendency of an Event of Default that was subsequently cured and no other Event of Default is then pending), to the extent such expenditures or such other investments or reinvestments have not previously been reimbursed to such Restricted Subsidiary pursuant to this clause (b)(iii).

Notwithstanding the foregoing, an investment in or acquisition of any equity ownership in any other entity shall constitute a Qualified Investment if an acquisition of the principal operating assets of such entity would constitute a Qualified Investment.

     “Qualified Investments Account” has the meaning assigned to such term in the Security Agreement.

     “Reference Indenture” means the Indenture dated as of March 5, 2003 between Southern Natural Gas Company, a Delaware Corporation, and The Bank of New York, as trustee, governing Southern Natural Gas Company’s 8-7/8% Notes due 2010, as in effect on the Effective Date; provided that for purposes of this Agreement, the percentage set forth in Section 3.05(b)(5) of the Reference Indenture shall be deemed to be 5%.

     “Register” has the meaning set forth in Section 10.04.

     “Related Parties” means, with respect to any specified Person, such Person’s Affiliates and the respective directors, officers, employees, agents, advisors and trustees of such Person and such Person’s Affiliates.

     “Released Parties” has the meaning set forth in Section 10.16(a).

     “Restricted Subsidiaries” means, collectively, each Pipeline Company Borrower and each of their respective consolidated Subsidiaries (other than Project Financing Subsidiaries) and each Subsidiary Guarantor (other than the Exempted Guarantor); provided, however, that any such Person shall cease to be a “Restricted Subsidiary” hereunder immediately upon any Disposition of the Equity Interests in such Person permitted by Section 6.04 that results in such Person no longer being a direct or indirect Subsidiary of the Company.

     “S&P” means Standard & Poors’ Ratings Group.

     “SEC” means the United States Securities and Exchange Commission.

     “Secured Hedging Agreement” has the meaning assigned to such term in the Security Agreement.

     “Secured Obligations” has the meaning assigned to such term in the Security Agreement.

     “Secured Parties” has the meaning assigned to such term in the Security Agreement.

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     “Security Agreement” means the Third Amended and Restated Security Agreement substantially in the form of Exhibit D hereto, dated as of the Effective Date, executed and delivered by the Collateral Agent, each Credit Party and the Depository Bank (as defined therein).

     “Security Documents” means, collectively, the Subsidiary Guarantee Agreement, the Security Agreement and all other security documents hereafter delivered by a Credit Party to the Administrative Agent or the Collateral Agent granting or purporting to grant a Lien on any property or Asset of any Credit Party to secure the Secured Obligations.

     “Single Employer Plan” means a single employer plan, as defined in Section 4001(a)(15) of ERISA, that (a) is maintained for employees of the Company or an ERISA Affiliate and no Person other than the Company and its ERISA Affiliates or (b) was so maintained and in respect of which the Company or an ERISA Affiliate could have liability under Section 4069 of ERISA in the event such plan has been or were to be terminated.

     “Specified Indenture Debt” means any Debt issued pursuant to an indenture qualified under the Trust Indenture Act of 1939, as amended, and the principal amount of which, at the time of determination, exceeds $50,000,000.

     “Statutory Reserve Rate” means a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board of Governors to which the Administrative Agent is subject for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board of Governors). Such reserve percentages shall include those imposed pursuant to such Regulation D. Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation. The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

     “Subsidiary” means, as to any Person (the “parent”) at any date, any Business Entity the accounts of which are, or are required to be, consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other Business Entity of which the shares of stock or other Equity Interests having ordinary voting power (other than stock or such other Equity Interests having such power only by reason of the happening of a contingency) to elect a majority of the board of directors or other managers of such Business Entity are at the time owned, directly or indirectly, through one or more Subsidiaries, or both, by such Person.

     “Subsidiary Guarantee Agreement” means the Third Amended and Restated Subsidiary Guarantee Agreement substantially in the form of Exhibit E hereto, dated as of the Effective Date, executed and delivered by each Subsidiary Guarantor in favor of the Collateral Agent for the ratable benefit of the Secured Parties.

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     “Subsidiary Guarantor” means, subject to the release of any of the following as Subsidiary Guarantor in accordance with the terms of this Agreement, each of El Paso Tennessee, EPNG Holding and TGPC Holding.

     “Syndication Agent” means CNA, in its capacity as syndication agent.

     “Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, charges or withholdings imposed by any Governmental Authority.

     “Termination Event” means (a) a “reportable event,” as such term is described in Section 4043 of ERISA (other than a “reportable event” not subject to the provision for 30-day notice to the PBGC under PBGC Reg. § 4043), or an event described in Section 4062(e) of ERISA, or (b) the withdrawal of the Company or any ERISA Affiliate from a Multiple Employer Plan during a plan year in which it was a “substantial employer,” as such term is defined in Section 4001(a)(2) of ERISA or the incurrence of liability by the Company or any ERISA Affiliate under Section 4064 of ERISA upon the termination of a Multiple Employer Plan, or (c) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under Section 4041 of ERISA, or (d) the institution of proceedings to terminate a Plan by the PBGC under Section 4042 of ERISA, or (e) the conditions set forth in Section 302(f)(1)(A) and (B) of ERISA to the creation of a lien upon property or rights to property of the Company or any ERISA Affiliate for failure to make a required payment to a Plan are satisfied, or (f) the adoption of an amendment to a Plan requiring the provision of security to such Plan, pursuant to Section 307 of ERISA, or (g) the occurrence of any other event or the existence of any other condition which would reasonably be expected to result in the termination of, or the appointment of a trustee to administer, any Plan under Section 4042 of ERISA.

     “TGPC” has the meaning assigned to such term in the preamble hereof.

     “TGPC Holding” means El Paso TGPC Investments, L.L.C., a Delaware limited liability company.

     “Transaction Liens” means the Liens on Collateral granted by the Credit Parties under the Security Documents.

     “Transactions” means the execution, delivery and performance by the Borrowers of this Agreement, the borrowing of Loans, the use of the proceeds thereof and the issuance of Letters of Credit hereunder.

     “Type”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Adjusted LIBO Rate or the Alternate Base Rate.

     “Uniform Customs” means the Uniform Customs and Practice for Documentary Credits (2007 Revision), International Chamber of Commerce Publication No. 600, as the same may be amended from time to time.

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     “Unregulated Restricted Subsidiary” means any Restricted Subsidiary whose principal business purpose is the ownership and operation of assets and properties that are not subject to regulations promulgated by FERC.

     “Withdrawal Liability” has the meaning given such term under Part 1 of Subtitle E of Title IV of ERISA.

     Section 1.02. Terms Generally. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (c) any reference herein to any applicable law means such applicable law as amended, modified, codified, replaced, or reenacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder and reference to any section or other provision of any applicable law means that section or provision of such applicable law from time to time in effect and any amendment, modification, codification, replacement, or reenactment of such section or other provision, (d) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement and (f) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, Equity Interests, accounts and contract rights.

     Section 1.03. Accounting Terms; GAAP. (a) Except as otherwise expressly provided herein, all terms of an accounting or financial nature shall be construed in accordance with GAAP, as in effect from time to time; provided that, if the Company notifies the Administrative Agent that the Company requests an amendment to any provision hereof to eliminate the effect of any change occurring after the date hereof in GAAP or in the application thereof on the operation of or calculation of compliance with such provision (or if the Administrative Agent notifies the Company that the Majority Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith.

     (b) For purposes of Section 6.02, the amount of Consolidated EBITDA, Debt and Guaranties shall be calculated assuming that MLP and its consolidated Subsidiaries are accounted for on the equity method (notwithstanding that they would be consolidated Subsidiaries of the Company under GAAP).

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ARTICLE 2
The Credits

     Section 2.01. Commitments. Subject to the terms and conditions set forth herein, each Lender agrees to make Loans to any Borrower from time to time during the Availability Period in an aggregate principal amount that will not result in any Lender’s Outstandings exceeding such Lender’s Commitment. Within the foregoing limits and subject to the terms and conditions set forth herein, each Borrower may borrow, prepay and reborrow Loans.

     Section 2.02. Loans and Borrowings. (a) Each Loan shall be made as part of a Borrowing consisting of Loans of the same Type made by the Lenders ratably in accordance with their respective Commitments, as the applicable Borrower may request (subject to Section 2.12) in accordance herewith. The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments of the Lenders are several and no Lender shall be responsible for any other Lender’s failure to make Loans as required.

     (b) Subject to Section 2.12, each Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Company, on its own behalf or on behalf of the applicable Pipeline Company Borrower, may request in accordance herewith. Each Lender at its option may make or hold any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make or hold such Loan; provided that any exercise of such option shall not affect the obligation of a Borrower to repay such Loan in accordance with the terms of this Agreement.

     (c) At the commencement of each Interest Period for any Eurodollar Borrowing, such Borrowing shall be in an aggregate amount that is an integral multiple of $1,000,000 and not less than $20,000,000. At the time that each ABR Borrowing is made, such Borrowing shall be in an aggregate amount that is an integral multiple of $1,000,000 and not less than $5,000,000; provided that an ABR Borrowing may be in an aggregate amount that is equal to the entire unused balance of the total Commitments or that is required to finance the reimbursement of an LC Disbursement as contemplated by Section 2.04(e). Borrowings of more than one Type may be outstanding at the same time; provided that there shall not at any time be more than a total of sixteen Eurodollar Borrowings outstanding. Within the limits of each Lender’s Commitment, any Borrower may make more than one Borrowing on any Business Day.

     (d) Notwithstanding any other provision of this Agreement, a Borrower shall not be entitled to request, or to elect to convert a Borrowing to or continue a Borrowing as, a Eurodollar Borrowing if the Interest Period requested with respect thereto would end after the Maturity Date.

     Section 2.03. Requests for Borrowings. To request a Borrowing, the Company, on its own behalf or on behalf of the applicable Pipeline Company Borrower, shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than 12:00 noon, New York City time, three Business Days before the date of the proposed Borrowing, or (b) in the case of an ABR Borrowing, not later than 10:00 a.m., New York City time, on the date of the proposed Borrowing. Each such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative

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Agent of a written Borrowing Request in substantially the form of Exhibit B and signed by the Company. Each such telephonic and written Borrowing Request shall specify the following information in compliance with Section 2.02:

     (i) the Borrower;

     (ii) the aggregate amount of such Borrowing;

     (iii) the date of such Borrowing, which shall be a Business Day;

     (iv) whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing;

     (v) in the case of any Eurodollar Borrowing, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term “Interest Period”; and

     (vi) the location and number of the Borrower’s account to which funds are to be disbursed.

If no election as to the Type of Borrowing is specified, then the requested Borrowing shall be an ABR Borrowing. If no Interest Period is specified with respect to any requested Eurodollar Borrowing, then the applicable Borrower shall be deemed to have selected an Interest Period of one month’s duration. Promptly following receipt of a Borrowing Request in accordance with this Section 2.03, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part of the requested Borrowing.

     Section 2.04. Letters of Credit.

     (a) General. • Subject to the terms and conditions set forth herein, upon request by the Company, on its own behalf or on behalf of the applicable Pipeline Company Borrower, each Issuing Bank agrees to issue Letters of Credit in any stated face amount specified by the Company in the applicable request with any Borrower as the reimbursement obligor in respect of drawings thereunder and for the account of the Borrowers, or any one or more of them, or any direct or indirect Subsidiary or Affiliate thereof, each Letter of Credit in a form reasonably acceptable to the Administrative Agent and the applicable Issuing Bank, at any time and from time to time during the Availability Period. In the event of any inconsistency between the terms and conditions of this Agreement and the terms and conditions of any form of letter of credit application, reimbursement agreement or other agreement submitted by a Borrower to, or entered into by a Borrower with, an Issuing Bank relating to any Letter of Credit issued thereby, the terms and conditions of this Agreement shall control.

     (i) Existing Letters of Credit. On the Effective Date, without further action by any party hereto, each Issuing Bank that has issued an Existing Letter of Credit shall be deemed to have granted to each Lender, and each Lender shall be deemed to have acquired from such Issuing Bank, a participation in each such Existing Letter of Credit equal to such Lender’s Percentage of (A) the aggregate amount available to be drawn under such Existing Letter of Credit and (B) the aggregate amount of any outstanding

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reimbursement obligations in respect thereof. With respect to each Existing Letter of Credit (i) any participation therein granted pursuant to the terms of the Existing Facility shall be automatically canceled on the Effective Date and (ii) if the relevant Issuing Bank has heretofore granted a participation therein to any bank or financial institution otherwise than pursuant to the terms of the Existing Facility, such Issuing Bank shall procure the termination of such participation on or prior to the Effective Date. On and after the Effective Date, each such Existing Letter of Credit shall be a Letter of Credit issued hereunder.

     (b) Notice of Issuance, Amendment, Renewal, Extension; Certain Conditions. To request the issuance of a Letter of Credit (or the amendment, renewal or extension of an outstanding Letter of Credit), the Company, on its own behalf, or on behalf of the applicable Pipeline Company Borrower as obligor, shall hand deliver or telecopy (or transmit by electronic communication, if arrangements for doing so have been approved by the applicable Issuing Bank) to the Issuing Bank requested to issue such Letter of Credit and the Administrative Agent (reasonably in advance of the requested date of issuance, amendment, renewal or extension) a notice (requesting the issuance of a Letter of Credit, or identifying the Letter of Credit to be amended, renewed or extended, and specifying the date of issuance, amendment, renewal or extension (which shall be a Business Day), the date on which such Letter of Credit is to expire (which shall comply with paragraph (c) of this Section 2.04), the amount of such Letter of Credit, the name and address of the beneficiary thereof and such other information (including the applicable Borrower as obligor for reimbursement obligations thereunder and the account party therefor if different) as shall be necessary to prepare, amend, renew or extend such Letter of Credit. If such notice is received by the applicable Issuing Bank (i) prior to 12:00 noon, New York City time, on any Business Day, the applicable Issuing Bank shall use its best efforts to issue the requested Letter of Credit on such date or (ii) after 12:00 noon, New York City time, on any Business Day, the applicable Issuing Bank shall issue the requested Letter of Credit by the end of the following Business Day, in each case provided that all necessary information is in order. If requested by the applicable Issuing Bank in connection with any request for a Letter of Credit, the applicable obligor Borrower in respect thereof also shall submit a letter of credit application on such Issuing Bank’s standard form. A Letter of Credit shall be issued, amended, renewed or extended only if (and upon issuance, amendment, renewal or extension of each Letter of Credit the Company shall be deemed to represent and warrant that), after giving effect to such issuance, amendment, renewal or extension (i) the total LC Exposure with respect to all Letters of Credit issued by each Issuing Bank shall not exceed such Issuing Bank’s LC Commitment and (ii) the total Outstandings shall not exceed the total Commitments. Each Issuing Bank shall have sole discretion as to any amendment, renewal or extension of the Letters of Credit issued by it, subject to the other terms and provisions of this Agreement.

     (c) Expiration Date. Each Letter of Credit shall expire at or prior to the close of business on the earlier of (i) the date three years after the date of the issuance of such Letter of Credit (or, in the case of any renewal or extension thereof, three years after such renewal or extension) and (ii) the date that is five Business Days prior to the Maturity Date; provided that (x) any Letter of Credit may provide for the extension or renewal thereof and may be renewed or extended upon the request of the Company, on its own behalf or on behalf of a Pipeline Company Borrower, in accordance with the terms thereof for additional periods of a duration requested by the Company, on its own behalf or on behalf of a Pipeline Company Borrower

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(which shall in no event extend beyond the date referred to in clause (ii) above) and (y) with the consent of the relevant Issuing Bank and the Administrative Agent, Letters of Credit with a term longer than three years shall be permitted (which shall in no event extend beyond the date referred to in clause (ii) above).

     (d) Participations. By the issuance of a Letter of Credit (or an amendment to a Letter of Credit increasing the amount thereof) and without any further action on the part of the applicable Issuing Bank or the applicable Lenders, such Issuing Bank hereby grants to each Lender having a Commitment, and each Lender hereby acquires from such Issuing Bank, a participation in such Letter of Credit equal to such Lender’s Percentage of the aggregate amount available to be drawn under such Letter of Credit. In consideration and in furtherance of the foregoing, each such Lender hereby absolutely and unconditionally agrees to pay to the Administrative Agent, for the account of the applicable Issuing Bank, such Lender’s Percentage of each LC Disbursement made by such Issuing Bank and not reimbursed by the applicable obligor Borrower or any Guarantor on the date due as provided in paragraph (e) of this Section 2.04, or of any reimbursement payment required to be refunded to any Borrower for any reason. Each Lender acknowledges and agrees that its obligation to acquire participations pursuant to this paragraph in respect of Letters of Credit is absolute and unconditional and shall not be affected by any circumstance whatsoever, including any amendment, renewal or extension of any Letter of Credit or the occurrence and continuance of a Default or reduction or termination of the Commitments, and that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever.

     (e) Reimbursement. If an Issuing Bank shall make any LC Disbursement in respect of a Letter of Credit issued by it, the applicable obligor Borrower shall reimburse such LC Disbursement by paying to the Administrative Agent an amount equal to such LC Disbursement not later than 12:00 noon, New York City time, on the date that such LC Disbursement is made, if such Borrower shall have received notice of such LC Disbursement prior to 10:00 a.m., New York City time, on such date, or, if such notice has not been received by such Borrower prior to such time on such date, then not later than 12:00 noon, New York City time, on (i) the Business Day that such Borrower receives such notice, if such notice is received prior to 10:00 a.m., New York City time, on the day of receipt, or (ii) the Business Day immediately following the day that such Borrower receives such notice, if such notice is not received prior to such time on the day of receipt; provided that, to the extent financed with proceeds of an ABR Borrowing as contemplated by the following sentence, such Borrower’s obligation to make such payment shall be discharged and replaced by the resulting ABR Borrowing. Unless the Company, on its own behalf or on behalf of the applicable Pipeline Company Borrower, shall have notified the Administrative Agent of such Borrower’s intention to reimburse the Administrative Agent directly for such LC Disbursement, the Administrative Agent shall notify each Lender of the applicable LC Disbursement, the payment then due from such Borrower in respect thereof and such Lender’s Percentage thereof. Promptly following receipt of such notice, each applicable Lender shall make an ABR Loan in the amount of its Percentage of the payment then due from the applicable Borrower, in the same manner as provided in Section 2.05 with respect to Loans made by such Lender (and Section 2.05 shall apply, mutatis mutandis, to the payment obligations of the applicable Lenders), and the Administrative Agent shall promptly pay to the applicable Issuing Bank the amounts so received by it from such Lenders. Promptly following receipt by the Administrative Agent of any payment from a Borrower pursuant to this paragraph, the

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Administrative Agent shall distribute such payment to the applicable Issuing Bank or, to the extent that Lenders have made payments pursuant to this paragraph to reimburse such Issuing Bank, then to the Lenders and such Issuing Bank as their interests may appear.

     (f) Obligations Absolute. Each Borrower’s obligation to reimburse LC Disbursements as provided in paragraph (e) of this Section 2.04 shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement under any and all circumstances whatsoever and irrespective of (i) any lack of validity or enforceability of any Letter of Credit or this Agreement, or any term or provision therein, (ii) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect, (iii) payment by the applicable Issuing Bank under a Letter of Credit against presentation of a draft or other document that does not comply with the terms of such Letter of Credit, or (iv) any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section 2.04, constitute a legal or equitable discharge of or defense to, or provide a right of setoff against, a Borrower’s obligations hereunder. Neither the Administrative Agent, the Lenders nor any Issuing Bank, nor any of their Related Parties, shall have any liability or responsibility by reason of or in connection with the issuance or transfer of any Letter of Credit or any payment or failure to make any payment thereunder (irrespective of any of the circumstances referred to in the preceding sentence), or any error, omission, interruption, loss or delay in transmission or delivery of any draft, notice or other communication under or relating to any Letter of Credit (including any document required to make a drawing thereunder), any error in interpretation of technical terms or any consequence arising from causes beyond the control of such Issuing Bank; provided that the foregoing shall not be construed to excuse such Issuing Bank from liability to a Borrower to the extent of any direct damages (as opposed to consequential damages, claims in respect of which are hereby waived by the applicable Borrower to the extent permitted by applicable law) suffered by a Borrower that are caused by such Issuing Bank’s failure to comply with the requirements of the ISP or the Uniform Customs, as applicable, when determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof. In furtherance of the foregoing, the parties agree that, with respect to documents presented which appear on their face to be in compliance with the terms of a Letter of Credit, the Issuing Bank that issued such Letter of Credit may, to the extent it is permitted to do so under the ISP or Uniform Customs, as applicable, and otherwise in its sole discretion, either accept and make payment upon such documents without responsibility for further investigation, regardless of any notice or information to the contrary, or refuse to accept and make payment upon such documents if such documents are not in strict compliance with the terms of such Letter of Credit (unless the applicable obligor Borrower shall consent to payment thereon notwithstanding such lack of strict compliance).

     (g) Disbursement Procedures. Each Issuing Bank shall, promptly following its receipt thereof, examine all documents purporting to represent a demand for payment under a Letter of Credit issued by it. Such Issuing Bank shall promptly notify the Administrative Agent and the Borrower by telephone (confirmed by telecopy) of the date and the amount of such demand for payment and whether such Issuing Bank has made or will make an LC Disbursement thereunder; provided that any failure to give or delay in giving such notice shall not relieve such Borrower of its obligation to reimburse such Issuing Bank and the Lenders with respect to any such LC Disbursement.

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     (h) Interim Interest. If any Issuing Bank shall make any LC Disbursement, then, unless the applicable obligor Borrower, or a Guarantor on its behalf, shall reimburse such LC Disbursement in full on the date such LC Disbursement is made (including reimbursement by way of ABR Loans made as contemplated by paragraph (e) of this Section 2.04), the unpaid amount thereof shall bear interest, for each day from and including the date such LC Disbursement is made to but excluding the date that such Borrower reimburses such LC Disbursement, at the rate per annum then applicable to ABR Loans; provided that, if such applicable obligor Borrower, or a Guarantor on its behalf, fails to reimburse such LC Disbursement when due pursuant to paragraph (e) of this Section 2.04, then Section 2.11(c) shall apply. Interest accrued pursuant to this paragraph shall be for the account of the applicable Issuing Bank, except that interest accrued on and after the date of payment by any Lender pursuant to paragraph (e) of this Section 2.04 to reimburse such Issuing Bank shall be for the account of such Lender to the extent of such payment.

     (i) Replacement of an Issuing Bank. Any Issuing Bank may be replaced at any time by written agreement among the Company, the Administrative Agent, the replaced Issuing Bank and the successor Issuing Bank. The Administrative Agent shall notify the Lenders of any such replacement of an Issuing Bank. At the time any such replacement shall become effective, the applicable obligor Borrower shall pay all unpaid fees accrued for the account of the replaced Issuing Bank pursuant to Section 2.10(b). From and after the effective date of any such replacement, (i) the successor Issuing Bank shall have all the rights and obligations of the replaced Issuing Bank under this Agreement with respect to Letters of Credit issued by it thereafter and (ii) references herein to the term “Issuing Bank” shall be deemed, when applicable, to refer to such successor or, when applicable, to any previous Issuing Bank, or to such successor and all previous Issuing Banks, as the context shall require. After the replacement of an Issuing Bank hereunder, the replaced Issuing Bank shall remain a party hereto and shall continue to have all the rights and obligations of an Issuing Bank under this Agreement with respect to Letters of Credit issued by it prior to such replacement, but shall not be required to issue additional Letters of Credit.

     (j) Cash Collateralization. Notwithstanding any provisions of the Security Agreement relating to the Cash Collateralization of LC Exposure, if any Event of Default shall occur and be continuing, on the Business Day that any Borrower receives notice from the Administrative Agent or the Majority Lenders demanding the Cash Collateralization of the LC Exposure pursuant to this paragraph, such Borrower shall Cash Collateralize the LC Exposure; provided that the obligation to deposit such cash collateral shall become effective immediately, and such deposit shall become immediately due and payable, without demand or other notice of any kind, upon the occurrence of any Event of Default with respect to such Borrower described in paragraph (f) of Article 7. If any Borrower is required to provide an amount of Cash Collateral hereunder as a result of the occurrence of an Event of Default, such amount (to the extent not applied as aforesaid) shall be returned to such Borrower within three Business Days after all Events of Default have been cured or waived.

     Section 2.05. Funding Of Borrowings. (a) Each Lender shall make each Loan to be made by it hereunder on the proposed date of the related Borrowing by wire transfer of immediately available funds by 12:00 noon, New York City time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders.

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The Administrative Agent will make such Loans available to the applicable Borrower by promptly crediting the Loan amounts so received, in like funds, to such account as designated by such Borrower in the applicable Borrowing Request; provided that ABR Loans made to finance the reimbursement of an LC Disbursement as provided in Section 2.04(e) shall be remitted by the Administrative Agent to the applicable Issuing Bank.

     (b) Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date (or, in the case of a requested ABR Borrowing for which notice has been provided by the Company on the same date of the proposed disbursement, the proposed time) of any Borrowing that such Lender will not make available to the Administrative Agent such Lender’s share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with paragraph (a) of this Section 2.05 and may, in reliance upon such assumption, make available to the applicable Borrower a corresponding amount. In such event, if a Lender has not in fact made its share of a Borrowing available to the Administrative Agent, then the applicable Lender and Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to such Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation, or (ii) in the case of the Borrower, the interest rate applicable to ABR Loans. If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender’s Loan included in such Borrowing.

     Section 2.06. Interest Elections. (a) Each Borrowing initially shall be of the Type specified in the applicable Borrowing Request and, in the case of a Eurodollar Borrowing, shall have an initial Interest Period as specified in such Borrowing Request. The Company, on its own behalf or on behalf of a Pipeline Company Borrower, may thereafter elect at any time and from time to time on any Business Day to convert such Borrowing to a different Type or to continue such Borrowing and, in the case of a Eurodollar Borrowing, may elect Interest Periods therefor, all as provided in this Section 2.06. The Company, on its own behalf or on behalf of a Pipeline Company Borrower, may elect different options with respect to different portions of the affected Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a separate Borrowing.

     (b) To make an election pursuant to this Section 2.06, a Borrower shall notify the Administrative Agent of such election by telephone not later than 12:00 noon, New York City time, three Business Days before the proposed effective date of such election. Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Interest Election Request in a form approved by the Administrative Agent and signed by such Borrower.

     (c) Each telephonic and written Interest Election Request shall specify the following information in compliance with Section 2.02:

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     (i) the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to clauses (iii) and (iv) below shall be specified for each resulting Borrowing);

     (ii) the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day;

     (iii) whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing; and

     (iv) if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term “Interest Period”.

If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an Interest Period, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration.

     (d) Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender’s portion of each resulting Borrowing.

     (e) If a Borrower fails to deliver a timely Interest Election Request with respect to a Eurodollar Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be converted to an ABR Borrowing. Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing and the Administrative Agent, at the request of the Majority Lenders, so notifies any Borrower, then, so long as an Event of Default is continuing (i) no outstanding Borrowing may be converted to or continued as a Eurodollar Borrowing and (ii) unless repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.

     Section 2.07. Optional and Mandatory Termination and Reduction of Commitments. (a) Unless previously terminated, the Commitments shall terminate on the Maturity Date.

     (b) The Company may at any time terminate, or from time to time reduce, the unused portions of the Commitments; provided that (i) each partial reduction of the Commitments shall be in an amount that is an integral multiple of $1,000,000 and not less than $10,000,000, and (ii) the Company shall not terminate or reduce the Commitments if, after giving effect to any concurrent prepayment of Loans in accordance with Section 2.09, the Outstandings would exceed the aggregate amount of the Commitments.

     (c) The Company shall notify the Administrative Agent of any election to terminate or reduce the Commitments under paragraph (b) of this Section 2.07, or any required reduction of the Commitments under paragraph (d) of this Section 2.07, at least three Business Days prior to the effective date of such termination or reduction, specifying such election and the effective

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date thereof. Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof. Each notice delivered by the Company pursuant to this Section 2.07 shall be irrevocable; provided that a notice of termination of the Commitments delivered by the Company may state that such notice is conditioned upon the effectiveness of other credit facilities, in which case such notice may be revoked by the Company (by notice to the Administrative Agent on or prior to the specified effective date) if such condition is not satisfied.

     (d) Within five days after the occurrence of a Mandatory Asset Reduction Event, the Commitments shall be ratably reduced (but not below zero) by an aggregate amount equal to the related Mandatory Asset Reduction Amount.

     (e) Any termination or reduction of the Commitments hereunder, whether optional or mandatory, shall be permanent. Each reduction of the Commitments shall be made ratably among the Lenders in accordance with their respective Commitments.

     Section 2.08. Repayment of Loans; Evidence of Debt. (a) Each Borrower hereby unconditionally promises to pay on the Maturity Date to the Administrative Agent for the account of each Lender the then unpaid principal amount of each Loan made to such Borrower.

     (b) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of each Borrower to such Lender resulting from each Loan made by such Lender to such Borrower, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

     (c) The Administrative Agent shall maintain accounts in which it shall record (i) the amount of each Loan made hereunder, the Type thereof, the Interest Period applicable thereto and the Borrower to whom such Loan is made, (ii) the amount of any principal or interest due and payable or to become due and payable to each Lender hereunder on account of each Loan from the relevant Borrower to whom such Loan was made and (iii) the amount of any sum received by the Administrative Agent hereunder for the account of the Lenders and each Lender’s share thereof.

     (d) The entries made in the accounts maintained pursuant to paragraph (b) or (c) of this Section 2.08 shall, to the extent permitted by applicable law, be prima facie evidence of the existence and amounts of the obligations of each Borrower recorded therein absent manifest error; provided that the failure of any Lender or the Administrative Agent to maintain any such account or any error therein shall not in any manner affect the obligation of each Borrower to repay the Loans made to such Borrower in accordance with the terms of this Agreement.

     (e) Any Lender may request that Loans made by it be evidenced by a Note. In such event, the applicable Borrower shall prepare, execute and deliver to such Lender a Note or Notes payable to the order of such Lender (or, if requested by such Lender, to such Lender and its registered assigns). Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (including after assignment pursuant to Section 10.04) be represented by one or more Notes in such form payable to the order of the payee named therein (or, if such Note is a registered note, to such payee and its registered assigns).

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     Section 2.09. Optional and Mandatory Prepayment of Loans. (a) Any Borrower shall have the right at any time and from time to time to prepay any Borrowing in whole or in part (without premium or penalty but subject to Section 2.14), subject to prior notice in accordance with paragraph (b) of this Section 2.09. All or any portion of any Loan prepaid may be borrowed and reborrowed in accordance with the terms and provisions of this Agreement.

     (b) A Borrower shall notify the Administrative Agent by telephone (confirmed by telecopy) of any optional prepayment hereunder (i) in the case of prepayment of a Eurodollar Borrowing, not later than 12:00 noon, New York City time, two Business Days before the date of prepayment, or (ii) in the case of prepayment of an ABR Borrowing, not later than 12:00 noon, New York City time, on the date of prepayment. Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of each Borrowing or portion thereof to be prepaid; provided that, if a notice of prepayment is given in connection with a conditional notice of termination of the Commitments as contemplated by Section 2.07(c), then such notice of prepayment may be revoked if such notice of termination is revoked in accordance with Section 2.07(c). Promptly following receipt of any such notice relating to a Borrowing, the Administrative Agent shall advise the Lenders of the contents thereof. Each optional partial prepayment of any Borrowing shall be in a minimum amount of $5,000,000 or a larger integral multiple of $1,000,000. Each optional prepayment of a Borrowing shall be applied ratably to the Loans included in the prepaid Borrowing. Each prepayment shall be accompanied by accrued and unpaid interest to the extent required by Section 2.11.

     (c) If on any date (including any date on which a mandatory reduction of Commitments occurs pursuant to Section 2.07(d)) the aggregate Outstandings exceed the then aggregate Commitments, then, without notice or demand, the Company shall promptly cause to be prepaid the principal amount of the Loans and any unreimbursed LC Disbursements in an amount equal to such excess and, if all Loans and unreimbursed LC Disbursements shall have been prepaid, promptly cause to be Cash Collateralized outstanding Letters of Credit by an amount equal to any remaining excess.

     Section 2.10. Fees. (a) The Company agrees to pay to the Administrative Agent for the account of each Lender a commitment fee, which shall accrue at the Applicable Rate on the daily amount of the excess of the Commitment of such Lender over such Lender’s Outstandings during the period from and including the date hereof to but excluding the date on which such Commitment terminates.

     (b) The Company agrees to pay (i) to the Administrative Agent for the account of each Lender a participation fee with respect to its participations in Letters of Credit, which shall accrue at the same Applicable Rate used to determine the interest rate applicable to Eurodollar Loans on the average daily amount of such Lender’s LC Exposure (excluding any portion thereof attributable to unreimbursed LC Disbursements) during the period from and including the Effective Date to but excluding the later of the date on which such Lender’s Commitment terminates and the date on which such Lender ceases to have any LC Exposure, (ii) to each Issuing Bank a fronting fee, which shall accrue at the rate of 0.125% per annum on the average daily amount of the LC Exposure (excluding any portion thereof attributable to unreimbursed LC Disbursements) with respect to each Letter of Credit issued by such Issuing Bank during the period from and including the Effective Date to but excluding the later of the date of termination

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of the Commitments and the date on which there ceases to be any LC Exposure with respect to Letters of Credit issued by such Issuing Bank and (iii) to each Issuing Bank, such Issuing Bank’s standard fees with respect to the issuance, amendment, renewal or extension of any Letter of Credit issued by it or processing of drawings thereunder.

     (c) Fees accrued pursuant to paragraphs (a), (b)(i) and (b)(ii) above, through and including the last day of March, June, September and December of each year shall be payable on the third Business Day following each such last day, commencing on the first such date to occur after the Effective Date; provided that all such fees for the account of the Lenders shall be payable on the date on which the Commitments terminate and any such fees accruing after the date on which the Commitments terminate shall be payable on demand. All such fees shall be computed on the basis of a year of 365 days (or 366 days in a leap year) and shall be payable for the actual number of days elapsed (including the first day but excluding the last day). Any other fees payable to any Issuing Bank pursuant to this Section shall be payable within 10 days after demand.

     (d) The Company agrees to pay (i) to the Administrative Agent, the Collateral Agent and the Lead Arrangers, for their own accounts, fees payable in the amounts and at the times separately agreed to pursuant to the Fee Letter and (ii) on or prior to the Effective Date, to the Administrative Agent for the account of each Lender an upfront fee in an amount separately agreed with the Lenders.

     (e) All fees payable hereunder shall be paid on the dates due, in immediately available funds, to the Administrative Agent (or to each Issuing Bank, in the case of fees payable to it) for distribution (if applicable) to the Lenders as specified above. Fees paid shall not be refundable under any circumstances.

     Section 2.11. Interest. (a) The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Rate.

     (b) The Loans comprising each Eurodollar Borrowing shall bear interest at the Adjusted LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Rate.

     (c) Notwithstanding the foregoing, if any principal of or interest on any Loan or any fee or other amount payable by any Borrower hereunder is not paid when due, whether at stated maturity, upon acceleration or otherwise, such overdue amount shall bear interest, after as well as before judgment, at a rate per annum equal to (i) in the case of overdue principal of any Loan, 2% plus the rate otherwise applicable to such Loan as provided in the preceding paragraphs of this Section 2.11 or (ii) in the case of any other amount, 2% plus the rate applicable to ABR Loans as provided in paragraph (a) of this Section 2.11.

     (d) Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan and upon termination of the Commitments; provided that (i) interest accrued pursuant to paragraph (c) of this Section 2.11 shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan, accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment and (iii) in the event of

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any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

     (e) All interest hereunder shall be computed on the basis of a year of 360 days, except that interest computed by reference to the Alternate Base Rate at times when the Alternate Base Rate is based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day of the Interest Period). The applicable Alternate Base Rate, Adjusted LIBO Rate or LIBO Rate shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error.

     Section 2.12. Alternate Rate of Interest. If prior to the commencement of any Interest Period for a Eurodollar Borrowing:

     (a) the Administrative Agent determines in good faith (which determination shall be conclusive absent manifest error) that, by reason of circumstances generally affecting the London interbank Eurodollar market, adequate and reasonable means do not exist for ascertaining the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period; or

     (b) the Administrative Agent is advised by the Majority Lenders that the Adjusted LIBO Rate or the LIBO Rate, as applicable, for such Interest Period will not adequately and fairly reflect the cost to such Lenders of making or maintaining their Loans included in such Borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Borrowers and the Lenders by telephone or telecopy as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrowers and the Lenders that the circumstances giving rise to such notice no longer exist, (i) any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective, and (ii) if any Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made as an ABR Borrowing.

     Section 2.13. Increased Costs.

     (a) If any Change in Law shall:

     (i) impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender (except any such reserve requirement reflected in the Adjusted LIBO Rate) or any Issuing Bank; or

     (ii) impose on any Lender or any Issuing Bank or the London interbank market any other condition materially affecting this Agreement or Eurodollar Loans made by such Lender or any Letter of Credit or participation therein;

in each case other than as specified in paragraph (b) below, and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such Loan) or to increase the cost to such Lender or such

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Issuing Bank of participating in, issuing or maintaining any Letter of Credit or to reduce the amount of any sum received or receivable by such Lender or such Issuing Bank hereunder (whether of principal, interest or otherwise), in each case by an amount that such Lender or such Issuing Bank reasonably deems to be material, then the applicable Borrower or Borrowers will pay to such Lender or such Issuing Bank, as the case may be, in accordance with paragraph (c) of this Section 2.13 after such Borrower’s receipt of its written demand accompanied by documentation specifying in reasonable detail the events and circumstances and the applicable Change in Law in support of any such reimbursement request, such additional amount or amounts necessary to compensate such Lender or such Issuing Bank, as the case may be, for such additional costs incurred or reduction suffered.

     (b) If any Lender or any Issuing Bank determines that any Change in Law regarding capital requirements has or would have the effect of reducing the rate of return on such Lender’s or such Issuing Bank’s capital or on the capital of such Lender’s or such Issuing Bank’s holding company, if any, as a consequence of this Agreement or the Loans made by, or participations in Letters of Credit held by, such Lender, or the Letters of Credit issued by such Issuing Bank, to a level below that which such Lender or such Issuing Bank or such Lender’s or such Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or such Issuing Bank’s policies and the policies of such Lender’s or such Issuing Bank’s holding company with respect to capital adequacy) by an amount reasonably deemed by such Lender or such Issuing Bank to be material, then from time to time upon submission by such Lender or such Issuing Bank to the applicable Borrower or Borrowers (with a copy to the Administrative Agent) of a written demand therefor accompanied by documentation specifying in reasonable detail the events and circumstances applicable to such reduction and the applicable Change in Law in support of such demand, and the amount demanded pursuant hereto, the applicable Borrower or Borrowers will, within 30 days after receipt of such demand, pay to such Lender or such Issuing Bank, as the case may be, such additional amount or amounts necessary to compensate such Lender or such Issuing Bank or such Lender’s or such Issuing Bank’s holding company for any such reduction suffered.

     (c) A certificate of a Lender or such Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or such Issuing Bank or its holding company, as the case may be, together with the relevant demand and accompanying documentation, all as specified in paragraph (a) or (b) of this Section 2.13, shall be delivered to the Company and shall be conclusive absent manifest error. The Company shall pay such Lender or such Issuing Bank, as the case may be, the amount shown as due on any such certificate within 30 days after receipt thereof.

     (d) Failure or delay on the part of any Lender or any Issuing Bank to demand compensation pursuant to this Section 2.13 shall not constitute a waiver of such Lender’s or such Issuing Bank’s right to demand such compensation; provided that a Borrower shall not be required to compensate a Lender or an Issuing Bank pursuant to this Section for any increased costs or reductions incurred more than 180 days prior to the date that such Lender or such Issuing Bank, as the case may be, notifies the Company of the Change in Law giving rise to such increased costs or reductions and of such Lender’s or such Issuing Bank’s intention to claim compensation therefor in accordance with this Section; provided further that, if the Change in

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Law giving rise to such increased costs or reductions is retroactive, then the 180-day period referred to above shall be extended to include the period of retroactive effect thereof.

     Section 2.14. Break Funding Payments. In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default or any prepayment under Section 2.09(a) or 2.09(c)), (b) the conversion of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto, (c) the failure to borrow, convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto (regardless of whether such notice may be revoked under Section 2.09(b) and is revoked in accordance therewith), or (d) the assignment of any Eurodollar Loan other than on the last day of the Interest Period applicable thereto as a result of a request by a Borrower pursuant to Section 2.17, then, in any such event, such Borrower shall compensate each Lender for the loss, cost and expense attributable to such event. In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount determined by such Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the amount so prepaid or converted, or not so borrowed, continued, converted or prepaid, at the Adjusted LIBO Rate that would have been applicable to such Eurodollar Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the Interest Period that would have commenced on the date of such failure for such Loan), over (ii) the amount of interest that would have accrued to such Lender on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the interbank eurodollar market. A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section shall be delivered to the applicable Borrower and shall be conclusive absent manifest error. Each affected Lender requesting payment under this Section shall submit written demand specifying in reasonable detail the events and circumstances resulting in such payment obligation, together with a certificate as to any amounts payable pursuant to this Section to the applicable Borrower. The applicable Borrower shall pay such Lender the amount shown as due on any such certificate within 30 days after receipt thereof.

     Section 2.15. Taxes. (a) Any and all payments by or on account of any obligation of any Borrower hereunder shall be made free and clear of and without deduction for any Indemnified Taxes or Other Taxes; provided that if a Borrower shall be required to deduct any Indemnified Taxes or Other Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section) the Administrative Agent, Lender or Issuing Bank (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) such Borrower shall make such deductions, and (iii) such Borrower shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

     (b) In addition, each Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

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     (c) Each Borrower shall indemnify the Administrative Agent, each Lender and each Issuing Bank, within 10 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes paid by the Administrative Agent, such Lender or such Issuing Bank, as the case may be, on or with respect to any payment by or on account of any obligation of any Borrower hereunder (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate as to the amount of such payment or liability delivered to a Borrower by a Lender or an Issuing Bank, or by the Administrative Agent on its own behalf or on behalf of a Lender or an Issuing Bank, shall be conclusive absent manifest error.

     (d) As soon as practicable after any payment of Indemnified Taxes or Other Taxes by a Borrower to a Governmental Authority, such Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

     (e) Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax under the law of the United States, or of the jurisdiction in which the Borrower is located, or any treaty to which such jurisdiction is a party, with respect to payments under this Agreement shall deliver to the Borrowers (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed forms or other documentation prescribed by applicable law or reasonably requested by a Borrower as will permit such payments to be made without withholding or at a reduced rate.

     (f) The Administrative Agent or a Lender shall determine if, in its reasonable discretion, it has received a refund of any Indemnified Taxes or Other Taxes as to which it has been indemnified by a Borrower or with respect to which a Borrower has paid additional amounts pursuant to this Section 2.15. If it determines that it has received any such refund, it shall pay over such refund to such Borrower (but only to the extent of indemnity payments made, or additional amounts paid, by such Borrower under this Section 2.15 with respect to the Indemnified Taxes or Other Taxes giving rise to such refund), net of all out-of-pocket expenses of the Administrative Agent or such Lender and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund); provided that each Borrower, upon the request of the Administrative Agent or such Lender, agrees to repay the amount paid over to such Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Administrative Agent or such Lender in the event the Administrative Agent or such Lender is required to repay such refund to such Governmental Authority. This Section shall not be construed to require the Administrative Agent or any Lender to make available its tax returns (or any other information relating to its taxes which it deems confidential) to any Borrower or any other Person.

     Section 2.16. Payments Generally; Pro Rata Treatment; Sharing of Set-Offs. (a) Each Borrower shall make each payment required to be made by it hereunder and, unless stated otherwise therein, under any of the other Loan Documents (whether of principal, interest, fees or reimbursement of LC Disbursements, or of amounts payable under Section 2.13, 2.14 or 2.15, or

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otherwise) prior to 12:00 noon, New York City time, on the date when due, in immediately available funds, without set-off or counterclaim. Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon. All such payments shall be made to the Administrative Agent at its offices at 270 Park Avenue, New York, New York, except payments to be made directly to an Issuing Bank as expressly provided herein and except that payments pursuant to Sections 2.13, 2.14, 2.15 and 10.03 shall be made directly to the Persons entitled thereto. The Administrative Agent shall distribute any such payments received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof. If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension. All payments hereunder shall be made in dollars.

     (b) Except as otherwise provided in Section 2.09(c), if at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, unreimbursed LC Disbursements, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal and unreimbursed LC Disbursements then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal and unreimbursed LC Disbursements then due to such parties.

     (c) If any Lender shall, by exercising any right of set-off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans or participations in LC Disbursements resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Loans and participations in LC Disbursements and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Loans and participations in LC Disbursements of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans and participations in LC Disbursements; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this paragraph shall not be construed to apply to any payment made by a Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans or participations in LC Disbursements to any assignee or participant, other than to a Borrower or any Subsidiary or Affiliate thereof (as to which the provisions of this paragraph shall apply). Each Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

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     (d) Unless the Administrative Agent shall have received notice from a Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders or any Issuing Bank hereunder that such Borrower will not make such payment, the Administrative Agent may assume that such Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders or the applicable Issuing Bank, as the case may be, the amount due. In such event, if such Borrower has not in fact made such payment, then each of the Lenders or any applicable Issuing Bank, as the case may be, severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender or such Issuing Bank, with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to or recovery by the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

     (e) If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.04(d) or 2.04(e), 2.05(b), or 2.16(d), then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender’s obligations under such Sections until all such unsatisfied obligations are fully paid.

     Section 2.17. Mitigation Obligations; Replacement of Lenders. (a) If any Lender requests compensation under Section 2.13, or if any Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.15, then such Lender shall use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 2.13 or 2.15, as the case may be, in the future and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. Each Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

     (b) If (w) any Lender requests compensation under Section 2.13, or (x) if any Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 2.15, or (y) if any Lender defaults in its obligation to fund Loans hereunder or (z) any Lender refuses to grant its approval with respect to any matter requiring the approval of all Lenders and such matter shall have been approved by the Majority Lenders, then the Company may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in Section 10.04), all its interests, rights and obligations under this Agreement to an assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that (i) the Company shall have received the prior written consent of the Administrative Agent, which consent shall not unreasonably be withheld, (ii) such Lender shall have received payment of an amount equal to the outstanding principal of its Loans, participations in LC Disbursements, accrued interest thereon, accrued fees and all other amounts payable to it hereunder, from the assignee (to the extent of such outstanding principal, participations in LC Disbursements and

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accrued interest and fees) or the Borrowers (in the case of all other amounts) and (iii) in the case of any such assignment resulting from a claim for compensation under Section 2.13 or payments required to be made pursuant to Section 2.15, such assignment will result in a reduction in such compensation or payments. A Lender shall not be required to make any such assignment and delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Company to require such assignment and delegation cease to apply.

ARTICLE 3
Conditions

     Section 3.01. Effective Date; Conditions to Initial Credit Event. This Agreement and the other Loan Documents, and the obligations of the Lenders to make Loans hereunder and of the Issuing Banks to issue Letters of Credit hereunder, shall not become effective until the date (the “Effective Date”) on which each of the following conditions is satisfied (or waived in accordance with Section 10.02):

     (a) This Third Amended and Restated Credit Agreement and each other Loan Document to be executed and delivered on or before the Effective Date shall have been executed by each party thereto, and each of the Administrative Agent (or its counsel) and the Company (or its counsel) shall have received from each party hereto and thereto either (i) a counterpart hereof or thereof, signed on behalf of each party thereto or (ii) written evidence satisfactory to the Administrative Agent (which may include telecopy transmission of a signed signature page of this Agreement or such other Loan Document) that such party has signed a counterpart hereof or thereof.

     (b) The Administrative Agent shall have received the following in form and substance satisfactory to the Administrative Agent and in sufficient copies for each Lender:

     (i) true and correct copies of the resolutions of the Board of Directors (or a committee thereof) of each of the Borrowers, certified as to authenticity by the Secretary or an Assistant Secretary (or equivalent) of such Borrower, approving the borrowings and any Guaranties contemplated hereby and authorizing the execution of this Agreement and the other Loan Documents, to the extent such Borrower is a party thereto, and of all documents evidencing other required Business Entity action of each of the Borrowers and required governmental approvals to each of the Borrowers, if any, with respect to this Agreement and the other Loan Documents.

     (ii) true and correct copies of the resolutions of the Board of Directors (or a committee thereof) of each of the Subsidiary Guarantors (but excluding any Released Parties), certified as to authenticity by the Secretary or an Assistant Secretary (or equivalent) of such Subsidiary Guarantor, approving the Guaranty of the Subsidiary Guarantors pursuant to the Subsidiary Guarantee Agreement as contemplated hereby and authorizing the execution of such Subsidiary Guarantee Agreement and the other Loan Documents, to the extent such Subsidiary Guarantor is a party thereto, and of all documents evidencing other required Business Entity action of each of the Subsidiary

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Guarantors and required governmental approvals to each of the Subsidiary Guarantors, if any, with respect to the Subsidiary Guarantee Agreement and the other Loan Documents.

     (iii) a certificate of the Secretary or an Assistant Secretary (or the equivalent) of each of the Credit Parties (but excluding any Released Parties) certifying the names and true signatures of the officers of each such Credit Party authorized to sign any Loan Document and any other documents to be delivered by it hereunder or thereunder.

     (iv) true and correct copies of the Business Entity organizational or formation documents of each Credit Party and of each Pledged Company (but excluding any Released Parties), certified as to the receipt and filing of public record thereof by the appropriate filing officer (or the office thereof) to the extent such documents are required by law to be on file in the jurisdiction of organization or formation of such Person, and further certified as to authenticity and completeness by the Secretary or an Assistant Secretary (or the equivalent) of such Person.

     (v) copies of certificates dated as of a recent date from the Secretary of State or other appropriate authority of such jurisdiction, evidencing the good standing (or equivalent status) of each of the Credit Parties and of each Pledged Company (but excluding any Released Parties) in its state of organization or formation.

     (vi) written opinions of (A) Bracewell & Giuliani LLP, counsel for the Credit Parties, substantially in the form of Exhibit F-1, and (B) the General Counsel or Associate General Counsel of the Company, substantially in the form of Exhibit F-2. The Borrowers hereby request such counsel to deliver such opinions.

     (vii) certificates, dated the Effective Date and signed by the President, a Vice President or a Financial Officer of the Company, confirming compliance with the conditions set forth in paragraphs (a) and (b) of Section 3.02.

     (viii) certificates, dated the Effective Date and signed by the President, a Vice President or a Financial Officer of the Company, confirming that no default or event of default that has not been waived shall have occurred and be continuing under the Existing Facility (as in effect immediately prior to the Effective Date).

     (c) The Administrative Agent shall have received (or shall receive from the proceeds of a Borrowing on the Effective Date) all fees and other amounts due and payable on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses required to be reimbursed or paid by the Borrowers hereunder.

     (d) (i) The Deposit (as defined in the Existing Facility), together with accrued interest thereon, shall have been returned to the Deposit Lenders (as defined in the Existing Facility) (or shall be returned substantially simultaneously with the closing hereunder), (ii) all Loans owing to Departing Lenders, together with accrued interest thereon and accrued fees and all other amounts payable under the Existing Facility for the account of Departing Lenders shall have been paid (or shall be paid substantially simultaneously with the closing hereunder) and (iii) the Administrative Agent shall have received evidence satisfactory to it of the foregoing.

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     (e) The Administrative Agent shall have received (i) evidence in form and substance satisfactory to it that all filings, recordings, registrations and other actions, including, without limitation, the filing of duly completed Uniform Commercial Code financing statements, necessary or, in the opinion of the Administrative Agent, desirable to perfect the Transaction Liens shall have been completed, (ii) the certificates, if any, representing the stock, limited partnership interests, limited liability company interests and general partnership interests or any other Equity Interest pledged as of the Effective Date pursuant to the Security Agreement, together with an undated stock power or other transfer certificate for each such certificate executed in blank by a duly authorized officer of the pledgor thereof, and (iii) such other evidence of the control of the applicable Collateral by the Collateral Agent acceptable to the Administrative Agent as may be requested the Administrative Agent.

     (f) Each of the Pipeline Company Borrowers, the Subsidiary Guarantors and the Pledged Companies shall be a wholly-owned, direct or indirect, Subsidiary of the Company.

     (g) The Administrative Agent shall have received (i) the audited consolidated financial statements of the Company and its consolidated Subsidiaries for the fiscal year ended December 31, 2006 and (ii) the unaudited consolidated financial statements of the Company and its consolidated Subsidiaries for the fiscal quarter ended September 30, 2007.

The Administrative Agent shall notify the Borrowers and the Lenders of the Effective Date and the satisfaction (or waiver in accordance with Section 10.02) of the conditions set forth in this Section 3.01, and such notice shall be conclusive and binding. Notwithstanding the foregoing, the obligations of the Lenders to make Loans and of the Issuing Banks to issue Letters of Credit hereunder shall not become effective unless each of the foregoing conditions is satisfied (or waived in accordance with Section 10.02) at or prior to 3:00 p.m., New York City time, on November 30, 2007 (and, in the event such conditions are not so satisfied or waived, the Commitments shall terminate at such time).

     Section 3.02. Each Credit Event. The obligation of each Lender to make a Loan (excluding any continuation or conversion of a Loan and any Loan financing the repayment of an LC Disbursement but including the Loans to be made on the Effective Date) on the occasion of any Borrowing, and the obligation of any Issuing Bank to issue a requested Letter of Credit (including the Letters of Credit to be deemed issued hereunder on the Effective Date but excluding the extension or renewal of Letters of Credit) for the account of any Borrower (or amend or increase the stated amount of any issued Letter of Credit), is subject to the satisfaction of the following conditions:

     (a) The representations and warranties of each Borrower and each other Credit Party set forth in this Agreement and the other Loan Documents shall be true and correct in all material respects on and as of the date of such Borrowing, or the date of issuance (or amendment or increase in the stated amount) of such Letter of Credit, as applicable, unless stated to be made on or as of, or to relate to, a specific date or period other than the date of such Borrowing or issuance (or amendment or increase in the stated amount).

     (b) At the time of and immediately after giving effect to such Borrowing (and, if any proceeds thereof are being applied substantially contemporaneously to satisfy any other

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obligation, to such application) or the issuance (or amendment or increase in the stated amount) of such Letter of Credit, as applicable, no Default shall have occurred and be continuing.

     (c) In the case of the issuance of a Letter of Credit, to the extent not already in effect between the Company and the Issuing Bank issuing such Letter of Credit, the applicable Borrower shall have executed and delivered standard documentation for account parties or reimbursement obligors in connection with the issuances of letters of credit as is customary for such Issuing Bank and that is not otherwise inconsistent with the terms of this Agreement.

Each Borrowing and each issuance of a (or amendment of or increase in the stated amount of an issued) Letter of Credit shall be deemed to constitute a representation and warranty by the applicable Borrower on the date thereof as to the matters specified in paragraphs (a) and (b) of this Section.

     Section 3.03. Changes In Lenders And Commitments. On the Effective Date:

     (a) The Deposit Commitments (as defined in the Existing Facility) shall terminate, and the Deposit Lenders shall cease to be Lenders party to this Agreement, provided that the provisions of Sections 2.13, 2.14, 2.15 and 10.03 shall continue to inure to the benefit of such Deposit Lenders.

     (b) Each Person listed in Schedule 1 hereto shall be a Lender with a Commitment in the applicable amount set forth for such Lender in Schedule 1.

     (c) Each Lender which is not a Revolving Lender (as defined in the Existing Facility) (a “New Lender”) shall make new Loans to the Borrowers in an amount such that, after giving effect thereto, the aggregate amount of such Loans shall bear the same relationship to the Commitment of such New Lender as the outstanding Loans of the other Lenders bear to their Commitments, such new Loans to be allocated ratably among all outstanding Borrowings and to be deemed part of such outstanding Borrowings.

     (d) The Existing Letters of Credit shall become Letters of Credit hereunder, and the participations of the Lenders therein shall be redetermined on the basis of their respective Commitments set forth in Schedule 1, all pursuant to Section 2.04(b).

     (e) Any Revolving Lender party to the Existing Facility but not listed in Schedule 1 shall cease to be a Lender party to this Agreement, shall cease to have any Commitment hereunder or any participation in outstanding Letters of Credit, and all Loans made by such Departing Lender, and all accrued interest, fees and other amounts payable under the Existing Facility for its account shall be due and payable on the Effective Date; provided that the provisions of Sections 2.13, 2.14, 2.15 and 10.03 of this Agreement shall continue to inure to the benefit of such Departing Lender.

     (f) Any Lender which is not a New Lender, but whose Percentage is greater than its Revolving Percentage (as defined in the Existing Facility) previously in effect shall be deemed a New Lender for purposes hereof to the extent of such increase, and any such Lender whose Percentage is less than its Revolving Percentage shall be deemed a Departing Lender for purposes hereof to the extent of such decrease.

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     (g) The Lenders which are parties to the Existing Facility, comprising the “Majority Lenders” as defined therein, hereby waive any requirement of notice of termination of the Commitments pursuant to Section 2.07(c) of the Existing Facility and of prepayment of Loans to the extent necessary to give effect to Section 3.01(d) and this Section 3.03.

ARTICLE 4
Representations and Warranties

     The Company, and each Pipeline Company Borrower, in each case with respect to itself and its Subsidiaries, represents and warrants to the Administrative Agent, the Collateral Agent, each Issuing Bank and each Lender that:

     Section 4.01. Organization; Powers. The Company is a Business Entity duly formed, validly existing and in good standing under the laws of the State of Delaware. Each other Credit Related Party is duly organized or formed, validly existing and, if applicable, in good standing in the jurisdiction of its organization or formation. Each Credit Related Party possesses all applicable Business Entity powers and all other authorizations and licenses necessary to engage in its business and operations as now conducted, the failure to obtain or maintain which would have a Material Adverse Effect.

     Section 4.02. Authorization. The execution, delivery and performance by each Credit Party of the Loan Documents to which it is a party are within such Credit Party’s applicable Business Entity powers, have been duly authorized by all necessary applicable Business Entity action, and do not contravene (a) any Credit Related Party’s organizational documents, or (b) any law or any material contractual restriction binding on or affecting any Credit Related Party.

     Section 4.03. Governmental Approvals; No Conflicts. No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority is required for the due execution, delivery and performance by any Credit Party of any Loan Document to which it is a party, except those necessary to comply with laws, rules, regulations and orders required in the ordinary course to comply with ongoing obligations of such Credit Party under Sections 5.01, 5.02 and 5.07, as applicable.

     Section 4.04. Binding Obligation; Enforceability. This Agreement constitutes, and the other Loan Documents when delivered hereunder shall constitute, the legal, valid and binding obligations of each Credit Party that is a party thereto, enforceable against such Credit Party in accordance with their respective terms, except as may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally or by general principles of equity.

     Section 4.05. Financial Condition.

     (a) (a) The consolidated balance sheet of the Company and its consolidated Subsidiaries as of December 31, 2006, and the related consolidated statements of income and cash flows of the Company and its consolidated Subsidiaries for the fiscal year then ended, reported on by Ernst & Young LLP, independent public accountants, copies of which have been

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furnished to the Administrative Agent and the Lenders prior to the date hereof, present fairly, in all material respects, the consolidated financial condition of the Company and its consolidated Subsidiaries as at such date and the consolidated results of the operations of the Company and its consolidated Subsidiaries for the period ended on such date, all in accordance with GAAP consistently applied (except as approved by the chief financial officer of such entity and as disclosed therein), excluding for purposes of this representation the effect of any subsequent revisions or restatements thereto that may be required by the SEC with respect to (i) the accounting treatment relating to the negative revision in the proven reserves of crude oil and natural gas of the Company effected as of or prior to December 31, 2003 by an amount equal to approximately 1.83 trillion cubic feet equivalent and (ii) the manner in which the Company reported changes to the accounting for various hedging transactions and related ceiling test impairment charges.

     (b) The consolidated balance sheets of the Company and its consolidated Subsidiaries as of September 30, 2007, and the related consolidated statements of income and cash flows of the Company and its consolidated Subsidiaries for the fiscal period then ended, copies of which have been furnished to the Administrative Agent on or prior to the date hereof, present fairly, in all material respects, the consolidated financial condition of the Company and its consolidated Subsidiaries as at such date and the consolidated results of the operations of the Company and its consolidated Subsidiaries for the period ended on such date, all in accordance with GAAP consistently applied (except as approved by the chief financial officer of such entity and as disclosed therein), subject in the case of such unaudited statements to normal year-end audit adjustments and reduced footnote disclosure, excluding for purposes of this representation the effect of any subsequent revisions or restatements thereto that may be required by the SEC with respect to (i) the accounting treatment relating to the negative revision in the proven reserves of crude oil and natural gas of the Company effected as of or prior to December 31, 2003 by an amount equal to approximately 1.83 trillion cubic feet equivalent and (ii) the manner in which the Company reported changes to the accounting for various hedging transactions and related ceiling test impairment charges.

     (c) Except as set forth in Schedule 4.05 or in the annual and quarterly reports referred to in Section 4.07 (collectively, the “Disclosure Update”), as of the Effective Date, since December 31, 2006, there has been no Material Adverse Effect.

     Section 4.06. Compliance with Laws and Agreements. Each of the Company and its Subsidiaries is in compliance with all laws, rules, regulations and orders of any Governmental Authority applicable to it or its property except where the failure to comply, individually or in the aggregate, would not, in the reasonable judgment of the Company, be expected to result in a Material Adverse Effect; provided that the alleged failures to comply with such laws, rules, regulations, and orders that are disclosed in any annual report on Form 10-K, quarterly report on Form 10-Q or current report on Form 8-K filed by any Borrower with the SEC prior to the date hereof shall not be deemed at any time by the parties to the Loan Documents to be expected to have a Material Adverse Effect for any purposes hereof.

     Section 4.07. Litigation. There is no action, suit or proceeding pending, or to the knowledge of any Borrower threatened, against or involving any Credit Related Party in any court, or before any arbitrator of any kind, or before or by any Governmental Authority, existing

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as of the Effective Date (x) that in the reasonable judgment of the Company (taking into account the availability of appeals) could reasonably be expected to have a Material Adverse Effect, except for the proceedings described in the Company’s annual report on Form 10-K for the year ended December 31, 2006 or its quarterly report on Form 10-Q for the fiscal quarter ended September 30, 2007 (the “3^rd Quarter 2007 10-Q”) as filed with the SEC (the “Disclosed Proceedings”) or (y) which purports to affect the legality, validity, binding effect or enforceability of the Loan Documents. Since the date of filing of the 3^rd Quarter 2007 10-Q, there has been no adverse change in the status of the Disclosed Proceedings that, taking into account the availability of any appeals, could reasonably be expected to increase materially the likelihood of a Material Adverse Effect resulting therefrom.

     Section 4.08. Taxes. Each Credit Related Party has duly filed all tax returns required to be filed by it, and has duly paid and discharged all taxes, assessments and governmental charges upon it or against its properties now due and payable, the failure to file or pay which, as applicable, would have a Material Adverse Effect, unless and to the extent only that the same are being contested in good faith and by appropriate proceedings by the Company or the applicable Credit Related Party.

     Section 4.09. Properties. (a) Each Credit Related Party has good title to its respective properties and assets, free and clear of all mortgages, liens and encumbrances, except for (i) Transaction Liens and (ii) other mortgages, liens and other encumbrances (including covenants, restrictions, rights, easements and minor irregularities in title) that do not materially interfere with the business or operations of such Credit Related Party as presently conducted or that are permitted by Section 6.01.

     (b) As of the Effective Date, the Company is aware of no Liens permitted by Section 6.01(a) solely by reason of clause (d) of the definition of Collateral Permitted Liens.

     Section 4.10. ERISA. (a) No Termination Event has occurred or is reasonably expected to occur with respect to any Plan which, with the giving of notice or lapse of time, or both, would constitute an Event of Default under paragraph (h) of Article 7.

     (b) Each Plan has complied with the applicable provisions of ERISA and the Code where the failure to so comply would reasonably be expected to result in a Material Adverse Effect.

     (c) The statement of assets and liabilities of each Plan and the statements of changes in fund balance and in financial position, or the statement of changes in net assets available for plan benefits, for the most recent plan year for which an accountant’s report with respect to such Plan has been prepared, copies of which report have been made available to the Administrative Agent, present fairly, in all material respects, the financial condition of such Plan as at such date and the results of operations of such Plan for the plan year ended on such date.

     (d) Neither the Company nor any ERISA Affiliate has incurred, or is reasonably expected to incur, any Withdrawal Liability to any Multiemployer Plan which, when aggregated with all other amounts required to be paid to Multiemployer Plans in connection with Withdrawal Liability (as of the date of determination), would have a Material Adverse Effect.

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     (e) Neither the Company nor any ERISA Affiliate has received any notification that any Multiemployer Plan is in reorganization, insolvent or has been terminated, within the meaning of Title IV of ERISA, and no Multiemployer Plan is reasonably expected to be in reorganization, to be insolvent or to be terminated within the meaning of Title IV of ERISA the effect of which reorganization, insolvency or termination would be the occurrence of an Event of Default under paragraph (h) of Article 7.

     Section 4.11. Investment Company Act. No Credit Party is an “investment company” or a “company” controlled by an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

     Section 4.12. Federal Reserve Regulations. The Borrowings by any Borrower under this Agreement and the Notes and the application of the proceeds thereof as provided herein will not violate Regulation T, U or X of the Board of Governors.

     Section 4.13. Collateral. The Security Agreement is effective to create in favor of the Collateral Agent, for the benefit of the Secured Parties, a valid Lien on, and security interest in, all right, title and interest of each Credit Party, as applicable, in the Collateral, as security for the Secured Obligations, prior and superior in right to any other Lien (except for Collateral Permitted Liens), except in each case above as may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally. All financing statements have been filed that are necessary to perfect any security interest created pursuant to any Security Document that can be perfected by the filing of such financing statements and all actions necessary to provide control to the Collateral Agent, with respect to any Collateral for which control can be established in favor of the Collateral Agent have been taken, including delivery of such Collateral to the Collateral Agent to the extent such Collateral is certificated or for which possession can provide perfection with respect thereto.

     Section 4.14. Environmental Matters. Except for the matters set forth on Schedule 4.14 and other matters that, in the aggregate, could not reasonably be expected to result in a Material Adverse Effect, no Credit Related Party (a) has failed to comply with any Environmental Law or to obtain, maintain or comply with any permit, license or other approval required under any Environmental Law, (b) is subject to any Environmental Liability, (c) has received notice of any claim with respect to any Environmental Liability or (d) knows of any basis for any Environmental Liability.

     Section 4.15. Disclosure. The publicly available information filed by any Credit Related Party with the SEC when taken as a whole does not contain any material misstatement of fact or omit to state any material facts necessary to make the statements therein, in light of the circumstances under which they were made, not misleading.

     Section 4.16. Subsidiaries. Schedule 4.16 sets forth the name of, and the ownership interest of the Company in, each of its Subsidiaries as of October 12, 2007.

     All representations and warranties made by the Credit Parties herein, and any other Loan Document delivered pursuant hereto, shall survive the making of the Loans, the issuance of any Letter of Credit and the execution and delivery by the Credit Parties of the Loan Documents.

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ARTICLE 5
Affirmative Covenants

     Until the Final Payment Date shall have occurred, unless the Majority Lenders shall otherwise consent in writing, each Borrower will, with respect to Sections 5.01 through 5.06, and the Company will, with respect to Sections 5.07 through 5.09:

     Section 5.01. Preservation of Existence. Preserve and maintain, and, in the case of the Company, cause each other Credit Related Party to preserve and maintain, its (a) existence, (b) rights (organizational and statutory), and (c) material franchises, except as otherwise permitted by Section 6.04 or 6.05 or where the failure to so preserve would not have a Material Adverse Effect and except that nothing herein shall prevent any change in Business Entity form of the Company or any other Credit Related Party.

     Section 5.02. Compliance with Laws. Comply, and, in the case of the Company, cause each other Credit Related Party to comply, in all material respects with all applicable laws, rules, regulations and orders (including all Environmental Laws and laws requiring payment of all taxes, assessments and governmental charges imposed upon it or upon its property except to the extent contested in good faith by appropriate proceedings) the failure to comply with which would have a Material Adverse Effect.

     Section 5.03. Visitation Rights. At any reasonable time and from time to time, permit the Administrative Agent or any of the Lenders or any agents or representatives thereof, to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, the Company and any of its Subsidiaries, and to discuss the affairs, finances and accounts of the Company and any of its Subsidiaries with any of their officers and, in the company of an officer of the Company or the applicable Subsidiary if so requested by the Company, with their independent certified public accountants.

     Section 5.04. Books and Records. Keep, and, in the case of the Company, cause each of its Subsidiaries to keep, proper books of record and account, in which full and correct entries shall be made of all its respective financial transactions and the assets and business of the Company and each of its Subsidiaries, as applicable, in accordance with GAAP either (a) consistently applied or (b) applied in a changed manner provided such change shall have been disclosed to the Administrative Agent and shall have been consented to by the accountants which (as required by Section 5.08) report on the financial statements of the Company and its Subsidiaries for the fiscal year in which such change shall have occurred.

     Section 5.05. Maintenance of Properties. Maintain and preserve, and, in the case of the Company, cause each other Credit Related Party to maintain and preserve, all of its properties that are used in the conduct of its business in good working order and condition, ordinary wear and tear excepted, to the extent that any failure to do so would have a Material Adverse Effect.

     Section 5.06. Maintenance of Insurance. Maintain or cause to be maintained with financially sound and reputable insurance companies (or through self-insurance), property damage and liability insurance of such types, in such amounts and against such risks as is

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commercially reasonable to maintain; and furnish to the Administrative Agent, upon written request, full information as to the insurance carried.

     Section 5.07. Security Interests in Collateral. (a) Execute and deliver, and cause each Subsidiary Guarantor to execute and deliver, to the Administrative Agent such guaranties, security agreements and supplements, amendments and joinders to the Security Documents, in each case in form and substance reasonably satisfactory to the Administrative Agent and as the Administrative Agent deems necessary or advisable in order to ensure that the applicable Guarantor guarantees, as primary obligor and not as surety, the full and punctual payment when due of the Secured Obligations and that the Secured Obligations are secured by valid, perfected and enforceable first-priority Transaction Liens (subject only to Collateral Permitted Liens) over all of the Collateral owned by the Company or such Subsidiary Guarantor as security for the Secured Obligations, and (b) deliver, or cause to be delivered, to the Administrative Agent such opinions of counsel and other related documents as may be reasonably requested by the Administrative Agent with respect to the requirements of this Section 5.07.

     Section 5.08. Reporting Requirements. Furnish to each Lender in such reasonable quantities as shall from time to time be requested by such Lender:

     (a) as soon as publicly available, and in any event within 60 days after the end of each of the first three fiscal quarters of each fiscal year of each of the Company and each other Credit Related Party that is required to file a Form 10-Q and/or Form 10-K with the SEC, a consolidated balance sheet of each of the Company and such other Credit Related Party and its respective consolidated Subsidiaries as of the end of such quarter, and consolidated statements of income and cash flows of each of the Company and such other Credit Related Party and its respective Subsidiaries each for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, certified (subject to normal year-end adjustments and the absence of footnotes) as being fairly stated in all material respects by a Financial Officer and accompanied by a certificate of such officer stating (i) whether or not such officer has knowledge of the occurrence of any Event of Default that is continuing hereunder or of any event not theretofore remedied that with notice or lapse of time or both would constitute such an Event of Default and, if so, stating in reasonable detail the facts with respect thereto, (ii) all relevant facts in reasonable detail to evidence, and the computations as to, whether or not (A) the Company is in compliance with the requirements set forth in Section 6.02 and (B) each Pipeline Company Borrower is in compliance with the requirements set forth in Section 6.03, and (iii) a listing of all Credit Related Parties and consolidated Subsidiaries of the Company showing the extent of its direct and indirect holdings of their stocks;

     (b) as soon as publicly available and in any event within 120 days after the end of each fiscal year of each of the Company and each other Credit Related Party that is required to file a Form 10-Q and/or Form 10-K with the SEC, a copy of the annual report for such year for each of the Company and such other Credit Related Party and its respective consolidated Subsidiaries containing financial statements for such year reported on by nationally recognized independent public accountants (without any qualification or exception as to the scope of such audit), accompanied by a report signed by said accountants stating that such financial statements have been prepared in accordance with GAAP;

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     (c) within 120 days after the close of each of the Company’s fiscal years, a certificate of a Financial Officer stating (i) whether or not he has knowledge of the occurrence of any Event of Default that is continuing hereunder or of any event not theretofore remedied that with notice or lapse of time or both would constitute such an Event of Default and, if so, stating in reasonable detail the facts with respect thereto, (ii) all relevant facts in reasonable detail to evidence, and the computations as to, whether or not (A) the Company is in compliance with the requirements set forth in Section 6.02 and (B) each Pipeline Company Borrower is in compliance with the requirements set forth in Section 6.03, and (iii) a listing of all Credit Related Parties and consolidated Subsidiaries of the Company showing the extent of its direct and indirect holdings of their stocks;

     (d) promptly after the sending or filing thereof, copies of all publicly available reports that the Company or any other Credit Related Party sends to any of its security holders and copies of all publicly available reports and registration statements that the Company or any other Credit Related Party files with the SEC or any national securities exchange other than registration statements relating to employee benefit plans and to registrations of securities for selling security holders;

     (e) within 10 days after sending or filing thereof, a copy of FERC Form No. 2: Annual Report of Major Natural Gas Companies, sent or filed by any Credit Related Party with FERC with respect to each fiscal year of such Credit Related Party;

     (f) promptly in writing, notice of all litigation and of all proceedings before any Governmental Authority against or involving the Company or any other Credit Related Party, except any litigation or proceeding that in the reasonable judgment of the Company (taking into account the availability of appeals) is not likely to have a material adverse effect on the consolidated financial condition of the Company and its consolidated Subsidiaries taken as a whole;

     (g) within three Business Days after a Financial Officer obtains knowledge thereof (i) notice of the occurrence of any Default that is continuing, together with a detailed statement by a responsible officer of the Company of the steps being taken by the Company or the appropriate Subsidiary of the Company to cure the effect of such event, (ii) notice of the occurrence of any event that could reasonably be expected to result in a Material Adverse Effect and (iii) notice of the execution of any agreement relating to, or the consummation of, any Disposition that could reasonably be expected to result in a Mandatory Asset Reduction Event,

     (h) as soon as practicable and in any event (i) within 30 days after the Company or any ERISA Affiliate knows or has reason to know that any Termination Event described in clause (a) of the definition of Termination Event with respect to any Plan has occurred that could reasonably be expected to have a Material Adverse Effect, and (ii) within 10 days after the Company or any ERISA Affiliate knows or has reason to know that any other Termination Event with respect to any Plan has occurred, a statement of a Financial Officer describing such Termination Event and the action, if any, that the Company or such ERISA Affiliate proposes to take with respect thereto;

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     (i) promptly and in any event within five Business Days after receipt thereof by the Company or any ERISA Affiliate, copies of each notice received by the Company or any ERISA Affiliate from the PBGC stating its intention to terminate any Plan or to have a trustee appointed to administer any Plan which termination could reasonably be expected to have a Material Adverse Effect;

     (j) promptly and in any event within 30 days after the filing thereof with the Internal Revenue Service, copies of each Schedule B (Actuarial Information) to the annual report (Form 5500 Series) with respect to each Single Employer Plan;

     (k) promptly and in any event within five Business Days after receipt thereof by the Company or any ERISA Affiliate from the sponsor of a Multiemployer Plan, a copy of each notice received by the Company or any ERISA Affiliate concerning (i) the imposition of Withdrawal Liability by a Multiemployer Plan, (ii) the determination that a Multiemployer Plan is, or is expected to be, in reorganization or insolvent within the meaning of Title IV of ERISA, (iii) the termination of a Multiemployer Plan within the meaning of Title IV of ERISA, or (iv) the amount of liability incurred, or expected to be incurred, by the Company or any ERISA Affiliate in connection with any event described in clause (i), (ii), or (iii) above, in each case if such event could reasonably be expected to have a Material Adverse Effect; and

     (l) as soon as practicable but in any event within 60 days of any notice of request therefor, such other information respecting the financial condition and results of operations of the Company or any Subsidiary of the Company as any Lender through the Administrative Agent may from time to time reasonably request.

     Each balance sheet and other financial statement furnished pursuant to Sections 5.08(a) and 5.08(b) shall contain comparative financial information which conforms to the presentation required in Form 10-Q and 10-K, as appropriate, under the Securities Exchange Act of 1934, as amended. The electronic posting of any financial statements, reports, notices or other items required to be furnished pursuant to this Section 5.08 on a website established for Lender access shall constitute delivery for all purposes this of Section 5.08.

     Section 5.09. Collateral Reporting. Furnish, and cause each Subsidiary Guarantor to furnish, to the Collateral Agent, on a quarterly basis, as of March 31, June 30, September 30 and December 31 of each calendar year, within 60 days after the end of each of the first three calendar quarters and within 120 days after the end of each calendar year, commencing September 30, 2007, a supplement to Schedule V to the Security Agreement.

ARTICLE 6
Negative Covenants

     Until the Final Payment Date shall have occurred, unless the Majority Lenders shall otherwise consent in writing:

     Section 6.01. Liens.

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     (a) The Company shall not, and shall not permit any Subsidiary of the Company to, create, assume, incur, or suffer to exist, any Liens (other than Collateral Permitted Liens) upon or with respect to any of the Collateral.

     (b) The Company shall not, and shall not permit any Subsidiary of the Company (other than Southern Natural Gas Company, (i) MLP, (ii) any Project Financing Subsidiary and (iii) any Subsidiary of any of the foregoing) to, create, assume, incur, or suffer to exist, any Lien securing Debt that would require the Company or any of its Subsidiaries to equally and ratably secure such Debt with any Specified Indenture Debt of the Company or any consolidated Subsidiary of the Company unless the Secured Obligations shall be secured equally and ratably with, or prior to, such Debt so long as such Specified Indenture Debt shall be so equally and ratably secured.

     (c) The Company shall not permit any Restricted Subsidiary to create, assume, incur or suffer to exist any Lien on any property or asset of such Restricted Subsidiary except for:

     (i) Liens on the Equity Interests in, or Indebtedness or other obligations of, or assets of, any Project Financing Subsidiary (or any Equity Interests in, or Indebtedness or other obligations of, any Business Entity that is directly or indirectly owned by any Project Financing Subsidiary) securing the payment of a Project Financing and related obligations;

     (ii) Permitted Liens;

     (iii) Liens created by any Alternate Program permitted under Section 6.04(b)(iv) (or any document executed by any Borrower or any Subsidiary of a Borrower in connection therewith);

     (iv) Liens (other than Liens with respect to the Collateral) in existence on the Effective Date, plus any successive renewals or extensions of such Liens, and any grant of a Lien, in connection with any successive refinancing, extension or renewal of the Debt or any liability under any Guaranty secured by such Liens, provided that (A) the aggregate principal amount of the Debt or any liability under any Guaranty (and any successive refinancing, extension or renewal thereof) secured by such Liens does not increase from that amount outstanding at the time of such renewal, extension or grant of the Lien or such refinancing and any such successive renewal, extension or grant of the Lien does not encumber any additional property or assets of such Restricted Subsidiary (except as contemplated by clause (vii) below) and (B) no such Liens shall be granted after the Effective Date to secure Debt owed to the Company or to any of its Subsidiaries that is not a Restricted Subsidiary;

     (v) any Lien on any asset (including a Capital Lease) securing Indebtedness incurred or assumed for the purpose of financing all or any part of the cost of acquiring such asset, provided that such Lien attaches to such asset concurrently with or within 180 days after the acquisition thereof;

     (vi) the Transaction Liens and Liens permitted by the Security Documents; and

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     (vii) any Lien on products and proceeds (including dividends, distributions, interest and like payments on or with respect to, and insurance and condemnation proceeds and rental, lease, licensing and similar proceeds) of, and property evidencing or embodying, or constituting rights or other general intangibles directly relating to or arising out of, and accessions and improvements to, property or assets subject to such Liens, so long as such Lien on such property or assets is permitted by this Section 6.01.

     Section 6.02. Financial Covenants.

     (a) Leverage Ratio. The Company shall not permit the ratio of (i) the sum of (A) the aggregate amount of consolidated Debt of the Company and its consolidated Subsidiaries, plus (B) the aggregate amount of consolidated Guaranties of the Company and its consolidated Subsidiaries, plus (C) the outstanding principal (or equivalent) amount of financing extended to the Company and its consolidated Subsidiaries pursuant to any Alternate Program, regardless of whether such financing gives rise to “Indebtedness” hereunder, minus (D) all unrestricted cash balances of the Company and its consolidated Subsidiaries (in each case, without duplication of amounts under this clause (i) and determined as to all of the foregoing entities on a consolidated basis) (it being understood that cash balances in the Qualified Investments Account or any Qualified Investments Subaccount are not restricted for purposes of this clause (D) minus (E) all restricted cash balances of the Company and its consolidated Subsidiaries securing or otherwise supporting the payment of Debt or Guaranties of the Company and its consolidated Subsidiaries included in (A) above to (ii) Consolidated EBITDA of the Company and its consolidated Subsidiaries for the then most recently ended period of four fiscal quarters to exceed (x) 5.50:1 at any time prior to June 30, 2008 and (y) 5.25:1 at any time on or after June 30, 2008.

     (b) Fixed Charge Coverage Ratio. The Company shall not permit the ratio of (i) Consolidated EBITDA of the Company and its consolidated Subsidiaries for the then most recently ended period of four fiscal quarters to (ii) the sum of its consolidated interest expense plus its total dividends paid, in each case for the then most recently ended period of four fiscal quarters to be less than (x) 1.75:1 at any time prior to June 30, 2008 and (y) 2.0:1 at any time on or after June 30, 2008.

     Section 6.03. Debt. No Pipeline Company Borrower and no Subsidiary of a Pipeline Company Borrower shall incur or become liable for any Debt (other than loans from a FERC-Regulated Restricted Subsidiary that are subordinated to the Obligations pursuant to Acceptable Subordination Provisions and the proceeds of which are used to make a Qualified Investment or fund working capital) or any liability under Guaranties if, immediately after giving effect to such Debt or liability under such Guaranties and the receipt and application of any proceeds thereof (or of any Debt so guaranteed) or value received in connection therewith, (i) the ratio of Debt (excluding loans from a FERC-Regulated Restricted Subsidiary that are subordinated to the Obligations pursuant to Acceptable Subordination Provisions and the proceeds of which are used to make a Qualified Investment or fund working capital) and liabilities under Guaranties, without duplication, of the applicable Pipeline Company Borrower and its consolidated Subsidiaries to Consolidated EBITDA of such Pipeline Company Borrower and its consolidated Subsidiaries, in each case on a consolidated basis for the applicable Pipeline Company Borrower and its consolidated Subsidiaries, for the then most recently completed four quarter period for which

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financial statements have been delivered as required by Section 5.08 would exceed 5 to 1, or (ii) the proceeds of any such Debt (or of the underlying Debt guaranteed by any such Guaranty) would be used for any purpose other than (A) the funding of working capital of the applicable Pipeline Company Borrower or Subsidiary, (B) the successive refinancing of Debt incurred to fund working capital, (C) the making of Qualified Investments or (D) the refinancing or replacement of Debt.

     Section 6.04. Disposition of Property or Assets.

     (a) The Company shall not, and shall not permit any Credit Related Party to, Dispose of any interest in any asset or property constituting Collateral, except (i) in connection with a change in form of Business Entity that does not (x) result in a Person other than a Credit Related Party owning any Equity Interests in the resulting Business Entity or (y) adversely affect the validity, perfection or priority of the Transaction Liens on any of the Collateral, (ii) any Disposition that is the result of any casualty or condemnation of Collateral or any order (whether or not having the force of law) of the FERC or any other Governmental Authority with respect to such Collateral, so long as the Commitments shall be permanently reduced to the extent required by Section 2.07(d), (iii) Dispositions of Collateral in a transaction permitted by Section 6.05 and (iv) Dispositions of direct or indirect equity interests in the Pipeline Company Borrowers to either (x) MLP or a Subsidiary of MLP (including intermediate inter-company transfers in connection therewith) or (y) a Person other than the Company or a Subsidiary of the Company, in any such case on an arm’s-length basis (as reasonably determined by the Company), provided that the sum of the effective percentage interest in TGPC so Disposed of plus the effective percentage interest in EPNGC so Disposed of shall not exceed 15%.

     (b) The Company shall not, and shall not permit any Credit Related Party to, Dispose of any property or asset, provided that this Section 6.04(b) shall not apply to:

     (i) Dispositions of property or assets (other than Dispositions of Collateral) by Restricted Subsidiaries not otherwise permitted pursuant to any other provision of this Section 6.04, provided that (x) any such Disposition is conducted on an arms-length basis, (y) except in the case of any such Disposition to MLP or a Subsidiary of MLP (including intermediate inter-company transfers in connection therewith), the consideration for such Disposition does not consist of Equity Interests or Indebtedness, and (z) if the Net Cash Proceeds of such Disposition exceed $5,000,000 on an individual basis or $10,000,000 in the aggregate during any fiscal year of the Company, the Commitments shall be permanently reduced to the extent required by Section 2.07(d);

     (ii) Dispositions not otherwise permitted pursuant to any other provision of this Section 6.04 (other than clause (i) above) and that result from any casualty or condemnation of any property or assets of any Restricted Subsidiary or any order (whether or not having the force of law) of the FERC or any other Governmental Authority, provided that, if the Net Cash Proceeds of such Disposition exceed $5,000,000 on an individual basis or $10,000,000 in the aggregate during any fiscal year of the Company, the Commitments shall be permanently reduced to the extent required by Section 2.07(d);

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     (iii) Dispositions of obsolete or worn out property or assets (or property or assets no longer useful in the business of the relevant Credit Related Party) in the ordinary course of business and leases or subleases of unused office or other space in the ordinary course of business;

     (iv) Dispositions of any receivables and related rights pursuant to any Alternate Program so long as immediately before and immediately after giving effect to such Disposition the Company is in compliance with Section 6.02(a);

     (v) Dispositions of any Project Financing Subsidiary and/or all or any part of any such Project Financing Subsidiary’s assets or property;

     (vi) Dispositions of property or assets to a Restricted Subsidiary, or to a Business Entity that after giving effect to such Disposition will become a Restricted Subsidiary in which the Company’s direct or indirect Equity Interest will be at least as great as its direct or indirect Equity Interest in the transferor immediately prior to such Disposition;

     (vii) Dispositions permitted by, and subject to the terms of, Section 6.04(a) and Dispositions permitted by Section 6.05;

     (viii) the Disposition of EPEC Realty, Inc.;

     (ix) Dispositions of inventory in the ordinary course of business;

     (x) Dispositions constituting licenses of intellectual property in the ordinary course of business;

     (xi) Dispositions of cash or Cash Equivalents (other than cash or Cash Equivalents constituting Collateral under the Security Agreement or an amount equal to proceeds of any Disposition permitted pursuant to clauses (i) and (ii) above in excess of the applicable threshold amounts specified therein, which such cash or Cash Equivalents shall be Disposed of pursuant to the terms and provisions of this Agreement and the Security Agreement);

     (xii) Dispositions of Indebtedness or instruments or other obligations that are received as consideration for any Disposition of property or assets (other than Dispositions permitted pursuant to clauses (i) and (ii) above);

     (xiii) Dispositions of investments (including Equity Interests and Indebtedness or instruments or other obligations) that are received in connection with the bankruptcy or reorganization of suppliers, customers or other Persons, or in settlement of, or pursuant to any judgment or other order in respect of, delinquent obligations of, or litigation proceedings or other disputes with, or from exercises of rights or remedies against, any such Persons;

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     (xiv) Dispositions by the Company or by any Exempted Guarantor on an arm’s-length basis (as reasonably determined by the Company) of any property or assets that do not constitute Collateral; or

     (xv) Dispositions by the Company or its Subsidiaries on an arms-length basis (as reasonably determined by the Company) of Equity Interests in any Subsidiary of the Company; provided that the sale thereof shall not result in the Company owning directly or indirectly less than 100% of the Equity Interests in the Subsidiary Guarantors.

     (c) No Borrower shall Dispose of (in a single or related series of transactions) assets constituting all or substantially all of the consolidated assets of such Borrower and its Subsidiaries taken as a whole, provided that this Section 6.04(c) shall not apply to (i) any transaction permitted by Section 6.04(a), Section 6.04(b)(ii), (b)(vi), (b)(vii) or (b)(xiii) or Section 6.05 or (ii) any transaction required by a final order of any Governmental Authority of competent jurisdiction.

     Section 6.05. Mergers. The Company shall not, and shall not permit any other Credit Related Party to, merge or consolidate with, or liquidate into, any Person, except that, provided no Event of Default has occurred and is continuing (both before and immediately after giving effect to any merger, consolidation or liquidation permitted below):

     (a) any Credit Related Party (other than the Company) in addition to mergers, consolidations and liquidations provided for in clauses (b) and (c) below, may merge or consolidate with, or liquidate into, any other Credit Related Party (other than the Company), provided that (i) the continuing or surviving Credit Related Party unconditionally assumes by written agreement satisfactory to the Administrative Agent all of the performance and payment obligations of the other Credit Related Party under any Loan Documents to which it is a party and (ii) the Lien under the Security Documents in favor of the Collateral Agent on any Collateral owned by any applicable Subsidiary Guarantor immediately prior to such merger, consolidation or liquidation remains effective and perfected immediately thereafter with no loss of relative priority to any other class of creditor from that existing immediately prior to such merger, consolidation or liquidation; provided, however, that any Pledged Company shall be permitted to merge with another Restricted Subsidiary, so long as the Equity Interests of the surviving Business Entity are subject to perfected Transaction Liens and neither the priority of such Liens nor the value of the Collateral is diminished as a result of such merger;

     (b) any Exempted Guarantor may merge or consolidate with, or liquidate into, any other Exempted Guarantor or other Business Entity that is not a Credit Related Party, provided that (i) the surviving Business Entity is, directly or indirectly, a wholly-owned Subsidiary of the Company and remains a Subsidiary Guarantor, (ii) if the Exempted Guarantor is not the continuing or surviving Business Entity, the continuing or surviving Business Entity unconditionally assumes by written agreement satisfactory to the Administrative Agent all of the obligations of such Exempted Guarantor under the Loan Documents to which the applicable Exempted Guarantor is a party and (iii) the Lien under the Security Documents in favor of the Collateral Agent on any Collateral owned by the applicable Exempted Guarantor immediately prior to such merger, consolidation or liquidation remains effective and perfected immediately

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thereafter with no loss of relative priority to any other class of creditor from that existing immediately prior to such merger, consolidation or liquidation; and

     (c) the Company may merge or consolidate with, or liquidate into, any Business Entity other than a Credit Related Party, provided that (i) (A) the Company is the continuing or surviving Business Entity or (B) the continuing or surviving Business Entity is organized under the laws of the United States or a State thereof and unconditionally assumes by written agreement satisfactory to the Administrative Agent all of the performance and payment obligations of the Company under any Loan Documents to which it is a party, and (ii) the Lien under the Security Documents in favor of the Collateral Agent on any Collateral owned by the Company immediately prior to such merger, consolidation or liquidation remains effective and perfected immediately thereafter with no loss of relative priority to any other class of creditor (either contractually, by structural subordination or otherwise) from that existing immediately prior to such merger, consolidation or liquidation.

     Section 6.06. Use of Proceeds. No Borrower shall use the proceeds of any Loan or any Letter of Credit for any purpose that would (a) whether directly or indirectly, entail a violation of any of the Regulations of the Board of Governors, including Regulations T, U and X or (b) constitute a use other than a general corporate purpose (it being understood that the payments to be made to Departing Lenders pursuant to Section 3.01(d)(ii) shall constitute a permitted use of proceeds pursuant to this Section 6.06).

     Section 6.07. Transactions with Affiliates. No Credit Related Party (other than an Exempted Guarantor) will sell, lease or otherwise transfer any property to, or purchase, lease or otherwise acquire any property from, or otherwise engage in any other transaction with, any Affiliate of the Company that is not a Subsidiary of the Company, whether or not in the ordinary course of business, except (a) transactions on terms no less favorable to such Credit Related Party as would be obtainable by such Credit Related Party at the time in a comparable arm’s-length transaction or series of transactions with a person other than an Affiliate of the Company, (b) any Disposition permitted under Section 6.04 or any merger, consolidation or liquidation permitted under Section 6.05 and (c) transactions the value of which are de minimis in relation to the assets, liabilities or revenues of the Credit Related Party engaging in such transaction.

     Section 6.08. Restrictive Agreements. No Credit Related Party will, directly or indirectly, enter into or permit to exist any agreement or other arrangement that prohibits, restricts or imposes any condition on (a) the ability of any Credit Related Party (other than the Company or the Exempted Guarantor) to create or permit to exist any Lien on any of its property or (b) the ability of any Restricted Subsidiary or Pipeline Company Borrower to pay dividends or other distributions with respect to any shares of its capital stock or to make or repay loans or advances to the Company or any Subsidiary Guarantor or to Guarantee Debt of the Company or any Subsidiary Guarantor or to otherwise transfer assets to or invest in the Company or any Subsidiary Guarantor; provided that (i) the foregoing shall not apply to restrictions and conditions imposed by law or by any Loan Document, (ii) the foregoing shall not apply to restrictions and conditions existing on the date hereof and identified on Schedule 6.08, or any extension, refinancing or renewal thereof on market terms and conditions, (iii) the foregoing shall not apply to customary restrictions and conditions contained in agreements relating to the sale of a Subsidiary pending such sale, provided that such restrictions and conditions apply only

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to the Subsidiary that is to be sold and such sale is permitted hereunder, (iv) clause (a) of this Section shall not apply to restrictions or conditions imposed by any agreement relating to secured Debt permitted by this Agreement if such restrictions or conditions apply only to the property securing such Debt, (v) clause (a) of this Section shall not apply to customary provisions in leases and other contracts entered into in the ordinary course of business restricting the assignment thereof, (vi) the foregoing shall not apply to any Pipeline Company Borrower or its Subsidiary in connection with the issuance of debt otherwise permitted hereunder on market-clearing terms that are no less favorable to such Pipeline Company Borrower or its Subsidiary than the Reference Indenture and (vii) clause (a) and (b) of this Section shall not apply to any assets that are the subject of an Alternate Program or to any Restricted Subsidiary whose only activities are to purchase receivables from a Pipeline Company Borrower or a Subsidiary of a Pipeline Company Borrower and resell such receivables, in each case pursuant to an Alternate Program.

ARTICLE 7
Events of Default

     If any of the following events (“Events of Default”) shall occur and be continuing:

     (a) Any Borrower shall fail to pay any installment of principal of any of its Loans or Notes when due, or any interest on any of its Loans or Notes or any other amount payable by it hereunder within five Business Days after the same shall be due; or

     (b) Any representation or warranty made or deemed made by any Credit Party herein or by any Credit Party (or any of its officers) in connection with this Agreement shall prove to have been incorrect in any material respect when made or deemed made and, if such representation or warranty is capable of being cured, such inaccuracy shall remain unremedied for 30 days after written notice thereof shall have been given to such Credit Party by the Administrative Agent or by any Lender with a copy to the Administrative Agent; or

     (c) Any Credit Party shall fail to perform or observe any term, covenant, or agreement applicable to it contained in Section 5.01(a) or 5.08(g) or Article 6; or

     (d) Any Credit Party shall fail to perform or observe any other term, covenant or agreement contained in the Loan Documents (other than those specified in paragraphs (a) through (c) above) on its part to be performed or observed and any such failure shall remain unremedied for 30 days after written notice thereof shall have been given to such Credit Party by the Administrative Agent or by any Lender with a copy to the Administrative Agent; or

     (e) The Company or any consolidated Subsidiary shall fail to pay any Debt or Guaranty (excluding Debt and Guarantees incurred pursuant hereto) or Hedging Agreement of such Person in an aggregate principal amount of $200,000,000 or more, or any installment of principal thereof or interest or premium thereon, when due (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise) and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Debt, Guaranty or Hedging Agreement; or any other default under any agreement or instrument

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relating to any such Debt in such aggregate principal amount (excluding Debt and Guarantees incurred hereunder) or any Secured Hedging Agreement, or any other event (other than an exercise of voluntary prepayment or voluntary purchase option or analogous right or any issuance or Disposition of Equity Interests or other assets, or an incurrence or issuance of Debt or other obligations, giving rise to a repayment or prepayment obligations in respect of such Debt or such Secured Hedging Agreement), shall occur and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such default or event is to accelerate the maturity of such Debt in such aggregate principal amount or such Secured Hedging Agreement; or

     (f) • Any Borrower, any Guarantor or any other Credit Related Party (other than any Borrower or Guarantor) having total Assets in excess of $100,000,000 (any of the foregoing, a “Material Credit Related Party”) shall generally not pay its debts as such debts become due; or admit in writing its inability to pay its debts generally; or make a general assignment for the benefit of creditors; or any proceeding shall be instituted or consented to by any Material Credit Related Party seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, or other similar official for it or for any substantial part of its property; or any such proceeding shall have been instituted against any Material Credit Related Party and either such proceeding shall not be stayed or dismissed for 60 consecutive days or any of the actions referred to above sought in such proceeding (including the entry of an order for relief against it or the appointment of a receiver, trustee, custodian or other similar official for it or any substantial part of its property) shall occur; or any Material Credit Related Party shall take any corporate action to authorize any of the actions set forth above in this paragraph (f); or

     (g) Any final judgment or order for the payment of money in an aggregate amount in excess of $100,000,000 (net of insurance coverage which is reasonably expected to be paid by the insurer) shall be rendered against the Company, any Credit Related Party or any combination thereof and the same shall remain undischarged for a period of 60 consecutive days during which execution (other than any enforcement proceedings consisting of the mere obtaining and filing of a judgment lien or obtaining of a garnishment or similar order so long as no foreclosure, levy or similar process in respect of such judgment lien, or payment over in respect of such garnishment or similar order, has commenced and is continuing or has been completed (collectively, the “Permitted Execution Actions”)) shall not be effectively stayed, or any action, other than a Permitted Execution Action, shall be legally taken by a judgment creditor to attach or levy upon any property or assets of the Company or any other Credit Related Party to enforce any such judgment or order; provided, however, that with respect to any such judgment or order that is subject to the terms of one or more settlement agreements that provide for the obligations thereunder to be paid or performed over time, such judgment or order shall not be deemed hereunder to be undischarged unless and until the Company or any other Credit Related Party shall have failed to pay any amounts due and owing thereunder (payment of which shall not have been stayed) for a period of 30 consecutive days after the respective final due dates for the payment of such amounts; or

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     (h) Any Termination Event with respect to a Plan shall have occurred and, 30 days after notice thereof shall have been given to the Company by the Administrative Agent, such Termination Event shall still exist; or the Company or any ERISA Affiliate shall have been notified by the sponsor of a Multiemployer Plan that it has incurred Withdrawal Liability to such Multiemployer Plan; or the Company or any ERISA Affiliate shall have been notified by the sponsor of a Multiemployer Plan that such Multiemployer Plan is in reorganization, or is insolvent or is being terminated, within the meaning of Title IV of ERISA; or any Person shall engage in a “prohibited transaction” (as defined in Section 406 of ERISA or Section 4975 of the Code) involving any Plan; and in each case in clauses (i) through (iv) above, such event or condition, together with all other such events or conditions, if any, would result in an aggregate liability of the Company or any ERISA Affiliate that would have a Material Adverse Effect; or

     (i) At any time (i) any “person” (within the meaning of Section 13(d) of the Securities Exchange Act of 1934) other than the Company or a Subsidiary of the Company or any employee benefit plan maintained for employees of the Company and/or any of its Subsidiaries or the trustee therefor, shall have acquired direct or indirect ownership of and paid for in excess of 50% of the outstanding capital stock of the Company entitled to vote in elections for directors of the Company or (ii) more than half of members of the Board of Directors of the Company consists of individuals who (1) were not members of the Board of Directors of the Company at the Effective Date and (2) were not appointed, elected or nominated by the Board of Directors of the Company at a time when no Event of Default existed under this clause (ii); or

     (j) Any of the guarantees contained in any Credit Party Guarantee, or any other material provision of any Loan Document, shall cease, for any reason, to be valid and binding upon or enforceable against any Credit Party that is a party thereto, or any such Credit Party shall so assert in writing, provided that if such invalidity or unenforceability is of a nature so as to be amenable to cure within five Business Days and if, within one Business Day after the Company receives notice from the Administrative Agent or the Collateral Agent or otherwise becomes aware that such material provision is not valid or is unenforceable as aforesaid, the Company delivers written notice to the Administrative Agent that the applicable Credit Party intends to cure such invalidity or unenforceability as soon as possible, then an Event of Default shall not exist pursuant to this paragraph (k) of Article 7 unless the Company or the relevant Credit Party shall fail to deliver or cause to be delivered an amendment or other modification, or other agreement or undertaking, having the same economic effect as the invalid or unenforceable provision within four Business Days after the delivery of such written notice of intent; or

     (k) Any Security Document shall for any reason fail or cease to create a valid and enforceable Lien on any Collateral stated to be covered thereby or, except as permitted by the Loan Documents, such Lien shall fail or cease to be a perfected and first-priority (subject only to Collateral Permitted Liens) Lien, or any Credit Related Party shall so state in writing and, if such invalidity or lack of perfection or priority relates solely to Collateral with an aggregate value of $1,000,000 or less and such invalidity or lack of perfection or priority is such so as to be amenable to cure without material disadvantage to the position of the Administrative Agent, the Collateral Agent and the other Secured Parties, such invalidity or lack of perfection or priority shall not be cured within 10 days of the earlier of such Credit Related Party so stating in writing or delivery of notice thereof by the Administrative Agent to the Company (or such shorter period as shall be specified by the Administrative Agent and is reasonable under the circumstances);

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then, and in every such event (other than an event with respect to any Credit Related Party described in paragraph (f) of this Article except for clause (i)(A) thereof), and at any time thereafter during the continuance of such event, the Administrative Agent may, and at the request of the Majority Lenders shall, by notice to the Company, take either or both of the following actions, at the same or different times: (i) declare the Commitments to be terminated and thereupon the Commitments shall terminate immediately, and (ii) declare the Loans and the Notes then outstanding, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable in whole (or in part, in which case any principal not so declared to be due and payable may thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable together with accrued interest thereon and all fees and other obligations of the Borrowers accrued hereunder, shall become due and payable immediately, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrowers; provided, however, that if an Event of Default under paragraph (f) (except under clause (i)(A) thereof) shall occur, (A) the Commitments shall automatically terminate and (B) the principal of the Loans and the Notes then outstanding, together with accrued interest thereon and all fees and other obligations of the Borrowers accrued hereunder shall automatically become due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrowers.

ARTICLE 8
Company Guarantee

     Section 8.01. Company Guarantee.

     (a) The Company hereby unconditionally and irrevocably guarantees to the Collateral Agent, for the ratable benefit of the Secured Parties and each of their respective permitted successors, endorsees, transferees and assigns, the prompt and complete payment by the Pipeline Company Borrowers when due (whether at the stated maturity, by acceleration or otherwise) of the Obligations payable by any of them and the prompt and complete payment by the Subsidiary Guarantors when due (whether at the stated maturity, by acceleration or otherwise) of all amounts payable by them under the Subsidiary Guarantee Agreement (the obligations described in the foregoing clauses (i) and (ii) being herein referred to as the “Company Guaranteed Obligations”). This is a guarantee of payment and not collection and the liability of the Company is primary and not secondary.

     (b) The guarantee contained in this Article 8 shall remain in full force and effect until the Final Payment Date, notwithstanding that from time to time during the term of this Agreement, no Company Guaranteed Obligations may be outstanding.

     (c) No payment made by any Pipeline Company Borrower, any of the Subsidiary Guarantors, any other guarantor or any other Person, or received or collected by any Agent or any Lender from any Pipeline Company Borrower, any of the Subsidiary Guarantors, any other guarantor or any other Person, by virtue of any action or proceeding or any set-off or appropriation or application at any time or from time to time in reduction of or in payment of the Obligations shall be deemed to modify, reduce, release or otherwise affect the liability of the

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Company hereunder which shall, notwithstanding any such payment (other than any payment made by the Company in respect of the Company Guaranteed Obligations or any payment received or collected from the Company in respect of the Company Guaranteed Obligations), remain liable for the Company Guaranteed Obligations until the Final Payment Date.

     Section 8.02. No Subrogation. Notwithstanding any payment made by any Pipeline Company Borrower hereunder, the Company under this Article 8 or the Parent Guarantee or any Subsidiary Guarantor under the Subsidiary Guarantee Agreement or any set-off or application of funds of any Pipeline Company Borrower or any Subsidiary Guarantor by any Agent or any Lender, the Company shall not be entitled to be subrogated to any of the rights of any Agent or any Lender against any Pipeline Company Borrower or any Subsidiary Guarantor or any collateral security or guarantee or right of offset held by any Agent or any Lender for the payment of the Company Guaranteed Obligations, nor shall the Company seek or be entitled to seek any contribution or reimbursement from any Pipeline Company Borrower or any Subsidiary Guarantor in respect of payments made by the Company hereunder, until the Final Payment Date. If any amount shall be paid to the Company on account of such subrogation rights prior to the Final Payment Date, such amount shall be held by the Company in trust for the Agents and the Lenders, segregated from other funds of the Company, and shall, forthwith upon receipt by the Company, be turned over to the Administrative Agent in the exact form received by the Company (duly indorsed by the Company to the Administrative Agent, if required), to be applied against the Company Guaranteed Obligations, whether matured or unmatured), in such order as the Administrative Agent may determine but subject in any event to the terms and provisions of this Agreement and the Security Agreement.

     Section 8.03. Amendments, etc. with Respect to the Obligations. The Company shall remain obligated hereunder notwithstanding that, without any reservation of rights against the Company and without notice to or further assent by the Company, any demand for payment of any of the Company Guaranteed Obligations made by any Agent or any Lender may be rescinded by such Agent or such Lender and any of the Company Guaranteed Obligations continued, and the Company Guaranteed Obligations, or the liability of any other Person upon or for any part thereof, or any collateral security or guarantee therefor or right of offset with respect thereto, may, from time to time, in whole or in part, be renewed, extended, amended, modified, accelerated, compromised, waived, surrendered or released by any Agent or any Lender, and this Agreement and the other Loan Documents and any other documents executed and delivered in connection therewith may be amended, modified, supplemented or terminated, in whole or in part, as the Administrative Agent (or the Majority Lenders or all Lenders, as the case may be) may deem advisable from time to time, and any collateral security, guarantee or right of offset at any time held by any Agent or any Lender for the payment of the Company Guaranteed Obligations may be sold, exchanged, waived, surrendered or released. Neither the Administrative Agent, the Collateral Agent nor any Lender or other Secured Party shall have any obligation to protect, secure, perfect or insure any Lien at any time held by it as security for the Company Guaranteed Obligations or for the guarantee contained in this Article 8 or any property subject thereto.

     Section 8.04. Guarantee Absolute and Unconditional. The Company waives any and all notice of the creation, renewal, extension or accrual of any of the Company Guaranteed Obligations and notice of or proof of reliance by any Agent or any Lender upon the guarantee

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contained in this Article 8 or acceptance of the guarantee contained in this Article 8; the Company Guaranteed Obligations, and any of them, shall conclusively be deemed to have been created, contracted or incurred, or renewed, extended, amended or waived, in reliance upon the guarantee contained in this Article 8; and all dealings between the Company, any of the Pipeline Company Borrowers and any Subsidiary Guarantor, on the one hand, and the Agents and the Lenders, on the other hand, likewise shall be conclusively presumed to have been had or consummated in reliance upon the guarantee contained in this Article 8. The Company waives diligence, presentment, protest, demand for payment and notice of default or nonpayment to or upon the Pipeline Company Borrowers or any of the Subsidiary Guarantors with respect to the Company Guaranteed Obligations. The Company understands and agrees that the guarantee contained in this Article 8 shall be construed as a continuing, absolute and unconditional guarantee of payment without regard to (a) the validity or enforceability of this Agreement or any other Loan Document, any of the Company Guaranteed Obligations or any other collateral security therefor or guarantee or right of offset with respect thereto at any time or from time to time held by any Agent or any Lender, (b) any defense, set-off or counterclaim (other than a defense of payment or performance) which may at any time be available to or be asserted by any Pipeline Company Borrower, any Subsidiary Guarantor or any other Person against any Agent or any Lender, or (c) any other circumstance whatsoever (with or without notice to or knowledge of the Pipeline Company Borrowers, the Subsidiary Guarantors or the Company), other than payment or performance, which constitutes, or might be construed to constitute, an equitable or legal discharge of Pipeline Company Borrowers or the Subsidiary Guarantors for the Company Guaranteed Obligations, or of the Company under the guarantee contained in this Article 8, in bankruptcy or in any other instance. When making any demand hereunder or otherwise pursuing its rights and remedies hereunder against the Company, any Agent or any Lender may, but shall be under no obligation to, make a similar demand on or otherwise pursue such rights and remedies as it may have against any Pipeline Company Borrower, any Subsidiary Guarantor or any other Person or against any collateral security or guarantee for the Company Guaranteed Obligations or any right of offset with respect thereto, and any failure by any Agent or any Lender to make any such demand, to pursue such other rights or remedies or to collect any payments from any Pipeline Company Borrower, any Subsidiary Guarantor or any other Person or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of any Pipeline Company Borrower, any Subsidiary Guarantor or any other Person or any such collateral security, guarantee or right of offset, shall not relieve the Company of any obligation or liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of any Agent or any Lender against the Company. For the purposes hereof “demand” shall include the commencement and continuance of any legal proceedings.

     Section 8.05. Reinstatement. The guarantee contained in this Article 8 shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Company Guaranteed Obligations is rescinded or must otherwise be restored or returned by any Agent or any Lender upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Company, any Pipeline Company Borrower or any Subsidiary Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Company, any Pipeline Company Borrower or any Subsidiary Guarantor or any substantial part of its or their respective property, or otherwise, all as though such payments had not been made.

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ARTICLE 9
The Agents

     Each of the Lenders and each Issuing Bank hereby irrevocably appoints each of the Administrative Agent and the Collateral Agent as its agent and authorizes each of the Administrative Agent and the Collateral Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent and the Collateral Agent by the terms hereof and of the other Loan Documents, together with such actions and powers as are reasonably incidental thereto.

     Any bank serving as an Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrowers or any Subsidiary or other Affiliate thereof as if it were not an Agent hereunder.

     No Agent shall not have any duties or obligations except those expressly set forth herein or in the Security Agreement. Without limiting the generality of the foregoing, (a) no Agent shall be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing, (b) no Agent shall have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby that such Agent is required to exercise in writing as directed by the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 10.02), and (c) except as expressly set forth herein, no Agent shall have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrowers or any of their Subsidiaries that is communicated to or obtained by the bank serving as an Agent or any of its Affiliates in any capacity. No Agent shall be liable for any action taken or not taken by it with the consent or at the request of the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 10.02) or in the absence of its own gross negligence or willful misconduct. No Agent shall be deemed to have knowledge of any Default unless and until written notice thereof is given to such Agent by a Borrower or a Lender, and no Agent shall be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement, (ii) the contents of any certificate, report or other document delivered hereunder or in connection herewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement or any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in Article 3 or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent.

     Each Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person. Each Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon. Each Agent may consult with legal counsel (who may be counsel for a Credit Party), independent accountants and

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other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

     Any Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by such Agent. Any Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties. The exculpatory provisions of the preceding paragraphs shall apply to any such sub-agent and to the Related Parties of any Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as an Agent.

     Subject to the appointment and acceptance of a successor Administrative Agent or Collateral Agent as provided in this paragraph, each of the Administrative Agent and the Collateral Agent may resign at any time by notifying the Lenders, each Issuing Bank and the Company. Upon any such resignation, the Majority Lenders shall have the right, in consultation with the Company, to appoint a successor. If no successor shall have been so appointed by the Majority Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives notice of its resignation, then the retiring Agent may, on behalf of the Lenders and each Issuing Bank, appoint a successor Agent which shall be a bank with an office in New York, New York, or an Affiliate of any such bank. Upon the acceptance of its appointment as Administrative Agent or Collateral Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations hereunder. The fees payable by the Borrowers to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Company and such successor. After an Agent’s resignation hereunder, the provisions of this Article and Section 10.03 shall continue in effect for the benefit of such retiring Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while it was acting as Administrative Agent or Collateral Agent.

     Each Lender acknowledges that it has, independently and without reliance upon any Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon any Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any related agreement or any document furnished hereunder or thereunder.

ARTICLE 10
Miscellaneous

     Section 10.01. Notices. (a) Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to paragraph (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

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     (i) if to the Company, to it at El Paso Building, 1001 Louisiana Street, Houston, Texas 77002, Attention of Treasurer (Telecopy No. (713) 420-2708);

     (ii) if to EPNGC or TGPC, to it c/o the Company at the address specified in clause (i) above;

     (iii) if to the Administrative Agent, to:

(iv) JPMorgan Chase Bank, N.A.

Technology, Shared Tech & Operation Commercial Loans
L&A Project Texas
1111 Fannin, Floor 10
Houston, TX 77002
Attention of Ina S. Tjahjono
Telecopy No. (713) 427-6307

with a copy to:

JPMorgan Chase Bank, N.A.
712 Main St, 12 Fl. Central
Houston, TX 77002
Attention of Robert Traband
Telecopy No. (713) 216-8870

(v) if to the Collateral Agent, to:

(vi) JPMorgan Chase Bank, N.A.

Institutional Trust Services
4 New York Plaza, 15^th Floor
New York, NY 10004
Attention of International/Project Finance, James Foley
Telecopy No. (212) 623-6216

with a copy to:

JPMorgan Chase Bank, N.A.
712 Main St, 12 Fl. Central
Houston, TX 77002
Attention of Robert Traband
Telecopy No. (713) 216-8870

     (vii) if to JPMCB in its capacity as an Issuing Bank, to it at JPMorgan Chase Bank, N.A., 10420 Highland Manor Drive, 4th Floor, Tampa Bay, Florida 33610, Attention of James Alonzo, Telecopy No. (813) 432-5161;

     (viii) if to Citibank in its capacity as an Issuing Bank, to it at Citibank, N.A., 333 Clay Street / Suite 3700, Houston, TX 77002, Attention of Nan Dockal, Telecopy No. (713) 654-2849;

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     (ix) if to any other Lender in its capacity as an Issuing Bank, to it at the address provided to the Company for notices to such Issuing Bank in such capacity; and

     (x) if to any other Lender, to it at its address (or telecopy number) set forth in its Administrative Questionnaire.

     (b) Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to Article 2 unless otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent or a Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

     (c) Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given and effective, if sent by mail or courier on the date of delivery thereof to the address specified herein for such notice, or if by telecopier when the answerback is received or if by other means, on the date of receipt; provided that a notice given by telecopier or electronic communication in accordance with this Section 10.01 but received on any day other than a Business Day or after business hours in the place of receipt, will be deemed to be received on the next Business Day in that place.

     Section 10.02. Waivers; Amendments. (a) No failure or delay by any Agent, any Issuing Bank or any Lender in exercising any right or power hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Agents, each Issuing Bank and the Lenders hereunder are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or consent to any departure by any Borrower therefrom shall in any event be effective unless the same shall be permitted by paragraph (b) of this Section, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. Without limiting the generality of the foregoing, the making of a Loan or issuance of a Letter of Credit shall not be construed as a waiver of any Default, regardless of whether any Agent, any Lender or any Issuing Bank may have had notice or knowledge of such Default at the time.

     (b) Except as expressly provided herein or in the applicable Loan Document, no provision of this Agreement or any other Loan Document may be waived, amended or modified, and no consent may be granted with respect to any departure by the Administrative Agent, any Lender or any Credit Party with respect hereto or thereto, except pursuant to an agreement or agreements in writing entered into by the Borrowers and the Majority Lenders or by the Borrowers and the Administrative Agent with the consent of the Majority Lenders; provided that no such waiver, amendment or modification of this Agreement or any other Loan Document, and no consent with respect to any departure by the Administrative Agent, any Lender, or any Credit Party with respect hereto or thereto, shall:

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     (i) increase the Commitment of any Lender, without the written consent of such Lender;

     (ii) reduce or forgive the principal amount of any Loan or LC Disbursement or reduce the rate of interest thereon, or reduce any fees payable hereunder, without the written consent of each Lender affected thereby;

     (iii) postpone the scheduled date of payment of the principal amount of any Loan or LC Disbursement, or any interest thereon, or any fees payable hereunder, or reduce the amount of, waive or excuse any such payment, or postpone the scheduled date of expiration of any Commitment, without the written consent of each Lender affected thereby;

     (iv) issue any Letter of Credit with an expiration date, or extend the expiration date of any Letter of Credit, to a date that is later than the fifth Business Days prior to the Revolving Maturity Date, without the written consent of each Revolving Lender and the Issuing Bank of such Letter of Credit;

     (v) change Section 2.16(b) or 2.16(c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender;

     (vi) release any Subsidiary Guarantor from its obligations under the Subsidiary Guarantee Agreement, without the written consent of each Lender, except in connection with the Disposition or merger of such Subsidiary Guarantor that is otherwise permitted hereunder;

     (vii) release the Company from its guarantee obligations under Article 8, without the written consent of each Lender;

     (viii) release all or substantially all of the Collateral, without the written consent of each Lender; or

     (ix) change any of the provisions of this Section or the definitions of “Majority Lenders”, or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or make any determination or grant any consent hereunder, without the written consent of each Lender;

provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of any Agent or any Issuing Bank hereunder or under any other Loan Document without the prior written consent of such Agent or such Issuing Bank, as the case may be. Any such waiver and any such amendment or modification shall apply equally to each of the Lenders and shall be binding upon the Borrowers, the Lenders, the Issuing Banks and the Agents. In the case of any waiver, the Borrower, the Lenders, the Issuing Banks and the Agents shall be restored to their former position and rights hereunder and under the other Loan Documents, and any Default or Event of Default waived shall be deemed waived ab initio and not continuing unless such waiver expressly provides otherwise; but no such waiver shall extend to any subsequent or other Default or Event of Default; and provided further that, in addition to Dispositions of Collateral permitted by Section 6.04(a), the Majority Lenders may consent to additional Dispositions of

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Collateral so long as each such Disposition is for fair market value on an arms-length basis in a cash transaction.

     Section 10.03. Expenses; Indemnity; Damage Waiver. (a) The Company shall pay (i) all reasonable out-of-pocket expenses incurred by the Administrative Agent and its Affiliates, including the reasonable fees, charges and disbursements of counsel for the Administrative Agent, in connection with the syndication of the credit facilities provided for herein, the preparation and administration of this Agreement or any amendments, modifications or waivers of the provisions hereof (whether or not the transactions contemplated hereby or thereby shall be consummated), (ii) all reasonable out-of-pocket expenses incurred by any Issuing Bank in connection with the issuance, amendment, renewal or extension of any Letter of Credit by it or any demand for payment thereunder made by such Issuing Bank (unless included in the fees charged separately by such Issuing Bank in respect of such Letter of Credit) and (iii) all out-of-pocket expenses incurred by any Agent, any Issuing Bank or any Lender, including the fees, charges and disbursements of any counsel for the Administrative Agent, any Issuing Bank or, during the continuation of any Default, any other Agent or any Lender, in connection with the enforcement or protection of its rights in connection with this Agreement, including its rights under this Section, or in connection with the Loans made or Letters of Credit issued hereunder, including all such out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans or Letters of Credit.

     (b) Each of the Borrowers shall indemnify, without duplication, each Agent, each Issuing Bank and each Lender, and each Related Party of any of the foregoing Persons (each such Person being called an “Indemnitee”) against, and hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related expenses, including the fees, charges and disbursements of any counsel for any Indemnitee, incurred by or asserted against any Indemnitee arising out of, in connection with, or as a result of (i) the execution or delivery of this Agreement or any agreement or instrument contemplated hereby, the performance by the parties hereto of their respective obligations hereunder or the consummation of the Transactions or any other transactions contemplated hereby, (ii) any Loan or Letter of Credit or the use of the proceeds therefrom (including any refusal by the applicable Issuing Bank to honor a demand for payment under a Letter of Credit issued by it in accordance with applicable law if the documents presented in connection with such demand do not strictly comply with the terms of such Letter of Credit), (iii) any actual or alleged presence or release of Hazardous Materials on or from any property owned or operated by the Company or any of its Subsidiaries, or any Environmental Liability related in any way to the Company or any of its Subsidiaries, or (iv) any actual or prospective claim, litigation, investigation or proceeding relating to any of the foregoing, whether based on contract, tort or any other theory and regardless of whether any Indemnitee is a party thereto; provided that such indemnity shall not, in any of the foregoing circumstances as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses (i) are determined by a court of competent jurisdiction by final and nonappealable judgment to have resulted from or to have been attributable to the gross negligence or willful misconduct of such Indemnitee or its employees or agents or (ii) have arisen from a dispute between or among the Arrangers, the Administrative Agent or the Lenders or from a claim of an Indemnitee against another Indemnitee which in either case is not a direct or indirect result of any act or omission of the Borrowers or any of their subsidiaries. The indemnification provisions of this Section 10.03(b) are not intended to constitute a guaranty of payment of any

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principal, interest, facility or commitment fees, rental or other lease payments, or analogous amounts, under the Loans or any other Secured Obligations; provided that nothing in this Section 10.03(b) shall limit the liability of any Borrower for the payment of the Loans or any Secured Obligations, which liability arises under any other Loan Document, including any liability arising under this Agreement.

     (c) To the extent that any Borrower fails to pay any amount required to be paid by it to any Agent or any Issuing Bank under paragraph (a) or (b) of this Section, each Lender severally agrees to pay to such Agent or such Issuing Bank, as the case may be, such Lender’s pro rata share (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought based on the Commitments at such time, or if the Commitments have terminated or expired, based on the Credit Exposures at such time) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against such Agent or such Issuing Bank in its capacity as such.

     (d) To the extent permitted by applicable law, the Borrowers shall not and each Indemnitee, by its acceptance of any right to or benefit of indemnification under this Agreement and as a condition to its rights to and benefits of indemnification provided for herein, agrees that it shall not, assert, and hereby waives, any claim against any Indemnitee or any Borrower, respectively, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement or any agreement or instrument contemplated hereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof.

     (e) All amounts due under this Section shall be payable not later than 30 days after the delivery of written demand to the Company therefor.

     Section 10.04. Successors and Assigns. (a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of an Issuing Bank that issues any Letter of Credit), except that (i) the Borrowers may not assign or otherwise transfer any of their respective rights or obligations hereunder in a transaction not permitted hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by any Borrower without such consent shall be null and void), and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of an Issuing Bank that issues any Letter of Credit), Participants (to the extent provided in paragraph (c) of this Section) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, each Issuing Bank and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

     (b) (i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and its Loans (if any)) with the prior written consent (such consent not to be unreasonably withheld or delayed) of:

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     (A) the Company, provided that no consent of the Company shall be required for an assignment to a Lender, an Affiliate of a Lender, an Approved Fund (as defined below) or, if an Event of Default has occurred and is continuing, any other assignee; and

     (B) the Administrative Agent; and

     (C) each Issuing Bank.

     (ii) Assignments shall be subject to the following additional conditions:

     (A) except (i) in the case of an assignment to a Lender or an Affiliate of a Lender or an Approved Fund or an assignment of the entire remaining amount of the assigning Lender’s Commitment (or, if the applicable Commitment is not then in effect, the outstanding principal balance of the Loans of the assigning Lender subject to each such assignment) or (ii) if each of the Company (unless an Event of Default has occurred and is continuing) and the Administrative Agent otherwise consent, the amount of the Commitment (or, if the applicable Commitment is not then in effect, the outstanding principal balance of the Loans) of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall be $5,000,000 or any increment of $1,000,000 in excess thereof; provided that related Approved Funds shall be aggregated for purposes of such minimum assigned amount;

     (B) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

     (C) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500; provided that only one such fee shall be payable in connection with simultaneous assignments to or by two or more related Approved Funds;

     (D) the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire in which the assignee designates one or more individuals (each such individual, a “Credit Contact”) to whom all syndicate-level information (which may contain material non-public information about the Borrowers, the Credit Parties and their Related Parties or their respective securities) will be made available and who may receive such information in accordance with the assignee’s compliance procedures and applicable laws, including Federal and state securities laws; and

     (E) in the case of an assignment by a Lender to a CLO (as defined below) managed or administered by such Lender or an Affiliate of such Lender, the assigning Lender shall retain the sole right to approve any amendment, modification or waiver of any provision of this Agreement, provided that the

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Assignment and Assumption between such Lender and such CLO may provide that such Lender will not, without the consent of such CLO, agree to any amendment, modification or waiver described in the first proviso to Section 10.02(b) that affects such CLO.

     For the purposes of this Section 10.04(b), the terms “Approved Fund” and “CLO” have the following meanings:

     “Approved Fund” means, with respect to any Lender, (a) a CLO managed or administered by such Lender or an Affiliate of such Lender and (b) with respect to any Lender that is a fund which invests in bank loans and similar extensions of credit, any other fund that invests in bank loans and similar extensions of credit and is managed by the same investment advisor as such Lender or by an Affiliate of such investment advisor.

     “CLO” means, with respect to any Lender, any entity (whether a corporation, partnership, trust or otherwise) that is engaged in making, purchasing, holding or otherwise investing in bank loans and similar extensions of credit in the ordinary course and is administered or managed by such Lender or an Affiliate of such Lender.

     (iii) Subject to execution and delivery thereof and acceptance and recording thereof pursuant to paragraph (b)(iv) of this Section, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.13, 2.14, 2.15 and 10.03). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 10.04 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (c) of this Section.

     (iv) The Administrative Agent, acting for this purpose as an agent of the Borrowers, shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitment of, and principal amount of the Loans and LC Disbursements owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register as to the identity of the Lenders shall be conclusive, and as to the other items referred to above shall be conclusive absent manifest error, and the Borrowers, the Administrative Agent, each Issuing Bank and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Company, any Issuing Bank and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

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     (v) Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) of this Section and any written consent to such assignment required by paragraph (b) of this Section, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.

     (c) Any Lender may, without the consent of the Borrowers, the Administrative Agent, or any Issuing Bank, sell participations to one or more banks or other entities (a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it and Notes held by it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain the holder of its Notes (if any) for all purposes of this Agreement and shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrowers, the Administrative Agent, each Issuing Bank and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the first proviso to Section 10.02(b) that affects such Participant. Subject to paragraph (d) of this Section, the Borrowers agree that each Participant shall be entitled to the benefits of Sections 2.13, 2.14 and 2.15 with respect to its participations hereunder to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b) of this Section and provided that such Participant shall have complied with any obligation in respect thereof that it would have had as a Lender. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 10.08 as though it were a Lender, provided such Participant agrees to be subject to Section 2.16(c) as though it were a Lender.

     (d) A Participant shall not be entitled to receive any greater payment under Section 2.13 or 2.15 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Company’s prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.15 unless the Company is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrowers, to comply with Section 2.15(e) and (f) as though it were a Lender.

     (e) Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

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     Section 10.05. Survival. All covenants, agreements, representations and warranties made by the Borrowers herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Loans and issuance of any Letters of Credit, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent, any Issuing Bank or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as of the date made, or any date referred to therein, as applicable, (but without being deemed remade on or as of any subsequent date by reason of this Section 10.05) as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid or any Letter of Credit is outstanding and so long as the Commitments have not expired or terminated. The provisions of Sections 2.13, 2.14, 2.15 and 10.03 and Article 9 shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Letters of Credit and the Commitments or the termination of this Agreement or any provision hereof.

     Section 10.06. Counterparts; Integration; Effectiveness. This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. This Agreement and the other Loan Documents and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof. Except as provided in Section 3.01, this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Delivery of an executed counterpart of a signature page of this Agreement by telecopy shall be effective as delivery of a manually executed counterpart of this Agreement.

     Section 10.07. Severability. To the fullest extent permitted by applicable law any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

     Section 10.08. Right of Setoff. If an Event of Default shall have occurred and be continuing, subject to the terms and provisions of the Security Agreement and the other Loan Documents, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations at any time owing by such Lender or Affiliate to or for the credit or the account of a Borrower against any of and all the obligations of such Borrower now or hereafter existing under this

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Agreement held by such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement and although such obligations may be unmatured. The rights of each Lender under this Section are in addition to other rights and remedies (including other rights of setoff) which such Lender may have but are subject to the terms and provisions of the Security Agreement and the other Loan Documents.

     Section 10.09. Governing Law; Jurisdiction; Consent to Service of Process. (a) This Agreement shall be construed in accordance with and governed by the law of the State of New York.

     (b) Each Borrower hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the Supreme Court of the State of New York sitting in New York County and of the United States District Court of the Southern District of New York, and any appellate court from any thereof, in any action or proceeding by the Administrative Agent, the Collateral Agent any Issuing Bank or any Lender arising out of or relating to this Agreement, or for recognition or enforcement of any judgment obtained in any such action or proceeding, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State or, to the extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that the Administrative Agent, any Issuing Bank or any Lender may otherwise have to bring any action or proceeding relating to this Agreement against any Borrower or its properties in the courts of any jurisdiction.

     (c) Each Borrower hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement in any court referred to in paragraph (b) of this Section. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

     (d) Each party to this Agreement irrevocably consents to service of process in any action or proceeding referred to in Section 10.09 by the mailing thereof by certified mail, return receipt requested, addressed as provided in Section 10.01(a), with a copy thereof to the “General Counsel” of such Person at such same address.

     Section 10.10. Waiver Of Jury Trial. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (a) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, AND (b) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN

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INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

     Section 10.11. Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

     Section 10.12. Confidentiality. Each of the Administrative Agent, the Collateral Agent, each Issuing Bank and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents, including accountants, legal counsel and other advisors involved in the financing provided for herein (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority, (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, applicable to it, (d) to any other party to this Agreement, (e) in connection with the exercise of any remedies hereunder or any suit, action or proceeding relating to this Agreement or the enforcement of rights hereunder, (f) subject to an agreement to comply with the provisions of this Section 10.12 or a separate agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement, (ii) any pledgee referred to in Section 10.04(e) or (iii) any actual or prospective counterparty (or its advisors) to any swap or derivative transaction relating to any Borrower and its obligations, (g) with the consent of a Borrower or (h) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section or (ii) becomes available to the Administrative Agent, the Collateral Agent, any Issuing Bank or any Lender on a nonconfidential basis from a source other than a Borrower or any of its Subsidiaries, the Administrative Agent, the Collateral Agent, any Issuing Bank or any other Lender. For the purposes of this Section, “Information” means all information received from a Borrower or any of its Subsidiaries relating to any Borrower or any of its Subsidiaries or its businesses, other than any such information that is available to the Administrative Agent, the Collateral Agent, any Issuing Bank or any Lender on a nonconfidential basis prior to disclosure by such Borrower; provided that, in the case of information received from a Borrower after the date hereof, such information is clearly identified at the time of delivery as confidential. Any Person required to maintain the confidentiality of Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information; and nothing in the foregoing authorization shall apply to any disclosure that would constitute a violation of applicable federal and state securities laws.

     EACH LENDER ACKNOWLEDGES THAT INFORMATION AS DEFINED IN SECTION 10.12 FURNISHED TO IT PURSUANT TO THIS AGREEMENT MAY INCLUDE MATERIAL NON-PUBLIC INFORMATION CONCERNING THE BORROWERS AND ITS AFFILIATES AND THEIR RELATED PARTIES OR THEIR RESPECTIVE SECURITIES, AND CONFIRMS THAT IT HAS DEVELOPED COMPLIANCE PROCEDURES REGARDING THE USE OF MATERIAL NON-PUBLIC INFORMATION AND THAT IT WILL HANDLE SUCH MATERIAL NON-

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PUBLIC INFORMATION IN ACCORDANCE WITH THOSE PROCEDURES AND APPLICABLE LAW, INCLUDING FEDERAL AND STATE SECURITIES LAWS.

     ALL INFORMATION, INCLUDING REQUESTS FOR WAIVERS AND AMENDMENTS, FURNISHED BY THE BORROWERS OR THE ADMINISTRATIVE AGENT PURSUANT TO, OR IN THE COURSE OF ADMINISTERING, THIS AGREEMENT WILL BE SYNDICATE-LEVEL INFORMATION, WHICH MAY CONTAIN MATERIAL NON-PUBLIC INFORMATION ABOUT THE BORROWER, CREDIT PARTIES AND THEIR RELATED PARTIES OR THEIR RESPECTIVE SECURITIES. ACCORDINGLY, EACH LENDER REPRESENTS TO THE BORROWER AND THE ADMINISTRATIVE AGENT THAT IT HAS IDENTIFIED IN ITS ADMINISTRATIVE QUESTIONNAIRE A CREDIT CONTACT WHO MAY RECEIVE INFORMATION THAT MAY CONTAIN MATERIAL NON-PUBLIC INFORMATION IN ACCORDANCE WITH ITS COMPLIANCE PROCEDURES AND APPLICABLE LAW, INCLUDING FEDERAL AND STATE SECURITIES LAWS.

     Section 10.13. Security Agreement. Each of the Lenders, for itself and for each of its Affiliates, and each Issuing Bank hereby (i) approves the Security Agreement and (ii) irrevocably authorizes and directs the Collateral Agent, and any successor thereof appointed pursuant to Article 9, to take such actions on its behalf and to exercise such powers as are delegated to the Collateral Agent by the terms of the Security Agreement, together with such actions and powers as are reasonably incidental thereto. The Collateral Agent is hereby authorized and directed to execute and deliver the Security Agreement on behalf of the Lenders. Until the Final Payment Date shall have occurred, to the extent the Security Agreement amends, modifies or supplements any term or provision hereof, it shall constitute an amendment and modification to, and supplement of, this Agreement. Each Lender that is now, or hereafter becomes, a party to this Agreement (including each Person that becomes a Lender pursuant to Section 10.04) and each Person (including any Affiliate of a Lender that party to any Secured Hedging Agreement) otherwise claiming rights pursuant to this Agreement (a) consents to the provisions of the Security Agreement and (b) agrees by being or becoming a Lender hereunder or otherwise claiming any such rights, to become or be bound by the Security Agreement and each other document entered into by the Administrative Agent on behalf of the Secured Parties pursuant to the terms and provisions of the Security Agreement.

     Section 10.14. Amendment and Restatement and Continuing Effect. This Agreement constitutes for all purposes an amendment and a restatement of the Existing Facility and as of the Effective Date all commitments or loans outstanding, or any letter of credit issued, under the Existing Facility shall constitute Commitments and Letters of Credit under this Agreement. The Existing Facility, as amended and restated hereby, continues in full force and effect as so amended and restated by this Agreement.

     Section 10.15. USA Patriot Act. Each Lender hereby notifies the Borrower that pursuant to the requirements of the Patriot Act, it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender to identify the Borrower in accordance with the Patriot Act.

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     Section 10.16. Releases. • On the Effective Date, without further action by any party to the Loan Documents, each Subsidiary listed on Schedule 10.16(a) (the “Released Parties”) shall cease to be a Subsidiary Guarantor or a Borrower, each of the Released Parties shall cease to be a “Grantor” under the Security Agreement, any property of a Released Party in which a security interest is granted by such Released Party pursuant to the Security Documents shall be released from such security interest and shall no longer constitute Collateral and the Released Parties shall cease to be parties to the Loan Documents or to have any rights or obligations thereunder.

     (a) The Administrative Agent shall from time to time upon the reasonable request of the Company, at the sole expense of the Company, execute and deliver to the Company such instruments and documents as the Company may reasonably request to fully effect solely the foregoing releases, terminations and discharges, and return to the Company any certificate or other instruments delivered to the Administrative Agent in connection with the Existing Credit Agreement and Security Documents all security interests in which are released pursuant to Section 10.16(a).

[SIGNATURE PAGES BEGIN ON NEXT PAGE]

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     IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written

EL PASO CORPORATION
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer
EL PASO NATURAL GAS COMPANY
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer
TENNESSEE GAS PIPELINE COMPANY
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer
COLORADO INTERSTATE GAS COMPANY,      solely as Borrower (as such term is      defined under the Existing Facility)      under the Existing Facility
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer

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JPMORGAN CHASE BANK, N.A.,      as Administrative Agent and as an Issuing Bank and as a Lender
By:	/s/ Robert Traband
	Name:	Robert Traband
	Title:	Executive Director
Citicorp North America, Inc.      as Lender
By:	/s/ Jim Reilly
	Name:	Jim Reilly
	Title:	Vice President
Bank of America, N.A., as Lender
By:	/s/ Ronald E. McKaig
	Name:	Ronald E. McKaig
	Title:	Senior Vice President

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DEUTSCHE BANK TRUST COMPANY AMERICAS,      as Lender
By:	/s/ Paul O’Leary
	Name:	Paul O’Leary
	Title:	Vice President
The Royal Bank of Scotland plc,      as Lender
By:	/s/ Patricia Dundee
	Name:	Patricia Dundee
	Title:	Managing Director
ABN AMRO Bank N.V.      as Lender
By:	/s/ R. Scott Donaldson
	Name:	R. Scott Donaldson
	Title:	Director
By:	/s/ Todd Vaubel
	Name:	Todd Vaubel
	Title:	Vice President

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BNP Paribas, as Lender
By:	/s/ Mark A. Cox
	Name:	Mark A. Cox
	Title:	Managing Director
By:	/s/ Larry Robinson
	Name:	Larry Robinson
	Title:	Director
Credit Suisse, Cayman Islands Branch,      as Lender
By:	/s/ James Moran
	Name:	James Moran
	Title:	Managing Director
By:	/s/ Nupur Kumar
	Name:	Nupur Kumar
	Title:	Associate
Fortis Capital Corp., as Lender
By:	/s/ Deirdre Sanborn
	Name:	Deirdre Sanborn
	Title:	Director
By:	/s/ Darrell Holley
	Name:	Darrell Holley
	Title:	Managing Director

Third Amended and Restated Credit Agreement

82

GOLDMAN SACHS CREDIT PARTNERS L.P.,      as Lender
By:	/s/ Mark Walton
	Name:	Mark Walton
	Title:	Authorized Signatory
The Bank of Nova Scotia,      as Lender
By:	/s/ A. Ostrov
	Name:	A. Ostrov
	Title:	Director
SOCIETE GENERALE,      as Lender
By:	/s/ Kevin C. Joyce
	Name:	Kevin C. Joyce
	Title:	Vice President

Third Amended and Restated Credit Agreement

83

UBS LOAN FINANCE LLC,      as Lender
By:	/s/ I. R. Otsa
	Name:	I. R. Otsa
	Title:	Associate Director Banking Products Services, US
By:	/s/ Richard L. Lavrow
	Name:	I Richard L. Lavrow
	Title:	Director Banking Products Services, US
BAYERISCHE HYPO-UND VEREINSBANK AG, NEW YORK BRANCH,      as Lender
By:	/s/ William W. Hunter
	Name:	William W. Hunter
	Title:	Director
By:	/s/ Shannon Batchman
	Name:	Shannon Batchman
	Title:	Director

Third Amended and Restated Credit Agreement

84

MORGAN STANLEY BANK,      as Lender
By:	/s/ Daniel Twenge
	Name:	Daniel Twenge
	Title:	Authorized Signatory
Merrill Lynch Capital Corporation,      as Lender
By:	/s/ Don Burkitt
	Name:	Don Burkitt
	Title:	Vice President
Bayerische Landesbank, New York Branch,      as Lender
By:	/s/ Craig J. Anderson
	Name:	Craig J. Anderson
	Title:	First Vice President
By:	/s/ Nikolai von Mengden
	Name:	Nikolai von Mengden
	Title:	Senior Vice President

Third Amended and Restated Credit Agreement

85

LEHMAN BROTHERS COMMERCIAL BANK,      as Lender
By:	/s/ George Janes
	Name:	George Janes
	Title:	Chief Credit Officer
Natixis,      as Lender
By:	/s/ Louis P. Laville, III
	Name:	Louis P. Laville, III
	Title:	Managing Director
By:	/s/ Daniel Payer
	Name:	Daniel Payer
	Title:	Director
Wachovia Bank, National Association,      as Lender
By:	/s/ Shawn Young
	Name:	Shawn Young
	Title:	Vice President

Third Amended and Restated Credit Agreement

86

Wells Fargo Bank, N.A.,      as Lender
By:	/s/ Sushim Shah
	Name:	Sushim Shah
	Title:	Vice President
Bank of New York,      as Lender
By:	/s/ Hussam S. Alsahlani
	Name:	Hussam S. Alsahlani
	Title:	Vice President

Third Amended and Restated Credit Agreement

87

SCHEDULE 1

LENDER COMMITMENTS

	Name of Lender	Commitment
1.	Citibank, N.A.	$	97,000,000
2.	JPMorgan Chase Bank, N.A.	$	97,000,000
3.	Bank of America, N.A.	$	90,000,000
4.	Deutsche Bank Trust Company Americas	$	90,000,000
5.	The Royal Bank of Scotland plc	$	90,000,000
6.	ABN AMRO Bank N.V.	$	90,000,000
7.	BNP Paribas	$	72,000,000
8.	Credit Suisse, Cayman Islands Branch	$	72,000,000
9.	Fortis Capital Corp.	$	72,000,000
10.	Goldman Sachs Credit Partners L.P.	$	72,000,000
11.	The Bank of Nova Scotia	$	72,000,000
12.	Societe Generale	$	72,000,000
13.	UBS Loan Finance LLC	$	72,000,000
4.	Bayerische Hypo-und Vereinsbank AG, New York Branch	$	60,000,000
15.	Morgan Stanley Bank	$	60,000,000
16.	Merrill Lynch Capital Corp.	$	60,000,000
17.	Bayerische Landesbank, New York Branch	$	50,000,000
18.	Lehman Brothers Commercial Bank	$	50,000,000
19.	Natixis	$	50,000,000
20.	Wachovia Bank, National Association	$	50,000,000
21.	Wells Fargo Bank, N.A.	$	50,000,000
22.	The Bank of New York	$	12,000,000
	TOTAL	$	1,500,000,000

Third Amended and Restated Credit Agreement

Schedule 1 – Page 1

SCHEDULE 2

LETTER OF CREDIT COMMITMENTS

Name of Issuing Bank	LC Commitment
JPMorgan Chase Bank, N.A.	$	400,000,000
BNP Paribas	$	400,000,000
Citibank, N.A.	$	300,000,000
Fortis Capital Corp.	$	300,000,000
Deutsche Bank Trust Company Americas	$	100,000,000

Third Amended and Restated Credit Agreement

Schedule 2 – Page 1

SCHEDULE 3

PRICING SCHEDULE

     “Applicable Margin” means, for any day, for purposes of calculating commitment fees on Commitments or interest on Loans, the rate per annum set forth below in the applicable row opposite such term and in the column corresponding to the Pricing Level that applies on such day:

	Level I			Level II			Level III			Level IV			Level V
Commitment Fees		0.100	%		0.125	%		0.200	%		0.250	%		0.375	%
ABR Loan Margin		0.000	%		0.000	%		0.000	%		0.250	%		0.500	%
Euro-Dollar Loan Margin		0.500	%		0.750	%		1.000	%		1.250	%		1.500	%

     For purposes of this Schedule, the following terms have the following meanings, subject to the concluding paragraphs of this Schedule:

     “Fitch” means Fitch Ratings, Ltd.

     “Level I Pricing” applies on any day on which the Reference Rating is BBB/Baa2/BBB or higher.

     “Level II Pricing” applies on any day on which the Reference Rating is BBB-/Baa3/BBB-.

     “Level III Pricing” applies on any day on which the Reference Rating is BB+/Ba1/BB+.

     “Level IV Pricing” applies on any day on which the Reference Rating is BB/Ba2/BB.

     “Level V Pricing” applies on any day if no other Pricing Level applies on such day.

     “Moody’s” means Moody’s Investors Service, Inc.

     “Pricing Level” refers to the determination of which of Level I, Level II, Level III, Level IV or Level V Pricing applies on any day.

     “Rating Agency” means Fitch, Moody’s or S&P.

Third Amended and Restated Credit Agreement

Schedule 3 — Page 1

     The “Reference Rating” is the credit rating assigned to the Loans by the relevant rating agency; provided that (i) until such time as Moody’s and S&P assigns an initial rating to the Loans, the Moody’s and S&P ratings of the Existing Facility shall be deemed to be its Reference Rating and (ii) until the Borrowers engage Fitch to rate the Loans, Fitch’s ratings shall be deemed to be unavailable. The rating in effect for any day is that in effect at the close of business on such day.

     “S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies.

     In the event that Reference Ratings are not available from all three Rating Agencies, (i) if the Reference Rating from Fitch is unavailable, Moody’s and S&P’s Reference Ratings shall apply and, if both Reference Ratings from Moody’s and S&P are available but not the same, then (A) if the difference is one notch, the higher such rating will govern so long as it is at least BBB- or Baa3 or higher, but the lower rating will govern if that requirement is not met, and (B) if the difference is more than one notch, a Reference Rating one notch below the higher of the two will govern; (ii) if the Reference Rating from either Moody’s or S&P is unavailable, then the Fitch Reference Rating shall not apply and the Pricing Level will be determined on the basis of the available Reference Rating from Moody’s or S&P; and (iii) if the Reference Ratings from both Moody’s and S&P are unavailable, then Level V shall apply.

     In the event Reference Ratings from all three Rating Agencies are available, then (i) the majority Reference Rating will govern, if two such ratings are the same or (ii) the middle Reference Rating will govern, if all three such ratings differ.

     If the rating system of any Rating Agency shall change, the Borrowers and the Lenders shall negotiate in good faith to amend this Schedule to reflect such changed rating system and, pending the effectiveness of any such amendment, the Applicable Rate shall be determined without reference to such Rating Agency.

Third Amended and Restated Credit Agreement

Schedule 3 — Page 2

SCHEDULE 4.05

DISCLOSURE UPDATE

None

Third Amended and Restated Credit Agreement

Schedule 4.05 — Page 1

SCHEDULE 4.14

ENVIRONMENTAL MATTERS

     Matters described in the Company’s annual report on Form 10-K for the year ended December 31, 2006 or in its 3^rd Quarter 2007 10-Q.

Third Amended and Restated Credit Agreement

Schedule 4.14 — Page 1

SCHEDULE 4.16

SUBSIDIARIES AS OF OCTOBER 12, 2007

SEE ATTACHED

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 1

As of October 12, 2007

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Agropecuaria Santo Antonio Ltda.	Brazil	El Paso Energia do Brasil Ltda.	Owner		0.0002
		Termogas S/A	Unaffiliated Parties		0.0002
		Termo Norte Energia Ltda.	Owner		99.9996
Agua del Cajon (Cayman) Company	Cayman Islands	EPED B Company	Owner of Preferred Stock		50.0000
		El Paso Neuquen Holding Company	Owner of Ordinary Stock		50.0000
Alpheus Communications, L.P.	Delaware	Zipline, L.L.C.	General Partner		1.0000
		Genesis Park Telecom Partners, L.P.	Unaffiliated Parties — LP Owner		28.0000
		El Paso Telecom, L.L.C.	Limited Partner		71.0000
Amethyst Power Holdings, L.L.C.	Delaware	Garnet Power Holdings, L.L.C.	Member		100.0000
ANR Advance Holdings, Inc.	Delaware	El Paso Midwest Company	Stockholder		50.0000
		Unaffiliated Parties	Unaffiliated Parties		50.0000
ANR Capital Company, L.L.C.	Delaware	El Paso CNG Company, L.L.C.	Member		100.0000
ANR Development Company, L.L.C.	Delaware	El Paso CGP Company, L.L.C.	Member		100.0000
ANR Real Estate Corporation	Delaware	Southern Natural Gas Company	Stockholder		100.0000
ANR Venture Eagle Point Company	Delaware	El Paso CNG Company, L.L.C.	Stockholder		100.0000
ANR Western Coal Development Company	Delaware	El Paso CNG Company, L.L.C.	Stockholder		100.0000
Aquamarine Power Holdings, L.L.C.	Delaware	Diamond Power Holdings, L.L.C.	Member		100.0000
BBPP Holdings Ltda.	Brazil	EPIC Gas International Servicos do Brasil Ltda.	Owner		33.3333
		British Gas International Holdings B.V.	Unaffiliated Parties		33.3333
		TotalFinaElf Gas and Power Brazil	Unaffiliated Parties		33.3334
Bear Creek Storage Company	Louisiana	Tennessee Storage Company	Partner		50.0000
		Southern Gas Storage Company	Partner		50.0000
Berkshire Feedline Acquisition Limited Partnership	Massachusetts	Berkshire Pittsfield, Inc.	Unaffiliated Parties — GP Owner		1.0000
		General Electric Capital Corporation	Unaffiliated Parties — GP Owner		49.0000
		El Paso Energy Pittsfield Corporation	Limited Partner		50.0000
Black Warrior Methane Corp.	Alabama	El Paso E&P Company, L.P.	Stockholder		50.0000
		Jim Walter Resources, Inc.	Unaffiliated Parties		50.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 2

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Black Warrior Transmission Corp.	Alabama	El Paso E&P Company, L.P.	Stockholder		50.0000
		Jim Walter Resources, Inc.	Unaffiliated Parties		50.0000
Bonneville McKenzie Energy Corporation	Canada	El Paso Merchant Energy North America Company	Owner		100.0000
Canyon Creek Compression Company	Illinois	CIG-Canyon Compression Company	Partner		15.0000
		URC-Canyon Creek Compression Company	Unaffiliated Parties		15.0000
		NGPL-Canyon Compression Co.	Unaffiliated Parties		70.0000
CEG Finance Company Ltd.	Cayman Islands	Coastal Power Nicaragua Holding Company Ltd.	Owner		100.0000
Chaparral Investors, L.L.C.	Delaware	El Paso Merchant Energy North America Company	Member		100.0000
Cheyenne Plains Gas Pipeline Company, L.L.C.	Delaware	Cheyenne Plains Investment Company, L.L.C.	Member		100.0000
Cheyenne Plains Investment Company, L.L.C.	Delaware	El Paso CNG Company, L.L.C.	Member		100.0000
CIG Finance Company, L.L.C.	Delaware	Colorado Interstate Gas Company	Member		100.0000
CIG Funding Company, L.L.C.	Delaware	CIG Finance Company, L.L.C.	Member		100.0000
CIG Gas Storage Company	Delaware	El Paso CNG Company, L.L.C.	Stockholder		100.0000
CIG Merchant Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
CIG Pipeline Services Company, L.L.C.	Delaware	El Paso Noric Investments III, L.L.C.	Member		100.0000
CIG-Canyon Compression Company	Delaware	El Paso CNG Company, L.L.C.	Stockholder		100.0000
CIGE Company	Delaware	CIGE Holdco, Inc.	Stockholder		100.0000
CIGE Holdco, Inc.	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Citrine FC Company	Cayman Islands	Emerald Finance, L.L.C.	Owner		100.0000
Citrus Corp.	Delaware	El Paso Citrus Holdings, Inc.	Stockholder		50.0000
		CrossCountry Citrus, LLC	Unaffiliated Parties		50.0000
Citrus Energy Services, Inc.	Delaware	Citrus Corp.	Stockholder		100.0000
Citrus Trading Corp.	Delaware	Citrus Corp.	Stockholder		100.0000
Cliffside Helium, LLC	Delaware	Colorado Interstate Gas Company	Member		4.0000
		The BOC Group, Inc.	Unaffiliated Parties		26.0000
		Praxair, Inc.	Unaffiliated Parties		34.0000
		Air Products Manufacturing Corp.	Unaffiliated Parties		36.0000
Cliffside Refiners, L.P.	Delaware	Cliffside Helium, LLC	General Partner		1.0000
		Colorado Water Supply Company	Limited Partner		3.9600

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 3

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		The BOC Group, Inc.	Unaffiliated Parties — LP Owner		25.7400
		Wall Chemical, Inc.	Unaffiliated Parties — LP Owner		33.6600
		Air Products Helium, Inc.	Unaffiliated Parties — LP Owner		35.6400
CNG Cayman Two Ltd.	Cayman Islands	CNG International Corporation	Unaffiliated Parties		23.0800
		DBNGP Finance Company L.L.C.	Owner		76.9200
CNG Labuan One Limited	Malaysia	CNG Cayman Two Ltd.	Owner		100.0000
Coastal (Bermuda) Petroleum Limited	Bermuda	Coastal Securities Company Limited	Owner		100.0000
Coastal (Rotterdam) B.V.	Netherlands	El Paso Merchant Energy-Petroleum Company	Owner		100.0000
Coastal Austral Ltd.	Cayman Islands	Coastal Cape Horn Ltd.	Owner		100.0000
Coastal Australia AC 96-3 Ltd.	Cayman Islands	El Paso E&P International Corporation	Owner		100.0000
Coastal Belcher Petroleum Pte Ltd.	Singapore	Coastal Securities Company Limited	Owner		0.2797
		Coastal Cayman Finance Ltd.	Owner		99.7203
Coastal Bridger Lake Pipeline Corporation	Delaware	El Paso Merchant Energy-Petroleum Company	Stockholder		100.0000
Coastal Canada Gas Services, Inc.	New Brunswick	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Canada Petroleum, Inc.	New Brunswick	Cosbel Petroleum Corporation	Owner		100.0000
Coastal Cape Horn Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Cayman Finance Ltd.	Cayman Islands	Coastal (Bermuda) Petroleum Limited	Owner		100.0000
Coastal Chem, Inc.	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal Coal, Inc.	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal Eagle Point Oil Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal Energy of Panama, Inc.	Panama	Coastal Stock Company Limited	Owner		100.0000
Coastal Energy Resources Ltd.	Mauritius	Coastal India Petroleum Ltd.	Owner		100.0000
Coastal Europe Limited	United Kingdom	Coastal Stock Company Limited	Owner		100.0000
Coastal Fuels of Puerto Rico, Inc.	Delaware	Cosbel Petroleum Corporation	Stockholder		100.0000
Coastal Fuji Oil Ltd.	Cayman Islands	Coastal Petroleum N.V.	Owner		50.0000
		Fuji Power & Petroleum Ltd.	Unaffiliated Parties		50.0000
Coastal Gas de Mexico S de R.L. de C.V.	Mexico	Coastal Halcon Pipeline I Ltd.	Owner		50.0000
		Coastal Halcon Pipeline II Ltd.	Owner		50.0000
Coastal Gas India Holdings Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 4

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Coastal Halcon Pipeline I Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Halcon Pipeline II Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal India Petroleum Ltd.	Cayman Islands	Coscol Petroleum Corporation	Owner		100.0000
Coastal International Finance Ltd.	Cayman Islands	El Paso CNG Company, L.L.C.	Owner		100.0000
Coastal Liquids Partners, L.P.	Delaware	El Paso Exploration & Production Management, Inc.	Limited Partner		2.1940
		El Paso Merchant Energy-Petroleum Company	General and Limited Partner		97.8060
Coastal Management Services (Singapore) Pte Ltd.	Singapore	Coastal Securities Company Limited	Owner		100.0000
Coastal Mart, Inc.	Delaware	El Paso Remediation Company	Stockholder		100.0000
Coastal Mobile Refining Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal Offshore Finance Ltd.	Cayman Islands	Coastal International Finance Ltd.	Owner		100.0000
Coastal Offshore Fuels, Inc.	Liberia	Cosbel Petroleum Corporation	Owner		100.0000
Coastal Offshore Insurance Ltd.	Bermuda	Coastal Offshore Finance Ltd.	Owner		100.0000
Coastal Oil & Gas Australia 20 Pty Ltd.	Australia	Coastal Australia AC 96-3 Ltd.	Owner		100.0000
Coastal Oil New England, Inc.	Massachusetts	Cosbel Petroleum Corporation	Stockholder		100.0000
Coastal Oil New York, Inc.	Delaware	Cosbel Petroleum Corporation	Stockholder		100.0000
Coastal Palembang Power (Singapore) Pte Ltd.	Singapore	Coastal Palembang Power Ltd.	Owner		100.0000
Coastal Palembang Power Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Petrochemical International (L) Limited	Labuan	Coastal Petrochemical International A.V.V.	Owner		100.0000
Coastal Petrochemical International A.V.V.	Aruba	Coscol Petroleum Corporation	Owner		100.0000
Coastal Petroleum (Far East) Pte Ltd.	Singapore	Coastal Securities Company Limited	Owner		100.0000
Coastal Petroleum Argentina, S.A.	Argentina	Triunion Energy Company	Owner		5.0001
		Coastal Petroleum N.V.	Owner		94.9999
Coastal Petroleum N.V.	Aruba	Coastal Stock Company Limited	Owner		100.0000
Coastal Petroleum N.V. Chile Limitada	Chile	El Paso Latin America Inc.	Owner		0.0030
		Coastal Petroleum N.V.	Owner		99.9970
Coastal Pipeline Company	Delaware	El Paso Merchant Energy-Petroleum Company	Stockholder		100.0000
Coastal Power International II Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Power Nicaragua Holding Company Ltd.	Cayman Islands	Coastal Power Nicaragua Ltd.	Owner		100.0000
Coastal Power Nicaragua Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Romanian Petroleum International A.V.V.	Aruba	Delve Overseas S.A.	Unaffiliated Parties		1.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 5

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		Coastal Petroleum N.V.	Owner		49.5000
		Arpechim S.A	Unaffiliated Parties		49.5000
Coastal Romanian Petroleum SRL	Romania	Delve Overseas S.A.	Unaffiliated Parties		1.0000
		Coscol Petroleum Corporation	Owner		49.5000
		Arpechim S.A	Unaffiliated Parties		49.5000
Coastal Saba Investor II Ltd.	Cayman Islands	Coastal Saba Manager Ltd.	Owner		1.0000
		Coastal Saba Investor Ltd.	Owner		99.0000
Coastal Saba Investor Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Saba Manager II Ltd.	Cayman Islands	Coastal Saba Manager Ltd.	Owner		1.0000
		Coastal Saba Investor Ltd.	Owner		99.0000
Coastal Saba Manager Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Saba Power Ltd.	Mauritius	Coastal Saba Manager II Ltd.	Owner		1.0000
		Coastal Saba Investor II Ltd.	Owner		99.0000
Coastal Securities Company Limited	Bermuda	Coastal Stock Company Limited	Owner		100.0000
Coastal States Energy Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal States Management Corporation	Colorado	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal Stock Company Limited	Bermuda	El Paso Merchant Energy-Petroleum Company	Owner of Common Stock		0.2800
		Coastal Austral Ltd.	Owner of Common Stock		0.8100
		EnCap Holdings (Cayman) Company	Owner of Class A Stock		5.9820
		EPED B Company	Owner of Class A Stock		16.3420
		Coastal Petrochemical International (L) Limited	Owner of Common Stock		19.2230
		Coscol Petroleum Corporation	Owner of Common Stock		57.3630
Coastal Subic Bay Terminal, Inc.	Philippines	Coscol Petroleum Corporation	Owner		100.0000
Coastal Technology Nicaragua S.A.	Nicaragua	Directors/Officers/Other Individuals	Individual Owner(s)		2.0000
		El Paso Technology, Inc.	Owner		98.0000
Coastal Technology Palembang (Cayman) Ltd.	Cayman Islands	El Paso Technology, Inc.	Owner		100.0000
Coastal Unilube, Inc.	Tennessee	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal Wartsila Petroleum Private Limited	India	Coastal Energy Resources Ltd.	Owner		50.0000
		Unaffiliated Party/Parties unknown	Unaffiliated Parties		50.0000
Coastal West Ventures, Inc.	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 6

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Colbourne Insurance Company Limited	United Kingdom	Directors/Officers/Other Individuals	Individual Owner(s)		0.0002
		El Paso Energy Capital Company	Owner		22.9998
		Coastal Europe Limited	Owner		77.0000
Colorado Interstate Gas Company	Delaware	El Paso Noric Investments III, L.L.C.	Stockholder		100.0000
Colorado Water Supply Company	Delaware	Colorado Interstate Gas Company	Stockholder		100.0000
Continental Connector Pipeline Company	Delaware	El Paso Corporation	Stockholder		100.0000
Copper Eagle Gas Storage, LLC	Delaware	El Paso Natural Gas Company	Member		100.0000
Coronado Energy E&P Company, L.L.C.	Delaware	Coronado Energy Production Operating, L.L.C.	Member		1.0000
		Coronado Energy Production Partners, L.L.C.	Member		99.0000
Coronado Energy Production Operating, L.L.C.	Delaware	Coronado Energy Production, L.L.C.	Member		100.0000
Coronado Energy Production Partners, L.L.C.	Delaware	Coronado Energy Production Operating, L.L.C.	Member		1.0000
		Coronado Energy Production, L.L.C.	Member		99.0000
Coronado Energy Production, L.L.C.	Delaware	EPC Holdings 756 LLC	Unaffiliated Party — Like Kind Exchange		100.0000
Cosbel Petroleum Corporation	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coscol Holding Company Ltd.	Cayman Islands	Coscol Petroleum Corporation	Owner		100.0000
Coscol Petroleum Corporation	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Cross Country Development L.L.C.	Delaware	Collins & Aikman Products Co.	Unaffiliated Parties		9.0000
		Wilson Sporting Goods Co.	Unaffiliated Parties		40.6700
		El Paso Natural Gas Company	Member		50.3300
Crystal Exploration and Production, L.L.C.	Delaware	Crystal Gas Storage, Inc.	Member		100.0000
Crystal Gas Storage, Inc.	Delaware	El Paso Remediation Company	Stockholder		100.0000
DBNGP Finance Company L.L.C.	Delaware	EPED Holding Company	Member		50.0000
		CNG International Corporation	Unaffiliated Parties		50.0000
DeepTech International Inc.	Delaware	El Paso Corporation	Stockholder		100.0000
Diamond Power Holdings, L.L.C.	Delaware	Diamond Power Ventures, L.L.C.	Member		100.0000
Diamond Power Ventures, L.L.C.	Delaware	Garnet Power Holdings, L.L.C.	Member		49.0000
		Gemstone Investor Limited	Member		51.0000
Dutonorte Investimentos Ltda	Brazil	Termogas International Inc.	Unaffiliated Parties		46.7158
		El Paso Cayman TNG Company	Owner		53.2842
Dynaf Bolivia S.A.	Bolivia	Directors/Officers/Other Individuals	Individual Owner(s)		0.2000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 7

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		EPED Holding Company	Owner		99.8000
Eastern Gulf Pipeline Company	Delaware	Southern Natural Gas Company	Stockholder		100.0000
Eastern Insurance Company Limited	Bermuda	El Paso Corporation	Stockholder		100.0000
El Paso Amazonas Energia Ltda.	Brazil	El Paso Energy Rio Negro Company	Owner		0.0100
		EPIC Energy Amazon Company	Owner		99.9900
El Paso Asia (Labuan) Limited	Labuan	EPED B Company	Owner		100.0000
El Paso Bahamas Holding B.V.	Netherlands	El Paso Pipeline Holding B.V.	Owner		100.0000
El Paso Brazil Holdings Company	Cayman Islands	El Paso Brazil, L.L.C.	Owner		100.0000
El Paso Brazil, L.L.C.	Delaware	El Paso Cayman Brazil Ventures Company	Member		7.6923
		El Paso Cayman BM-CAL-4 Company	Member		7.6923
		El Paso Cayman BAS-97 Company	Member		7.6923
		El Paso Cayman BCAM-2 Company	Member		7.6923
		El Paso Cayman BS-1 Company	Member		7.6923
		El Paso Cayman BM-POT-11 Company	Member		7.6923
		El Paso Cayman BM-POT-13 Company	Member		7.6923
		El Paso Cayman BM-S-13 Company	Member		7.6923
		El Paso Cayman BM-CAL-6 Company	Member		7.6923
		El Paso Cayman BM-ES-5 Company	Member		7.6923
		El Paso Cayman BM-CAL-5 Company	Member		7.6923
		El Paso Cayman CAL-M-312 Company	Member		7.6923
		El Paso Cayman CAL-M-372 Company	Member		7.6923
El Paso Canada Pipeline B.V.	Netherlands	El Paso Pipeline Holding B.V.	Owner		100.0000
El Paso Canada Pipeline Company	Nova Scotia	El Paso Canada Pipeline B.V.	Owner		100.0000
El Paso Capital Trust II	Delaware	El Paso Corporation	Sponsor		100.0000
El Paso Capital Trust III	Delaware	El Paso Corporation	Sponsor		100.0000
El Paso Cayman BAS-97 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BCAM-2 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-CAL-4 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 8

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-CAL-5 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-CAL-6 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-ES-5 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-ES-6 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-PAMA-1 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-POT-11 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-POT-13 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-S-13 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BPAR-10 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman Brazil Ventures Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BS-1 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BT-PR-4 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman CAL-M-312 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman CAL-M-372 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman DBNGP, Ltd.	Cayman Islands	DBNGP Finance Company L.L.C.	Owner		100.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 9

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
El Paso Cayman TNG Company	Cayman Islands	EPED B Company	Owner		100.0000
El Paso CGP Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso CGP Gas Transmission Company	Delaware	El Paso Field Operations Company	Stockholder		100.0000
El Paso Citrus Holdings, Inc.	Delaware	Southern Natural Gas Company	Stockholder		100.0000
El Paso CNG Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso Coal Holding, L.L.C.	Delaware	El Paso CNG Company, L.L.C.	Member		100.0000
El Paso Compression Services de Mexico, S. de R.L. de C.V.	Mexico	El Paso El Sauz B.V.	Owner		0.0134
		El Paso Nederland Energie B.V.	Owner		99.9866
El Paso Corporate Foundation	Texas	El Paso Corporation	Member		100.0000
El Paso Corporation	Delaware	Unaffiliated Parties	Stockholder		100.0000
El Paso DBNGP Limited	Labuan	El Paso Cayman DBNGP, Ltd.	Owner		100.0000
El Paso E&P Cayman Finance Ltd.	Cayman Islands	El Paso E&P International Holding Company	Owner		100.0000
El Paso E&P Company, L.P.	Delaware	El Paso Exploration & Production Management, Inc.	General Partner		1.0000
		El Paso E&P Holdings, Inc.	Limited Partner		99.0000
El Paso E&P Finance Company, L.L.C.	Delaware	El Paso E&P Cayman Finance Ltd.	Member		100.0000
El Paso E&P Holdings, Inc.	Delaware	El Paso Exploration & Production Management, Inc.	Stockholder		100.0000
El Paso E&P International Corporation	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso E&P International Holding Company	Delaware	El Paso Exploration & Production Company	Stockholder		100.0000
El Paso E&P Zapata, L.P.	Texas	El Paso South Texas E&P Company, L.L.C.	General Partner		1.0000
		El Paso E&P Company, L.P.	Limited Partner		99.0000
El Paso Egypt Production Company	Cayman Islands	El Paso E&P International Holding Company	Owner		100.0000
El Paso El Sauz B.V.	Netherlands	EPED Holding Company	Owner		100.0000
El Paso Energia Cayman I Limited	Cayman Islands	EPED Holding Company	Owner		100.0000
El Paso Energia do Brasil Ltda.	Brazil	El Paso Oleo e Gas do Brasil Ltda.	Owner		0.0001
		El Paso Merchant Energy Americas do Sul (Cayman) Company	Owner		0.0313
		El Paso Energy Brazil Corporation	Owner		99.9686
El Paso Energia Mexico, SA de CV	Mexico	El Paso Energy International Company	Owner		49.7500
		El Paso Latin America Inc.	Owner		50.2500

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 10

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
El Paso Energy Amazon Company	Cayman Islands	Amethyst Power Holdings, L.L.C.	Owner		100.0000
El Paso Energy Argentina Limitada S.A.	Argentina	Triunion Energy Inversiones Company	Owner		5.0000
		Triunion Energy Company	Owner		95.0000
El Paso Energy Argentina Service Company	Delaware	EPED Holding Company	Stockholder		100.0000
El Paso Energy Brazil Corporation	Cayman Islands	EPED B Company	Owner		100.0000
El Paso Energy Capital Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
El Paso Energy Capital Trust I	Delaware	El Paso Corporation	Sponsor		100.0000
El Paso Energy Cayger II Company	Cayman Islands	Aquamarine Power Holdings, L.L.C.	Owner		100.0000
El Paso Energy Corporation Environmental Settlement Irrevocable Trust I		El Paso Energy E.S.T. Company	Trustee		100.0000
El Paso Energy E.S.T. Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Energy Engineering Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Energy Europe Limited	Scotland	El Paso Energy Operating Services Company	Owner		100.0000
El Paso Energy Global Holdings Company	Cayman Islands	EPED Holding Company	Owner		100.0000
El Paso Energy Hydro Holding B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Energy India (Private) Ltd.	India	El Paso Energy Global Holdings Company	Owner		0.0022
		El Paso International Power Operations Company	Owner		99.9978
El Paso Energy International Company	Delaware	El Paso Tennessee Pipeline Co.	Stockholder		100.0000
El Paso Energy Marketing de Mexico, S de RL de CV	Mexico	El Paso Merchant Energy Company	Owner		0.1100
		El Paso Nederland Energie B.V.	Owner		99.8900
El Paso Energy Oil Transmission, L.L.C.	Delaware	El Paso Exploration & Production Management, Inc.	Member		100.0000
El Paso Energy Operating Services Company	Cayman Islands	EPED B Company	Owner		100.0000
El Paso Energy Pittsfield Corporation	Delaware	El Paso Energy International Company	Stockholder		100.0000
El Paso Energy Portland Corporation	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
El Paso Energy Rio Negro Company	Cayman Islands	El Paso Energy Amazon Company	Owner		100.0000
El Paso Energy Service Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Energy Servicios S. de R.L. de C.V.	Mexico	El Paso Energy International Company	Owner		1.0000
		EPED Holding Company	Owner		99.0000
El Paso EPNG Investments, L.L.C.	Delaware	El Paso Corporation	Member		100.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 11

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
El Paso Europe Limited	Scotland	El Paso Merchant Energy International Company	Owner		100.0000
El Paso European Energie B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Exploration & Production Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Exploration & Production Management, Inc.	Delaware	El Paso Exploration & Production Company	Stockholder		100.0000
El Paso Field Operations Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
El Paso Field Services International Company	Cayman Islands	El Paso Tennessee Pipeline Co.	Owner		100.0000
El Paso Field Services Management, Inc.	Delaware	El Paso Transmission Company	Stockholder		100.0000
El Paso Field Services, L.L.C.	Delaware	El Paso Field Services Management, Inc.	Member		1.0000
		El Paso Transmission Company	Member		99.0000
El Paso Fife I Company	Cayman Islands	EPED B Company	Owner		100.0000
El Paso Gas Marketing Company	Delaware	El Paso Merchant Energy-Gas Company	Stockholder		100.0000
El Paso Gas Services Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Gas Transmission de Mexico, S. de R.L. de C.V.	Mexico	El Paso El Sauz B.V.	Owner		0.0001
		El Paso Nederland Energie B.V.	Owner		99.9999
El Paso Global Networks Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Great Lakes Company, L.L.C.	Delaware	Seafarer US Pipeline System, Inc.	Member		100.0000
El Paso Guna Power (Mauritius) Limited	Mauritius	KLT Power Asia	Owner		100.0000
El Paso Indonesia B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Industrial Energy, L.P.	Delaware	El Paso Merchant Energy Company	General Partner		1.0000
		El Paso Marketing, L.P.	Limited Partner		99.0000
El Paso International Power Operations Company	Cayman Islands	El Paso Energy Global Holdings Company	Owner		100.0000
El Paso Japan Holding B.V.	Netherlands	El Paso Nederland Energie B.V.	Owner		100.0000
El Paso Khulna Power ApS	Denmark	El Paso Power Khulna Holding Ltd.	Owner		100.0000
El Paso Latin America Inc.	Delaware	El Paso Energy International Company	Stockholder		100.0000
El Paso Maritime B.V.	Netherlands	El Paso Oleo e Gas do Brasil Ltda.	Owner		100.0000
El Paso Marketing, L.P.	Delaware	El Paso Merchant Energy Company	General Partner		1.0000
		El Paso SPM Company	Limited Partner		23.0000
		El Paso Merchant Energy-Gas Company	Limited Partner		76.0000
El Paso Mauritius Holding Limited	Mauritius	EPED B Company	Owner		100.0000
El Paso Merchant Energy Americas do Sul (Cayman) Company	Cayman Islands	El Paso Merchant Energy International Company	Owner		100.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 12

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
El Paso Merchant Energy Brazil, Ltd.	Cayman Islands	El Paso Merchant Energy International Company	Owner		100.0000
El Paso Merchant Energy Company	Delaware	El Paso Merchant Energy North America Company	Stockholder		100.0000
El Paso Merchant Energy do Brasil Ltda.	Brazil	El Paso Energia do Brasil Ltda.	Owner		0.0001
		El Paso Merchant Energy Brazil, Ltd.	Owner		99.9999
El Paso Merchant Energy Europe Holdings I Company	Cayman Islands	El Paso Merchant Energy International Company	Owner		100.0000
El Paso Merchant Energy Europe Holdings II Company	Cayman Islands	El Paso Merchant Energy International Company	Owner		100.0000
El Paso Merchant Energy Europe Holdings III Company	Cayman Islands	El Paso Merchant Energy International Company			100.0000
El Paso Merchant Energy Europe Limited	Scotland	El Paso Merchant Energy Europe Holdings I Company	Owner		100.0000
El Paso Merchant Energy International Company	Cayman Islands	El Paso Energy Global Holdings Company	Owner		100.0000
El Paso Merchant Energy North America Company	Delaware	El Paso Tennessee Pipeline Co.	Stockholder		100.0000
El Paso Merchant Energy-Gas Company	Delaware	EPEC Corporation	Stockholder		100.0000
El Paso Merchant Energy-Petroleum Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
El Paso Mexico Gasoductos B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Mexico Management B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Mexico Management S. de R.L. de C.V.	Mexico	El Paso El Sauz B.V.	Owner		0.0300
		El Paso Mexico Management B.V.	Owner		99.9700
El Paso Midwest Company	Delaware	El Paso Energy Capital Company	Stockholder		100.0000
El Paso Mojave Pipeline Co.	Delaware	El Paso Natural Gas Company	Stockholder		100.0000
El Paso Natural Gas Company	Delaware	El Paso EPNG Investments, L.L.C.	Stockholder		100.0000
El Paso Nederland Energie B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Neuquen Holding Company	Cayman Islands	El Paso Energy Argentina Service Company	Owner		100.0000
El Paso Noric Investments III, L.L.C.	Delaware	El Paso CNG Company, L.L.C.	Member		100.0000
El Paso O&M do Brasil Ltda.	Brazil	El Paso Energia do Brasil Ltda.	Owner		0.0001
		El Paso International Power Operations Company	Owner		99.9999
El Paso Oleo e Gas do Brasil Ltda.	Brazil	El Paso Brazil Holdings Company	Owner		0.1998
		El Paso Brazil, L.L.C.	Owner		99.8002

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 13

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
El Paso Pacific Company	Delaware	El Paso Energy International Company	Stockholder		100.0000
El Paso Pakistan Power (Private) Limited	Pakistan	Directors/Officers/Other Individuals	Individual Owner(s)		0.2000
		El Paso Energy International Company	Owner		99.8000
El Paso Petroleum Overseas N.V.	Aruba	Coastal Stock Company Limited	Owner		100.0000
El Paso Pipeline GP Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso Pipeline Holding B.V.	Netherlands	El Paso Corporation	Owner		100.0000
El Paso Pipeline LP Holdings, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso Pipeline Partners Operating Company, L.L.C.	Delaware	El Paso Pipeline Partners, L.P.	Member		100.0000
El Paso Pipeline Partners, L.P.	Delaware	El Paso Pipeline GP Company, L.L.C.	General Partner		2.0000
		El Paso Pipeline LP Holdings, L.L.C.	Limited Partner		98.0000
El Paso Pipeline Services Company	Delaware	El Paso Natural Gas Company	Stockholder		100.0000
El Paso Power Khulna Holding Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
El Paso PPC Holding B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Preferred Holdings Company	Delaware	El Paso E&P International Holding Company	Stockholder		100.0000
El Paso Production Company Turkey BV	Netherlands	El Paso Production Holdings B.V.	Owner		100.0000
El Paso Production Holdings B.V.	Netherlands	El Paso Corporation	Owner		100.0000
El Paso Production International Cayman Company	Cayman Islands	El Paso E&P International Holding Company	Owner		100.0000
El Paso Production Oil & Gas Gathering, L.P.	Delaware	El Paso Exploration & Production Management, Inc.	General Partner		1.0000
		El Paso E&P Holdings, Inc.	Limited Partner		99.0000
El Paso Production Resale Company	Delaware	El Paso Exploration & Production Management, Inc.	Stockholder		100.0000
El Paso Reata Energy, L.P.	Delaware	El Paso Merchant Energy Company	General Partner		1.0000
		El Paso Marketing, L.P.	Limited Partner		99.0000
El Paso Remediation Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Rio Bravo B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Rio Negro Energia Ltda.	Brazil	EPIC Energy Amazon Company	Owner		0.0100
		El Paso Energy Rio Negro Company	Owner		99.9900
El Paso Rondonia Power Company	Cayman Islands	Aquamarine Power Holdings, L.L.C.	Owner		100.0000
El Paso Samalayuca Holding (Cayman) Company	Cayman Islands	EPED SAM Holdings Company	Owner		100.0000
El Paso Services (D.C.) Inc.	Delaware	El Paso Energy Service Company	Stockholder		100.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 14

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
El Paso Services Holding Company	Delaware	El Paso Tennessee Pipeline Co.	Stockholder		100.0000
El Paso SLOC Holding Company	Cayman Islands	Coscol Petroleum Corporation	Owner		100.0000
El Paso SNG Holding Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso South Texas E&P Company, L.L.C.	Delaware	El Paso E&P Company, L.P.	Member		100.0000
El Paso SPM Company	Delaware	El Paso Merchant Energy Company	Stockholder		100.0000
El Paso Tankships Malta, Ltd.	Malta	Coscol Holding Company Ltd.	Owner		1.0000
		El Paso SLOC Holding Company	Owner		99.0000
El Paso Tankships USA Company	Delaware	Coscol Petroleum Corporation	Stockholder		100.0000
El Paso Technology Pakistan (Private) Limited	Pakistan	Directors/Officers/Other Individuals	Individual Owner(s)		0.0003
		El Paso Technology, Inc.	Owner		99.9997
El Paso Technology, Inc.	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
El Paso Telecom, L.L.C.	Delaware	El Paso Global Networks Company	Member		100.0000
El Paso Tennessee Pipeline Co.	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso TGPC Investments, L.L.C.	Delaware	El Paso Tennessee Pipeline Co.	Member		100.0000
El Paso Transmission Company	Delaware	El Paso Tennessee Pipeline Co.	Stockholder		100.0000
El Paso Wyoming Gas Supply Company	Delaware	Colorado Interstate Gas Company	Stockholder		100.0000
Elba Express Company, L.L.C.	Delaware	Southern Natural Gas Company	Member		100.0000
Emerald Finance, L.L.C.	Delaware	El Paso Energia Cayman I Limited	Member		100.0000
Empresa Energetica Sierra Chaco S.A.	Bolivia	Directors/Officers/Other Individuals	Individual Owner(s)		0.3333
		EPED Holding Company	Owner		99.6667
EnCap Holdings (Cayman) Company	Cayman Islands	El Paso Merchant Energy International Company	Owner		100.0000
EnCap Investments L.L.C.	Delaware	David Miller	Unaffiliated Parties		8.3333
		Martin Phillips	Unaffiliated Parties		8.3333
		Gary Petersen	Unaffiliated Parties		8.3333
		Robert Zorich	Unaffiliated Parties		8.3333
		El Paso Merchant Energy North America Company	Member		33.3333
		EnCap Investments L.P.	Unaffiliated Parties		33.3333
Energy Maritime Holdings LLC	Delaware	El Paso Tankships USA Company	Member		50.0000
		C-Shuttle, L.L.C.	Unaffiliated Parties		50.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 15

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Energy Maritime LLC	Delaware	Energy Maritime Holdings LLC	Member		100.0000
EnerVest Energy, L.P.	Delaware	Coronado Energy E&P Company, L.L.C.	Partner		23.0000
		Unaffiliated Party/Parties unknown	Partner		77.0000
Enfield Holdings B.V.	Netherlands	EPIC Energy Hungary B.V.	Owner		50.0000
		NRGenerating International B.V.	Unaffiliated Parties		50.0000
EP Connect, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
EP Power Finance, L.L.C.	Delaware	El Paso Merchant Energy North America Company	Member		100.0000
EPEC Communications Corporation	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
EPEC Corporation	Delaware	El Paso Services Holding Company	Stockholder		100.0000
EPEC Gas Brazil Corporation	Delaware	El Paso Energy International Company	Stockholder		100.0000
EPEC Gas Canada Ltd.	Canada	El Paso Energy International Company	Owner		100.0000
EPEC Gas Chile Corporation	Delaware	El Paso Energy International Company	Stockholder		100.0000
EPEC Nederland B.V.	Netherlands	El Paso Corporation	Owner		100.0000
EPEC Polymers, Inc.	Delaware	El Paso Remediation Company	Stockholder		100.0000
EPEC Realty, Inc.	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
EPEC West, Inc.	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
EPED B Company	Cayman Islands	EPED Holding Company	Owner		100.0000
EPED Holding Company	Delaware	El Paso Energy International Company	Stockholder		100.0000
EPED SAM Holdings Company	Delaware	EPED Holding Company	Stockholder		100.0000
EPIC Energy (Australia) Nominees Pty. Ltd.	Australia	Directors/Officers/Other Individuals	Individual Owner(s)		0.2217
		El Paso DBNGP Limited	Owner		33.2594
		CNG Labuan One Limited	Owner		33.2594
		Isarose Pty Limited	Unaffiliated Parties		33.2594
EPIC Energy Amazon Company	Cayman Islands	Amethyst Power Holdings, L.L.C.	Owner		100.0000
EPIC Energy Australia Trust	Australia	El Paso DBNGP Limited	Owner		33.3000
		CNG Labuan One Limited	Owner		33.3000
		Unaffiliated Party/Parties unknown	Unaffiliated Parties		33.4000
EPIC Energy Hungary B.V.	Netherlands	El Paso Energy International Company	Owner		100.0000
EPIC Gas International Servicos do Brasil Ltda.	Brazil	El Paso Services Holding Company	Owner		0.0001
		El Paso Energy International Company	Owner		14.9736

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 16

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		EPEC Gas Brazil Corporation	Owner		85.0263
EPNG Finance Company, L.L.C.	Delaware	El Paso Natural Gas Company	Member		100.0000
EPNG Funding Company, L.L.C.	Delaware	EPNG Finance Company, L.L.C.	Member		100.0000
EPNG Mojave, Inc.	Delaware	El Paso Natural Gas Company	Stockholder		100.0000
EPPP CIG GP Holdings, L.L.C.	Delaware	El Paso Noric Investments III, L.L.C.	Member		100.0000
EPPP SNG GP Holdings, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
Fife Power	Scotland	El Paso Fife I Company	Owner		50.0000
		Fife Limited	Unaffiliated Parties		50.0000
Florida Gas Transmission Company, LLC	Delaware	Citrus Corp.	Member		100.0000
Four Star Oil & Gas Company	Delaware	Texaco Nederland BV	Unaffiliated Party — Owner of Class A Stock		0.2787
		Chevron Texaco Global Energy Inc.	Unaffiliated Party — Owner of Class A and Class B Stock		19.8439
		Chevron U.S.A. Inc.	Unaffiliated Party — Owner of Class A and Class B Stock		31.1037
		MBOW Four Star Corporation	Stockholder		48.7737
Garnet Power Holdings, L.L.C.	Delaware	EPED B Company	Member		100.0000
Gas de Chile S.A.	Chile	EPEC Gas Chile Corporation	Owner		50.0000
		Empresa Nacional del Petroleo S.A.	Unaffiliated Parties		50.0000
Gas TransBoliviano S.A.	Bolivia	EPED B Company	Owner		2.0000
		BG Overseas Holdings Limited	Unaffiliated Parties		2.0000
		Petrobras Gas S.A.	Unaffiliated Parties		11.0000
		Shell Gas (Latin America) B.V.	Unaffiliated Parties		17.0000
		Enron (Bolivia) C.V.	Unaffiliated Parties		17.0000
		Transredes S.A.	Unaffiliated Parties		51.0000
Gasoducto del Pacifico (Argentina) S.A.	Argentina	YEF Sociedad Argentina	Unaffiliated Parties		10.0000
		Empresa Nacional del Petroleo S.A.	Unaffiliated Parties		18.2000
		Compania de Consumidores de Gas de Santiago S.A.	Unaffiliated Parties		20.0000
		El Paso Energy Argentina Limitada S.A.	Owner of Preferred Stock		21.8000
		Nova Gas Sur Gas Transmission (Argentina) Ltd.	Unaffiliated Parties		30.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 17

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Gasoducto del Pacifico (Cayman) Ltd.	Cayman Islands	YPF Societe Anonima	Unaffiliated Parties		10.0000
		Nova Gas Sur Gas Transmission (Argentina) Ltd.	Unaffiliated Parties		15.0000
		Nova Gas Sur Gas Transmission (Chile) Ltd.	Unaffiliated Parties		15.0000
		Empresa Nacional del Petroleo S.A.	Unaffiliated Parties		18.2000
		Gasco S.A.	Unaffiliated Parties		20.0000
		Triunion Energy Pacifico Company	Owner		21.8000
Gasoducto del Pacifico S.A.	Chile	Repsol YPF Chile Ltda.	Unaffiliated Parties		10.0000
		Empresa Nacional del Petroleo S.A.	Unaffiliated Parties		18.2000
		Gasco S.A.	Unaffiliated Parties		20.0000
		Triunion Energy Inversiones Pacifico (Chile) Limitada	Owner of Preferred Stock		21.8000
		Nova Gas Sur Gas Transmission (Argentina) Ltd.	Unaffiliated Parties		30.0000
Gasoductos de Chihuahua, S. de R.L. de C.V.	Mexico	Pemex — Gas Y Petroquimica Basica	Unaffiliated Parties		50.0000
		El Paso Energy International Company	Owner		50.0000
Gasoductos de Tamaulipas, S. de R.L. de C.V.	Mexico	Gasoductos Servicios, S. de R.L. de C.V.	Owner		0.0100
		Gasoductos de Chihuahua, S. de R.L. de C.V.	Owner		99.9900
Gasoductos Servicios, S. de R.L. de C.V.	Mexico	Gasoductos de Tamaulipas, S. de R.L. de C.V.	Owner		0.0100
		Gasoductos de Chihuahua, S. de R.L. de C.V.	Owner		99.9900
GEBF, L.L.C.	Louisiana	ConocoPhillips Company	Unaffiliated Parties		33.3333
		Chevron U.S.A. Inc.	Unaffiliated Parties		33.3333
		Vermilion Bay Land, L.L.C.	Member		33.3334
Gemstone Investor Limited	Cayman Islands	EPED Holding Company	Owner of Ordinary Class A Stock		100.0000
Gemstone Investor, Inc.	Delaware	Gemstone Investor Limited	Stockholder		100.0000
Grupo El Paso, S. de R.L. de C.V.	Mexico	El Paso El Sauz B.V.	Owner		0.0300
		El Paso Nederland Energie B.V.	Owner		99.9700
Habibullah Coastal Power Company (Private) Limited	Pakistan	Directors/Officers/Other Individuals	Individual Owner(s)		0.0001
		Quetta Power Holding Company II Ltd.	Owner		0.9999
		Quetta Power Holding Company I Ltd.	Owner		99.0000
Harbortown Commercial Partnership	Michigan	MichCon Development Corp.	Unaffiliated Parties		33.3330

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 18

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		ANR Development Company, L.L.C.	General Partner		66.6670
Harbortown Condominium Partnership	Michigan	MichCon Development Corp.	Unaffiliated Parties		33.3330
		ANR Development Company, L.L.C.	General Partner		66.6670
Harbortown Development Partnership	Michigan	MichCon Development Corp.	Unaffiliated Parties		33.3330
		ANR Development Company, L.L.C.	General Partner		66.6670
Harbortown Limited Dividend Housing Association	Michigan	ANR Development Company, L.L.C.	General Partner		50.0000
		MichCon Development Corp.	Unaffiliated Parties		50.0000
Interenergy Company	Cayman Islands	EPED B Company	Owner		100.0000
Inversiones EPEC Gas (Chile) Limitada	Chile	El Paso Latin America Inc.	Owner		0.0001
		EPEC Gas Chile Corporation	Owner		99.9999
Jewel Investor, L.L.C.	Delaware	EPED Holding Company	Member		100.0000
Khulna Power Company Ltd.	Bangladesh	Wartsila Development & Financial Services (Asia) Ltd.	Unaffiliated Party — Owner of Class A and Class B Stock		6.1000
		Summit Industrial & Mercantile Corporation (Pvt) Ltd.	Unaffiliated Party — Owner of Class A and Class B Stock		10.0000
		United Enterprises & Company Ltd.	Unaffiliated Party — Owner of Class A and Class B Stock		10.0000
		El Paso Khulna Power ApS	Owner of Class A and Class B Stock		73.9000
KLT Power Asia	Cayman Islands	KLT Power Inc.	Owner		100.0000
KLT Power Inc.	Missouri	EPED Holding Company	Stockholder		100.0000
MBOW Four Star Corporation	Delaware	El Paso Exploration & Production Company	Stockholder		100.0000
McCoy Caney Coal Company	Delaware	Coastal Coal, Inc.	Stockholder		100.0000
Mesquite Investors, L.L.C.	Delaware	Chaparral Investors, L.L.C.	Member		100.0000
Mojave Pipeline Company	Texas	El Paso Mojave Pipeline Co.	Partner		50.0000
		EPNG Mojave, Inc.	Partner		50.0000
Mojave Pipeline Operating Company	Texas	Mojave Pipeline Company	Stockholder		100.0000
Mont Belvieu Land Company	Delaware	El Paso Remediation Company	Stockholder		100.0000
Mt. Franklin Insurance Ltd.	Bermuda	El Paso Corporation	Owner		100.0000
Pacific Refining Company	California	El Paso Merchant Energy-Petroleum Company	Partner		2.0000
		Coastal West Ventures, Inc.	Partner		98.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 19

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Palembang Coastal Technology (Singapore) Pte Ltd.	Singapore	Coastal Technology Palembang (Cayman) Ltd.	Owner		100.0000
Peridot Finance S.a.r.l.	Luxembourg	Diamond Power Holdings, L.L.C.	Owner		100.0000
Petro-Tex Chemical Corporation Dissolution, Distribution, Liquidating and Recovery Trust		EPEC Polymers, Inc.	Trustee		100.0000
Polar Delta Project Ltd.	Canada	EPEC Gas Canada Ltd.	Owner		50.0000
		TransCanada Pipelines Ltd.	Unaffiliated Parties		50.0000
Potiguar 4A LLC	Delaware	Potiguar I, L.L.C.	Member		100.0000
Potiguar 4B LLC	Delaware	Potiguar I, L.L.C.	Member		100.0000
Potiguar I, L.L.C.	Delaware	El Paso Production International Cayman Company	Member		100.0000
Potiguar II, L.L.C.	Delaware	Potiguar I, L.L.C.	Member		100.0000
Quetta Operating Company (Private) Limited	Pakistan	Directors/Officers/Other Individuals	Individual Owner(s)		0.0001
		El Paso Technology, Inc.	Owner		99.9999
Quetta Power Holding Company I Ltd.	Cayman Islands	H.E.I. Ltd.	Unaffiliated Parties		25.0000
		Habibullah Energy Limited (Pakistan)	Unaffiliated Parties		25.0000
		Coastal Power International II Ltd.	Owner		50.0000
Quetta Power Holding Company II Ltd.	Cayman Islands	Coastal Power International II Ltd.	Owner		1.0000
		Habibullah Energy Limited	Unaffiliated Parties		1.0000
		Quetta Power Holding Company I Ltd.	Owner		98.0000
Rondonia Power Company	Cayman Islands	El Paso Rondonia Power Company	Owner		50.0000
		Termo Gas International	Unaffiliated Parties		50.0000
Saba Power Company (Private) Limited	Pakistan	Directors/Officers/Other Individuals	Individual Owner(s)		0.0001
		Capco Resources, Inc.	Unaffiliated Parties		1.1499
		Cogen Technologies Saba Capital Company LLC	Unaffiliated Parties		4.7100
		Coastal Saba Power Ltd.	Owner		94.1400
Samalayuca II Management, L.L.C.	Delaware	EPED SAM Holdings Company	Member		50.0000
		Samalayuca Construction Management Corporation	Unaffiliated Parties		50.0000
Sandbar Petroleum Company	Delaware	El Paso Energy International Company	Stockholder		100.0000
Seafarer Bahamas Pipeline System, Ltd.	Bahamas	Directors/Officers/Other Individuals	Individual Owner(s)		0.0400
		El Paso Bahamas Holding B.V.	Owner		99.9600

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 20

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Seafarer US Pipeline System, Inc.	Delaware	El Paso Corporation	Stockholder		100.0000
Sierra 1996-I Limited Partnership	Texas	Unaffiliated Party/Parties unknown	General Partner		1.0000
		Coronado Energy E&P Company, L.L.C.	Limited Partner		99.0000
SNG Finance Company, L.L.C.	Delaware	Southern Natural Gas Company	Member		100.0000
SNG Funding Company, L.L.C.	Delaware	SNG Finance Company, L.L.C.	Member		100.0000
SNG Pipeline Services Company, L.L.C.	Delaware	El Paso SNG Holding Company, L.L.C.	Member		100.0000
SNG RenCen Company, L.L.C.	Delaware	Southern Natural Gas Company	Member		100.0000
Sonora LNG Terminal Holding, S. de R.L. de C.V.	Mexico	Sonora Pipeline Holding, S de R. L. de C.V.	Owner		0.0300
		Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		99.9700
Sonora Pipeline Holding, S de R. L. de C.V.	Mexico	Sonora LNG Terminal Holding, S. de R.L. de C.V.	Owner		0.0300
		Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		99.9700
Sonora Pipeline, S. de R.L. de C.V.	Mexico	Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		0.0300
		Sonora Pipeline Holding, S de R. L. de C.V.	Owner		99.9700
Sonora Services Energy, S. de R.L. de C.V.	Mexico	Sonora Pipeline Holding, S de R. L. de C.V.	Owner		0.0300
		Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		99.9700
Sonora Terminal and Pipeline, S. de R.L. de C.V.	Mexico	Sonora Pacific Mexico S. de R.L. de C.V.	Unaffiliated Parties		50.0000
		Grupo El Paso, S. de R.L. de C.V.	Owner		50.0000
Southeast Storage Development Company, L.L.C.	Delaware	Southern Natural Gas Company	Member		100.0000
Southern Gas Storage Company	Delaware	Southern Natural Gas Company	Stockholder		100.0000
Southern Gulf LNG Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
Southern LNG Inc.	Delaware	Southern Natural Gas Company	Stockholder		100.0000
Southern Natural Gas Company	Delaware	El Paso Corporation	Stockholder		100.0000
Starr County Gathering System	Texas	EEX Natural Gas Company	Unaffiliated Parties		1.0000
		El Paso CGP Gas Transmission Company	General Partner		30.0000
		EEX Pipeline Company, L.P.	Unaffiliated Parties		69.0000
Starr-Zapata Pipe Line	Texas	EEX Natural Gas Company	Unaffiliated Parties		1.0000
		EEX Pipeline Company, L.P.	Unaffiliated Parties		49.0000
		El Paso CGP Gas Transmission Company	General Partner		50.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 21

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Subic Bay Petroleum Products Ltd.	Cayman Islands	Coastal Stock Company Limited	Owner		100.0000
TCN Energia Ltda.	Brazil	El Paso Energia do Brasil Ltda.	Owner		0.0500
		EPED B Company	Owner		99.9500
TDF, S. de R.L. de C.V.	Mexico	Gasoductos Servicios, S. de R.L. de C.V.	Owner		0.0001
		Transportadora del Norte SH, S. de R.L. de C.V.	Owner		99.9999
Tennessee Gas Pipeline Company	Delaware	El Paso TGPC Investments, L.L.C.	Stockholder		100.0000
Tennessee Storage Company	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
Terminal GNL de Sonora, S. de R.L. de C.V.	Mexico	Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		0.0300
		Sonora LNG Terminal Holding, S. de R.L. de C.V.	Owner		99.9700
Termo Norte Energia Ltda.	Brazil	CS Participacoes Ltda.	Unaffiliated Parties		0.0001
		El Paso Energia do Brasil Ltda.	Owner		0.0001
		Rondonia Power Company	Owner		99.9998
Termo O&M Energia Ltda.	Brazil	El Paso O&M do Brasil Ltda.	Owner		50.0000
		Termogas S/A	Unaffiliated Parties		50.0000
TGP Finance Company, L.L.C.	Delaware	Tennessee Gas Pipeline Company	Member		100.0000
TGP Funding Company, L.L.C.	Delaware	TGP Finance Company, L.L.C.	Member		100.0000
Tipitapa Power Company Ltd.	Cayman Islands	Coastal Power Nicaragua Holding Company Ltd.	Owner		1.0000
		Unaffiliated Parties	Unaffiliated Parties		40.0000
		Coastal Power Nicaragua Ltd.	Owner		59.0000
TNG Participacoes Ltda.	Brazil	Dutonorte Investimentos Ltda	Owner		50.0000
		Petrobras Gas S.A.	Unaffiliated Parties		50.0000
Topaz Power Ventures, L.L.C.	Delaware	EPED Holding Company	Member		100.0000
Transport USA, Inc.	Pennsylvania	ANR Advance Holdings, Inc.	Stockholder		100.0000
Transportadora Brasiliera Gasoduto Bolivia-Brazil S.A.	Brazil	Shell	Unaffiliated Parties		4.0000
		Enron	Unaffiliated Parties		4.0000
		Transporte de Hidrocarburos	Unaffiliated Parties		12.0000
		BBPP Holdings Ltda.	Owner		29.0000
		Petrobras affiliate	Unaffiliated Parties		51.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 22

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Transportadora del Norte SH, S. de R.L. de C.V.	Mexico	Gasoductos Servicios, S. de R.L. de C.V.	Owner		0.0001
		Gasoductos de Chihuahua, S. de R.L. de C.V.	Owner		99.9999
Triunion Energy Company	Cayman Islands	EPED B Company	Owner		23.2000
		Agua del Cajon (Cayman) Company	Owner		38.4000
		Interenergy Company	Owner		38.4000
Triunion Energy Inversiones (Chile) Limitada	Chile	Triunion Energy Company	Owner		0.4200
		Triunion Energy Pacifico Company	Owner		99.5800
Triunion Energy Inversiones Company	Cayman Islands	Triunion Energy Company	Owner		100.0000
Triunion Energy Inversiones Pacifico (Chile) Limitada	Chile	Triunion Energy Pacifico Company	Owner		0.2200
		Triunion Energy Inversiones (Chile) Limitada	Owner		99.7800
Triunion Energy Pacifico Company	Cayman Islands	Triunion Energy Inversiones Company	Owner		100.0000
United Summit Coastal Oil Ltd.	Bangladesh	Summit Industrial & Mercantile Corporation (Pvt) Ltd.	Unaffiliated Parties		25.0000
		United Enterprises & Company Ltd.	Unaffiliated Parties		25.0000
		Coastal Petroleum N.V.	Owner		50.0000
UnoPaso Exploracao e Producao de Petroleo e Gas Ltda.	Brazil	Potiguar 4B LLC	Owner		0.0001
		El Paso Oleo e Gas do Brasil Ltda.	Owner		0.0001
		Potiguar II, L.L.C.	Owner		99.9998
Vermilion Bay Land, L.L.C.	Delaware	Crystal Gas Storage, Inc.	Member		100.0000
Western Fuel Oil Company	California	Pacific Refining Company	Stockholder		100.0000
WIC Holdings, Inc.	Delaware	Colorado Interstate Gas Company	Stockholder		100.0000
WYCO Development LLC	Colorado	Xcel Energy WYCO Inc.	Unaffiliated Parties		50.0000
		WIC Holdings, Inc.	Member		50.0000
WYCO Holding Company, L.L.C.	Delaware	Colorado Interstate Gas Company	Member		100.0000
Wyoming Interstate Company, Ltd.	Colorado	El Paso Wyoming Gas Supply Company	Limited Partner		50.0000
		WIC Holdings, Inc.	General Partner		50.0000
Young Gas Storage Company, Ltd.	Colorado	The City of Colorado Springs	Unaffiliated Parties — LP Owner		5.0000
		CIG Gas Storage Company	General Partner		47.5000
		Xcel Energy Markets Holdings Inc.	Unaffiliated Parties		47.5000
Zipline, L.L.C.	Delaware	Genesis Park GP Company, L.L.C.	Unaffiliated Parties		50.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 23

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		El Paso Global Networks Company	Member		50.0000

Third Amended and Restated Credit Agreement

Schedule 4.16 — Page 24

SCHEDULE 6.08

EXISTING RESTRICTIVE AGREEMENTS

1. EL PASO NATURAL GAS COMPANY

(a) Indenture dated as of January 1, 1992, between El Paso Natural Gas Company and Citibank, N.A. (subsequently replaced by Wilmington Trust Company).

(i) Prospectus Supplement dated as of January 9, 1992, to Prospectus dated January 9, 1992 ($260 Million 8.625% Debentures due 1/15/22).

(b) Indenture dated as of November 13, 1996 between El Paso Natural Gas Company and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company).

(i)	Prospectus Supplement dated as of November 7, 1996 to Prospectus dated November 5, 1996 ($200 Million 7.5% Debentures due 11/15/26).
(ii)	First Supplemental Indenture dated as of June 10, 2002 ($300 Million 8.375% Notes due 6/15/32).
(iii)	Second Supplemental Indenture dated as of April 4, 2007 ($355 Million 5.95% Notes due 4/15/17).

(c) Indenture dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company ($355,000,000 7.625% Notes due 2010).

2. EL PASO TENNESSEE PIPELINE CO.

(a) Indenture, dated as of March 15, 1988, between Tenneco, Inc. (now El Paso Tennessee Pipeline Co.) and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company).

(i)	Second Supplemental Indenture dated as of March 30, 1988 ($250 Million 10% Debentures due 3/15/08, outstanding balance $26.4 Million).
(ii)	Tenth Supplemental Indenture dated as of November 15, 1992 ($150 Million 9% Debentures due 11/15/12, outstanding principal $1.1 Million).
(iii)	Twelfth Supplemental Indenture dated as of December 15, 1995 ($300 Million 7.25% Debentures due 12/15/25, outstanding principal $23.2).
(iv)	Thirteenth Supplemental Indenture dated as of December 10, 1996 (various amendments).

Third Amended and Restated Credit Agreement

Schedule 6.08 — Page 1

3. TENNESSEE GAS PIPELINE COMPANY

(a) Indenture, dated as of December 15, 1981, between Tenneco Inc. (now Tennessee Gas Pipeline Company (“TGPC”)) and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company) ($400 Million 6% Debentures due 12/15/11, current balance $85.8 Million).

(i)	First Supplemental Indenture dated as of December 10, 1996 (various amendments, mainly name change to TGPC).
(ii)	Second Supplemental Indenture dated as of December 10, 1996 (various amendments).

(b) Indenture, dated as of March 4, 1997, between Tennessee Gas Pipeline Company and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company).

(i)	First Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.5% Debentures due 4/1/17).
(ii)	Second Supplemental Indenture dated as of March 13, 1997 ($300 Million 7% Debentures due 3/15/27, put date 3/15/07, redeemable after 3/15/07).
(iii)	Third Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.625% Debentures due 10/15/37).
(iv)	Fourth Supplemental Indenture dated as of October 9, 1998 ($400 Million 7% Debentures due 10/15/28).
(v)	Fifth Supplemental Indenture dated as of June 10, 2002 ($240 Million 8.375% Notes due 6/15/32)

Third Amended and Restated Credit Agreement

Schedule 6.08 — Page 2

SCHEDULE 10.16(a)

RELEASED SUBSIDIARIES

El Paso CNG Company, L.L.C.

El Paso Noric Investments III, L.L.C.

EPPP CIG GP Holdings, L.L.C.

Colorado Interstate Gas Company

EXHIBIT A

FORM OF

ASSIGNMENT AND ASSUMPTION

     Reference is made to the Third Amended and Restated Credit Agreement dated as of November 16, 2007 (as amended and in effect on the date hereof, the “Credit Agreement”), among EL PASO CORPORATION, a Delaware corporation (the “Company”), EL PASO NATURAL GAS COMPANY, a Delaware corporation, TENNESSEE GAS PIPELINE COMPANY, a Delaware corporation, the several banks and other financial institutions from time to time parties thereto (the “Lenders”), and JPMORGAN CHASE BANK, N.A., as administrative agent (the “Administrative Agent”) and as collateral agent.

     The Assignor named on the reverse hereof hereby sells and assigns, without recourse, to the Assignee named on the reverse hereof, and the Assignee hereby purchases and assumes, without recourse, from the Assignor, effective as of the Assignment Date set forth on the reverse hereof, the interests set forth on the reverse hereof (the “Assigned Interest”) in the Assignor’s rights and obligations under the Credit Agreement, including the interests set forth on the reverse hereof in the Commitment of the Assignor on the Assignment Date and Loans owing to the Assignor which are outstanding on the Assignment Date, in the case of a Revolving Commitment or Revolving Loan together with the participations in Letters of Credit and LC Disbursements held by the Assignor on the Assignment Date, but excluding accrued interest and fees to and excluding the Assignment Date. The Assignee hereby acknowledges receipt of a copy of the Credit Agreement and the Security Agreement (as defined in the Credit Agreement). From and after the Assignment Date (i) the Assignee shall be a party to and be bound by the provisions of the Credit Agreement and, to the extent of the Assigned Interest, have the rights and obligations of a Lender thereunder, (ii) the Assignee acknowledges that, upon becoming a Lender under the Credit Agreement, it is subject to, and hereby agrees to be bound by, the terms and provisions of the Credit Agreement, and (iii) the Assignor shall, to the extent of the Assigned Interest, relinquish its rights and be released from its obligations under the Credit Agreement, except that the Assignor shall continue to be entitled to the benefits of Sections 2.13, 2.14, 2.15 and 10.03.

     This Assignment and Assumption is being delivered to the Administrative Agent together with (i) if the Assignee is a Foreign Lender, any documentation required to be delivered by the Assignee pursuant to Section 2.15(e) of the Credit Agreement, duly completed and executed by the Assignee, and (ii) if the Assignee is not already a Lender under the Credit Agreement, an Administrative Questionnaire in the form supplied by the Administrative Agent, duly completed by the Assignee. The Assignor represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, and (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim. The [Assignee/Assignor] shall pay the fee payable to the Administrative Agent pursuant to Section 10.04(b) of the Credit Agreement.

Exhibit A – Page 4
Third Amended and Restated Credit Agreement

     This Assignment and Assumption shall be governed by and construed in accordance with the laws of the State of New York.

Date of Assignment:

Legal Name of Assignor:

Legal Name of Assignee:

Assignee’s Address for Notices:

Effective Date of Assignment
(“Assignment Date”):

			Percentage Assigned of
Facility	Principal Amount Assigned		Facility/Commitment1
Revolving Commitment Assigned:		$		%
Revolving Loans Assigned:		$		%

     The Assignee agrees to deliver to the Administrative Agent a completed Administrative Questionnaire in which the Assignee designates one or more Credit Contacts to whom all syndicate-level information (which may contain material non-public information about the Borrowers, the Credit Parties and their Related Parties or their respective securities) will be made available and who may receive such information in accordance with the Assignee’s compliance procedures and applicable laws, including Federal and state securities laws.

     The terms set forth above and on the reverse side hereof are hereby agreed to:

[Name of Assignor], as Assignor

By:

Name:

Title:

[Name of Assignee], as Assignee

By:

¹ Set forth, to at least 8 decimals, as a percentage of the applicable Facility and the aggregate Commitments of all Lenders thereunder.

Third Amended and Restated Credit Agreement

Exhibit A – Page 5

Name:

Title:

Third Amended and Restated Credit Agreement

Exhibit A – Page 6

     The undersigned hereby consent to the within assignment:²

EL PASO CORPORATION		JPMORGAN CHASE BANK, N.A., as Administrative Agent
By:		By:
	Name:		Name:
	Title:		Title:
JPMORGAN CHASE BANK, N.A., as an Issuing Bank		CITIBANK, N.A., as an Issuing Bank
By:		By:
	Name:		Name:
	Title:		Title:

[Other Issuing Banks]

² If required.

Third Amended and Restated Credit Agreement

Exhibit A – Page 7

EXHIBIT B

FORM OF

BORROWING REQUEST

JPMorgan Chase Bank, N.A.,
   as Administrative Agent for the Lenders
   parties to the Credit Agreement referred to below
   Technology, Shared Tech & Operation Commercial Loans
   L&A Project Texas
1111 Fannin, Floor 10
Houston, TX 77002
Attention:    Ina S. Tjahjono

     Ladies and Gentlemen:

     The undersigned, EL PASO CORPORATION, refers to the Third Amended and Restated Credit Agreement, dated as of November 16, 2007 (the “Credit Agreement”, the terms defined therein being used herein as therein defined), among the undersigned, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, certain Lenders parties thereto, and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent, and hereby gives you notice, irrevocably, pursuant to Section 2.03 of the Credit Agreement that the undersigned hereby requests a Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Borrowing (the “Proposed Borrowing”) as required by Section 2.03 of the Credit Agreement:

          (i) The Borrower for the Proposed Borrowing is                     .

          (ii) The Business Day of the Proposed Borrowing is                     , 200_.

          (iii) The Proposed Borrowing is a [ABR Borrowing] [Eurodollar Borrowing].

          (iv) The aggregate amount of the Proposed Borrowing is $                    .

          (v) The initial Interest Period for each Eurodollar Loan made as part of the Proposed Borrowing is [                     month[s]].

          (vi) The account to which the funds of the Proposed Borrowing are to be disbursed is                     .

          (vii) The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing, before and immediately after giving effect thereto and to the application of the proceeds therefrom:

     (A) The representations and warranties of each Borrower and each other Credit Party set forth in this Agreement and the other Loan Documents shall be true and correct in all material respects

Third Amended and Restated Credit Agreement

Exhibit B – Page 1

on and as of the date of the Proposed Borrowing, unless stated to be made on or as of, or to relate to, a specific date or period other than the date of the Proposed Borrowing; and

     (B) at the time of and immediately after giving effect to the Proposed Borrowing (and if any proceeds thereof are being applied substantially contemporaneously to satisfy any other obligation, to such application), no Default shall have occurred and be continuing.

Very truly yours,

EL PASO CORPORATION

By:

Title:

Third Amended and Restated Credit Agreement

Exhibit B – Page 2

EXHIBIT C

FORM OF

NOTE

$	New York, New York
	, 200_

     FOR VALUE RECEIVED, the undersigned, [Name of Borrower], a Delaware corporation (the “Borrower”) hereby unconditionally promises to pay to the order of                      (the “Lender”) at the office of JPMorgan Chase Bank, N.A., located at 270 Park Avenue, New York, New York 10017, in lawful money of the United States of America and in immediately available funds, the principal amount of the lesser of (a)                      ($                    ), and (b) the aggregate unpaid principal amount of all Loans made by the Lender to the undersigned pursuant to Section 2.02 of the Credit Agreement (as defined below), on the Maturity Date (as defined in the Credit Agreement) and on such other dates and in such other amounts set forth in the Credit Agreement.

     The undersigned further agrees to pay interest in like money at such office on the unpaid principal amount hereof from time to time from the date hereof at the applicable rate per annum set forth in Section 2.11 of the Credit Agreement until any such amount shall become due and payable (whether at the stated maturity, by acceleration or otherwise), and thereafter on such overdue amount at the rate per annum set forth in paragraph (c) of Section 2.11 of the Credit Agreement until paid in full (both before and after judgment). Interest shall be payable in arrears on each Interest Payment Date commencing on the first such date to occur after the date hereof, provided that interest accruing pursuant to paragraph (c) of Section 2.11 of the Credit Agreement shall be payable on demand. In no event shall the interest payable hereon, whether before or after maturity, exceed the maximum interest which, under applicable law, may be charged on this Note, and this Note is expressly made subject to the provisions of the Credit Agreement which more fully set out the limitations on how interest accrues hereon.

     The holder of this Note is authorized to record the date, type and amount of each Loan made by the Lender pursuant to Section 2.02 of the Credit Agreement, each continuation thereof, each conversion of all or a portion thereof to another type, the date and amount of each payment or prepayment of principal with respect thereto, and, in the case of Eurodollar Loans, the length of each Interest Period with respect thereto, on the schedules annexed hereto and made a part hereof, or on a continuation thereof which shall be attached hereto and made a part hereof, which recordation shall constitute prima facie evidence of the accuracy of the information recorded in the absence of manifest error; provided that failure by the Lender to make any such recordation on this Note shall not affect the obligations of the Borrower under this Note or the Credit Agreement.

     This Note is one of the Notes referred to in the Third Amended and Restated Credit Agreement, dated as of November 16, 2007 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among the Borrower, [the Company], [EPNGC] and [TGPC], the Lender, the other financial institutions parties thereto, and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent, is entitled to the benefits thereof, is

Third Amended and Restated Credit Agreement

Exhibit C – Page 1

secured as provided therein and in the Security Documents and is subject to optional and mandatory prepayment in whole or in part as provided therein. Terms used herein which are defined in the Credit Agreement shall have such defined meanings unless otherwise defined herein or unless the context otherwise requires.

     Upon the occurrence of any one or more of the Events of Default specified in the Credit Agreement, all amounts then remaining unpaid on this Note shall become, or may be declared to be, immediately due and payable all as provided therein.

     This Note and the other Notes are given in replacement and substitution for, but not payment or satisfaction of, certain revolving credit notes previously issued under the Credit Agreement. The indebtedness evidenced by such other revolving credit notes is continued in full force and effect hereunder.

     THIS NOTE SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

     This Note evidences existing indebtedness under the Credit Agreement and does not constitute payment of such indebtedness, and such indebtedness continues in full force and effect, as amended and restated in the Credit Agreement.

[Name of Borrower]

By:

Name:

Title:

Third Amended and Restated Credit Agreement

Exhibit C – Page 2

SCHEDULE A
to Note

EURODOLLAR LOANS AND CONVERSIONS AND PAYMENTS WITH RESPECT TO EURODOLLAR LOANS

	Amount of Eurodollar Loans	Amount of Eurodollar Loans
	Made or Converted from	Paid or Converted into	Unpaid Principal Balance of
Date	Alternate Base Rate Loans	Alternate Base Rate Loans	Eurodollar Rate Loans	Notation Made By

Third Amended and Restated Credit Agreement

Exhibit C - Schedule A – Page 1

SCHEDULE B
to Note

ALTERNATE BASE RATE LOANS AND CONVERSIONS AND PAYMENTS
WITH RESPECT TO ALTERNATE BASE RATE LOANS

	Amount of Alternate Base Rate	Amount of Alternate Base Rate
	Loans Made or Converted from	Loans Paid or Converted into	Unpaid Principal Balance of
Date	Eurodollar Loans	Eurodollar Loans	Alternate Base Rate Loans	Notation Made By

Third Amended and Restated Credit Agreement

Exhibit C - Schedule B – Page 1

EXHIBIT D

FORM OF

THIRD AMENDED AND RESTATED
SECURITY AGREEMENT

EXECUTION VERSION

THIRD AMENDED AND RESTATED SECURITY AGREEMENT

dated as of November ___, 2007

among

EL PASO CORPORATION,

THE PERSONS REFERRED TO HEREIN AS
PIPELINE COMPANY BORROWERS,

THE PERSONS REFERRED TO HEREIN AS SUBSIDIARY GRANTORS

and

JPMORGAN CHASE BANK, N.A.,
as Collateral Agent and Depository Bank

TABLE OF CONTENTS

	Page
ARTICLE 1 Definitions And Interpretation
Section 1.01. Definitions		2
Section 1.02. Principles of Interpretation		7
ARTICLE 2 . [Reserved]
ARTICLE 3 Representations And Warranties
Section 3.01. Representations And Warranties of The Credit Parties		8
ARTICLE 4 Pledged Accounts
Section 4.01. Creation of Pledged Accounts		10
Section 4.02. Cash Collateral Account		12
Section 4.03. Qualified Investments Account		13
Section 4.04. Payments In Trust		15
Section 4.05. Investment of Funds In Pledged Accounts		16
Section 4.06. Transfers From Accounts During The Continuance of An Event of Default		17
Section 4.07. Reports, Certification And Instructions		17
Section 4.08. Depository Bank Undertakings		18
Section 4.09. Force Majeure		21
Section 4.10. Clearing Agency		21
Section 4.11. Return of Funds to the Company		21
ARTICLE 5 Security Interests
Section 5.01. Grant of Security Interests		21
Section 5.02. Security For Obligations		24
Section 5.03. Delivery And Control of Collateral		25
Section 5.04. Further Assurances; Etc		25
Section 5.05. Grantors Remain Liable		26
Section 5.06. Additional Equity Interests		27

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	Page
Section 5.07. Release of Collateral		27
Section 5.08. Voting Rights, Dividends, Payments, Etc		28
Section 5.09. The Collateral Agent Appointed Attorney-in-fact		31
Section 5.10. Netting of Accounts		32
ARTICLE 6 Remedies And Enforcement`
Section 6.01. Remedies And Enforcement		32
Section 6.02. Application of Proceeds		34
Section 6.03. Other Remedies of Secured Parties		35
ARTICLE 7 Depository Bank
Section 7.01. Depository Bank		35
ARTICLE 8 [Reserved]
ARTICLE 9 Miscellaneous
Section 9.01. Indemnity And Expenses		36
Section 9.02. Amendments; Waivers, Etc		37
Section 9.03. Security Interest Absolute And Waivers		37
Section 9.04. Notices; Etc		39
Section 9.05. Continuing Security Interest; Assignments		40
Section 9.06. [Reserved]		41
Section 9.07. Execution In Counterparts		41
Section 9.08. Severability		41
Section 9.09. Integration		41
Section 9.10. No Partnership		41
Section 9.11. No Reliance		41
Section 9.12. Release		41
Section 9.13. No Impairment		41
Section 9.14. Equitable Remedies		41
Section 9.15. Remedies		42
Section 9.16. Limitations		42
Section 9.17. Survival		43
Section 9.18. [Reserved]		43
Section 9.19. Jurisdiction, Etc		43
Section 9.20. GOVERNING LAW		44
Section 9.21. Waiver of Jury Trial		44

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SCHEDULES

Schedule I    Subsidiary Grantors

Schedule II    Initial Pledged Equity

Schedule III    Name, Location, Chief Executive Office, Type of Organization, Jurisdiction of Organization and Organizational Identification Number

Schedule IV    Changes in Name, Location, Etc.

Schedule V    Secured Hedging Agreements

Schedule VI    Material Agreements of El Paso Corporation

EXHIBITS

Exhibit A    Form of Officer’s Certificate for Qualified Investments

iii

THIRD AMENDED AND RESTATED SECURITY AGREEMENT

     THIRD AMENDED AND RESTATED SECURITY AGREEMENT, dated as of November ___, 2007, made by and among:

     EL PASO CORPORATION, a Delaware corporation (the “Company”);

     EL PASO NATURAL GAS COMPANY, a Delaware corporation (“EPNGC”), TENNESSEE GAS PIPELINE COMPANY, a Delaware corporation (“TGPC”) (EPNGC and TGPC, collectively, the “Pipeline Company Borrowers” and, together with the Company, the “Borrowers”);

     Each of the Persons listed on Schedule I hereto as a Subsidiary Grantor (collectively, the “Subsidiary Grantors” and, together with the Company, the “Grantors”) (the Borrowers and the Subsidiary Grantors are sometimes referred to herein, collectively, as the “Credit Parties”; and the Credit Parties, together with the other Restricted Subsidiaries, are sometimes referred to herein, collectively, as the “Credit Related Parties”);

     JPMorgan Chase Bank, N.A. (“JPMCB”), not in its individual capacity but solely as collateral agent for the Secured Parties (solely in such capacity, the “Collateral Agent”); and

     JPMCB, not in its individual capacity but solely in its capacity as the Depository Bank (solely in such capacity, the “Depository Bank”).

PRELIMINARY STATEMENTS

     (1) Certain of the parties hereto are party to a Third Amended and Restated Credit Agreement dated as of the date hereof (the “Credit Agreement”) pursuant to which the Lenders have agreed to make Loans to the Borrowers and participate in Letters of Credit, the Issuing Banks have agreed to issue Letters of Credit for the account of the Borrowers, and the Administrative Agent and the Collateral Agent have agreed to serve in such capacities.

     (2) The Credit Parties, the Depository Bank, the Collateral Agent (on behalf of the Lenders, the Issuing Banks, the Agents and the other Secured Parties) and certain other parties have heretofore entered into that certain Amended and Restated Security Agreement dated as of July 31, 2006 (the “Existing Security Agreement”) with respect to their respective rights in respect of the Collateral and certain other matters related to the Financing Documents.

     NOW, THEREFORE, to secure the Secured Obligations, and in consideration of the premises and to induce each of the Lenders, the Issuing Banks and the Agents to enter into the Credit Agreement and for good and valuable consideration, the receipt and sufficiency of which are hereby

acknowledged, each of the Credit Parties and the Collateral Agent (on behalf of the Lenders, the Issuing Banks, the Agents and the other Secured Parties) agrees that the Existing Security Agreement shall be amended and restated in its entirety as follows:

ARTICLE 1
Definitions And Interpretation

     Section 1.01. Definitions. • Capitalized terms used but not defined herein shall have the respective meanings assigned to such terms in the Credit Agreement.

     (a) As used in this Agreement, the following terms have the meanings specified below:

     “Account Collateral” has the meaning set forth in Section 5.01(d).

     “Agreement” means this Security Agreement.

     “Applicable Law” means, with respect to any Person, any and all laws, statutes, regulations, rules, orders, injunctions, decrees, writs, determinations, awards and judgments issued by any Governmental Authority applicable to such Person.

     “Bankruptcy Code” means the Federal Bankruptcy Reform Act of 1978, as amended from time to time (11 U.S.C. §101, et seq.).

     “Borrowers” has the meaning set forth in the Preamble.

     “Cash Collateral Account” has the meaning set forth in Section 4.01(a)(ii).

     “Clearing Agency” has the meaning set forth in Section 4.10.

     “Collateral” means the Account Collateral, the Security Collateral, the Payment Collateral and all other property or assets with respect to which a Security Document executed by a Grantor creates or grants, or states that it creates or grants, a Transaction Lien.

     “Collateral Account” has the meaning set forth in Section 4.01(a)(i).

     “Collateral Agent” has the meaning set forth in the Preamble.

     “Company” has the meaning set forth in the Preamble.

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     “Company Payment Collateral” has the meaning set forth in Section 5.01(c).

     “Credit Agreement” has the meaning set forth in the Preamble.

     “Credit Parties” has the meaning set forth in the Preamble.

     “Credit Related Parties” has the meaning set forth in the Preamble.

     “Depository Bank” has the meaning set forth in the Preamble.

     “Enforcement Action” means the taking of any or all of the following actions:

     (a) applying funds in the Pledged Accounts (including by charging or exercising any contractual or legal setoff rights) to the payment of the Secured Obligations;

     (b) making any demand for, or receiving any, payment under the Subsidiary Guarantee Agreement;

     (c) taking any Foreclosure Action or exercising any other power of sale or similar other rights or remedies under any of the Security Documents;

     (d) proceeding to protect and enforce the rights of the Secured Parties under this Agreement or any other Security Document by sale of the Collateral pursuant to judicial proceedings or by a proceeding in equity or at law or otherwise, whether for the enforcement of any Transaction Lien or for the enforcement of any other legal, equitable or other remedy available under this Agreement, any other Security Document or Applicable Law;

     (e) exercising any of the rights and remedies of a secured party with respect to the Collateral upon default under the Uniform Commercial Code as in effect in any applicable jurisdiction; and

     (f) exercising any other right or remedy provided in this Agreement or otherwise available to the Collateral Agent, to the extent permitted by Applicable Law.

     “Enforcement Proceeds” means any cash, securities or other consideration received from time to time by the Collateral Agent as a result of the taking of any Enforcement Action in accordance with the Security Documents and Applicable Law, including, without limitation (a) any balances then outstanding in the Pledged Accounts or received therein from time to time

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thereafter, including any Net Cash Proceeds then held in any Pledged Account, (b) the proceeds of any Disposition or other Enforcement Action taken pursuant to Article 6, and (c) proceeds of any Foreclosure Action or judicial or other non-judicial proceeding.

     “EPNGC” has the meaning set forth in the Preamble.

     “Excluded Payment Property” means any property of a Grantor of the type described in (and not excluded from) Section 5.01(b)(i) through (iv), to the extent that the grant of a security interest therein or a Lien thereon would result in (i) a breach of or a default under a provision which is not rendered ineffective by the UCC contained in any agreement in existence on the Effective Date to which the Company or any Subsidiary of the Company is a party (other than (x) an agreement listed on Schedule VI hereto or (y) an agreement that can be amended solely by the Company and/or one or more of its Subsidiaries), or (ii) a mandatory prepayment obligation under any such agreement, or allow any party to any such agreement (other than the Company or any Subsidiary of the Company) to accelerate obligations due thereunder, terminate any material contract right thereunder or exercise any put or call right, right of refusal, purchase option or similar right thereunder.

     “Excluded Subsidiary Grantor Assets” has the meaning set forth in Section 5.01(b).

     “Federal Book Entry Regulations” means (a) the federal regulations contained in Subpart B (“Treasury/Reserve Automated Debt Entry System (TRADES)”) governing book-entry securities consisting of U.S. Treasury bonds, notes and bills and Subpart D of 31 C.F.R. Part 357, 31 C.F.R. § 357.2, § 357.10 through § 357.14 and § 357.41 through § 357.44 and (b) to the extent substantially identical to the federal regulations referred to in clause (a) above (as in effect from time to time), the federal regulations governing other book-entry securities.

     “Financing Documents” means the Loan Documents and the Secured Hedging Agreements.

     “Foreclosure Action” means the sale, transfer or other Disposition by the Collateral Agent of all or any part of the Collateral at any public or private sale at such place and at such time as the Collateral Agent shall determine and in compliance with Applicable Law.

     “Grantors” has the meaning set forth in the Preamble.

     “Indemnified Party” has the meaning set forth in Error! Reference source not found..

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     “Initial Pledged Equity” means, with respect to any Grantor, the Equity Interests set forth opposite such Grantor’s name on and as otherwise described in Schedule II and issued by the Persons named therein.

     “Insolvency Proceeding” means, with respect to any Person, that (a) such Person shall (i) admit in writing its inability to pay its debts generally, or shall fail to pay its debts generally as they become due; or (ii) make a general assignment for the benefit of creditors; or (b) any proceeding shall be instituted or consented to by such Person seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, or other similar official for it or for any substantial part of its property; or (c) any such proceeding shall have been instituted against such Person and either such proceeding shall not be stayed or dismissed for 60 consecutive days or any of the actions referred to above sought in such proceeding (including the entry of an order for relief against it or the appointment of a receiver, trustee, custodian or other similar official for it or any substantial part of its property) shall occur; or (d) such Person shall take any corporate (or other Business Entity) action to authorize any of the actions set forth above in this definition.

     “JPMCB” has the meaning set forth in the Preamble.

     “Officer’s Certificate” means, with respect to any Person, a certificate substantially in the form of Exhibit A hereto, signed by the president, any vice-president, the treasurer or the chief financial officer of such Person.

     “Payment Collateral” has the meaning set forth in Section 5.01(c).

     “Pipeline Company Borrowers” has the meaning set forth in the Preamble.

     “Pledged Accounts” has the meaning set forth in Error! Reference source not found..

     “Pledged Company” means any issuer of the Initial Pledged Equity or any successor entity to any such issuer; provided that, if all of the Equity Interests issued by a Pledged Company and pledged by a Grantor to the Collateral Agent hereunder are released from the Transaction Liens in accordance with the terms of this Agreement and the Credit Agreement, then from and after such release, such issuer shall no longer be a Pledged Company.

     “Pledged Equity” has the meaning set forth in Section 5.01(a)(ii).

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     “Pledged Financial Assets” means all financial assets credited from time to time to the Pledged Accounts.

     “Pledged Security Entitlement” means all security entitlements with respect to the Pledged Financial Assets.

     “Qualified Investments Account” has the meaning set forth in Section 4.01(a)(iii).

     “Remaining Reinvestment Amount” has the meaning set forth in Section 4.03(c).

     “Secured Hedging Agreement” means any Hedging Agreement that (i) was entered into by any Borrower with a Person which was at the time such Hedging Agreement was entered into a Lender or an Affiliate of a Lender and (ii) either (A) is listed on Schedule V hereto or (B) has been designated as a Secured Hedging Agreement by the Company in a certificate signed by a Financial Officer delivered to the Collateral Agent and the Administrative Agent which (I) identifies such Hedging Agreement, including the name and address of the other party thereto (which must be a Lender or an Affiliate of a Lender at the time of such designation), the notional amount thereof and the expiration or termination date thereof, and (II) states that the applicable Borrower’s obligations thereunder shall from and after the date of delivery of such certificate be Secured Obligations for purposes hereof and of the other Security Documents.

     “Secured Obligations” means, with respect to each Grantor, the obligations, including all “Obligations” (as defined in the Credit Agreement) and all “Guaranteed Obligations” (as defined in the Subsidiary Guarantee Agreement) of such Grantor, under (a) the Credit Agreement and/or the Subsidiary Guarantee Agreement, as applicable, (b) this Agreement, (c) any other Loan Document to which such Grantor is a party, (d) any Secured Hedging Agreement to which such Grantor is a party and (e) any agreement relating to the refinancing of the obligations referred to in the foregoing clauses (a) through (d), and in the case of each of clauses (a) through (e) including interest accruing at any post-default rate and Post-Petition Interest.

     “Secured Parties” means, collectively, the Lenders, the Issuing Banks, the Administrative Agent, the Collateral Agent, each counterparty to a Secured Hedging Agreement and each other Person that is a holder of any Secured Obligations.

     “Security Collateral” has the meaning set forth in Error! Reference source not found..

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     “Subsidiary Grantor Payment Collateral” has the meaning set forth in Section 5.01(b).

     “Subsidiary Grantors” has the meaning set forth in the Preamble.

     “TGPC” has the meaning set forth in the Preamble.

     “UCC” means the Uniform Commercial Code as in effect from time to time in the State of New York; provided that, if perfection or the effect of perfection or non-perfection or the priority of any Transaction Liens on any Collateral is governed by the Uniform Commercial Code as in effect in a jurisdiction other than New York, “UCC” means the Uniform Commercial Code as in effect from time to time in such other jurisdiction for purposes of the provisions hereof relating to such perfection, effect of perfection or non-perfection or priority.

     “Unused Cash Collateral” has the meaning set forth in Section 4.02(c).

     (b) Terms defined in Article 8 or 9 of the UCC and/or in the Federal Book Entry Regulations are used in this Agreement as such terms are defined in such Article 8 or 9 and/or the Federal Book Entry Regulations.

     Section 1.02. Principles of Interpretation. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (c) any reference herein to any Applicable Law means such Applicable Law as amended, modified, codified, replaced, or reenacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder and reference to any section or other provision of any Applicable Law means that section or provision of such Applicable Law from time to time in effect and any amendment, modification, codification, replacement, or reenactment of such section or other provision, (d) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and

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Schedules to, this Agreement and (f) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, Equity Interests, accounts and contract rights, and all references to “days” shall mean calendar days. This Agreement is the result of negotiations among the parties thereto and their respective counsel. Accordingly, this Agreement shall be deemed the product of all parties thereto, and no ambiguity in this Agreement shall be construed in favor of or against any Credit Party or any Secured Party.

ARTICLE 2.
[Reserved]

ARTICLE 3
Representations And Warranties

     Section 3.01. Representations And Warranties of The Credit Parties. Each Credit Party, with respect to itself and its Subsidiaries, represents and warrants to the Collateral Agent, for the benefit of the Secured Parties, that:

     (a) With respect to any Credit Party that is a Grantor: (i) such Credit Party’s exact legal name is correctly set forth in Schedule III, (ii) such Credit Party is located (within the meaning of Section 9-307 of the UCC) and has its chief executive office, in the state or jurisdiction set forth in Schedule III, (iii) the information set forth in Schedule III with respect to such Credit Party is true and accurate in all respects and (iv) such Credit Party has not, within the last five years, changed its legal name, location, chief executive office, type of organization, jurisdiction of organization or organizational identification number from those set forth in Schedule III, except as disclosed in Schedule IV.

     (b) Such Credit Party is duly organized or formed, validly existing and, if applicable, in good standing in its jurisdiction of organization or formation. Such Credit Party possesses all applicable Business Entity powers and all other authorizations and licenses necessary to engage in its business and operations as now conducted, the failure to obtain or maintain which would have a Material Adverse Effect.

     (c) The execution, delivery and performance by such Credit Party of the Security Documents to which it is a party are within such Credit Party’s applicable Business Entity powers, have been duly authorized by all necessary applicable Business Entity action, and do not contravene • such Credit Party’s organizational documents or • any material contractual restriction binding on or affecting such Credit Party.

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     (d) No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority is required for the due execution, delivery and performance by such Credit Party of any Security Document to which it is a party, except those necessary to comply • with Applicable Laws in the ordinary course of such Credit Party’s business or • with ongoing obligations of such Credit Party under the Security Documents to which it is a party and Sections 5.01, 5.02 and 5.07 of the Credit Agreement.

     (e) This Agreement constitutes, and the other Security Documents when delivered shall constitute, the legal, valid and binding obligations of each Credit Party that is a party thereto, enforceable against such Credit Party in accordance with their respective terms, except as may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally or by general principles of equity.

     (f) With respect to any Credit Party that is a Grantor, all Collateral pledged by such Credit Party hereunder consisting of certificated securities has been delivered to the Collateral Agent.

     (g) With respect to any Credit Party that is a Grantor, this Agreement is effective to create in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, a Lien on, and security interest in, all right, title and interest of such Grantor in the Collateral pledged by such Credit Party hereunder as security for the Secured Obligations, prior and superior in right to any other Lien (except for Collateral Permitted Liens), except in each case above as may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally. All financing statements have been filed that are necessary to perfect any Transaction Lien that can be perfected by the filing of such financing statements. All actions required by Section 5.03 to provide control to the Collateral Agent with respect to Collateral pledged by such Credit Party hereunder for which control can be established have been taken, including delivery of such Collateral consisting of certificated securities to the Collateral Agent, duly endorsed for transfer or accompanied by duly executed instruments of transfer.

     (h) With respect to any Credit Party that is a Grantor, the Pledged Equity pledged as Collateral by such Credit Party to the Collateral Agent hereunder has (to the extent applicable) been duly authorized and validly issued and is (to the extent applicable) fully paid and non-assessable. With respect to any Equity Interests pledged by such Credit Party to the Collateral Agent hereunder that are uncertificated securities, such Credit Party has caused the issuer thereof to agree in an authenticated record with such Credit Party and the Collateral Agent that such issuer will comply with instructions with respect to such uncertificated securities originated by the Collateral Agent without further consent of such Credit Party and has delivered a copy of such authenticated

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record to the Collateral Agent. If such Credit Party is a Pledged Company, such Credit Party confirms that it has received notice of such security interest.

     (i) With respect to any Credit Party that is a Grantor, the Initial Pledged Equity as set forth on Schedule II (as such schedule may be amended or supplemented from time to time) pledged as Collateral by such Credit Party to the Collateral Agent hereunder constitutes 100% of the issued and outstanding Equity Interests of each issuer thereof.

All representations and warranties made by the Credit Parties herein, and in any other Security Document delivered pursuant hereto, shall survive the execution and delivery by the Credit Parties of the Security Documents. The Credit Parties shall deliver to the Collateral Agent amended and restated schedules (the “Amended Schedules”) to this Agreement in the event that any information contained on the schedules attached hereto becomes inaccurate. Such Amended Schedules shall replace the schedules provided by the Credit Parties on the Effective Date, and shall be deemed the schedules to this Agreement. Each Credit Party will not change its name, identity, corporate structure (including, without limitation, its jurisdiction of formation) or the location of its registered office without (i) giving the Collateral Agent at least 10 Business Days’ prior written notice clearly describing such new name, identity, corporate structure or new location and providing such other information in connection therewith as the Collateral Agent may reasonably request, and (ii) taking all action satisfactory to the Collateral Agent at the expense of such Credit Party as the Collateral Agent may request to maintain the security interest of the Collateral Agent in the Collateral intended to be granted hereby at all times fully perfected with the same priority and in full force and effect.

ARTICLE 4
Pledged Accounts

     Section 4.01. Creation of Pledged Accounts. (a) The Collateral Agent is hereby directed by the Company and each Grantor to cause to be established on or before the date hereof with, and maintained thereafter by, the Depository Bank at its offices in New York City, New York (ABA No. 021000021), in the name of the Collateral Agent as entitlement holder and under the sole control and dominion of the Collateral Agent and subject to the terms of this Agreement, the following segregated securities accounts (collectively, the “Pledged Accounts”):

     (i) a master collateral account, Account No. 10205184 (the “Collateral Account”), into which Mandatory Asset Reduction Amounts will be deposited and to which Unused Cash Collateral and certain amounts described in Section 4.03(f) will be transferred;

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     (ii) a cash collateral account, Account No. 10205185 (the “Cash Collateral Account”), into which certain amounts will be deposited in respect of Letters of Credit; and

     (iii) an account, Account No. 10205186 (the “Qualified Investments Account”), from which the Company, on behalf of the Restricted Subsidiaries, may direct the Collateral Agent to direct the Depository Bank to pay funds to the Company to make Qualified Investments as permitted under the Loan Documents.

     (b) Commencing with the date hereof and continuing until the termination of the Transaction Liens in accordance with Section 5.07(b), each Pledged Account shall be established and maintained by the Depository Bank as a securities account or as a deposit account at its offices in New York City, New York, in the name of and under the sole dominion and control of the Collateral Agent; provided that the Cash Collateral Account may be terminated at such time as: (i) all Letters of Credit shall have expired or been paid, settled, satisfied, released, or otherwise terminated, (ii) all LC Disbursements shall have been reimbursed, (iii) all LC Commitments and all commitments of the Lenders to participate in Letters of Credit shall have been terminated and (iv) all amounts on deposit in the Cash Collateral Account shall have been transferred to the Collateral Account as Unused Cash Collateral, to be applied in accordance with Section 2.09 of the Credit Agreement and Section 6.02. The Collateral Agent shall cause each of the Pledged Accounts to be, and each Pledged Account shall be, separate from all other accounts held by or under the control or dominion of the Collateral Agent. The Company irrevocably confirms the authority of (and directs and authorizes) the Collateral Agent to, or to direct the Depository Bank to, and the Collateral Agent agrees to, or to direct the Depository Bank to, deposit into, or credit to, and transfer funds from the Pledged Accounts to the Collateral Agent, the Administrative Agent, the other Secured Parties and the Company (or its designee), in each case in accordance with this Agreement and the other Loan Documents.

     (c) The Credit Parties acknowledge that the Collateral Agent may cause the Depository Bank to establish subaccounts of the Qualified Investments Account, and that such subaccounts may, at the Collateral Agent’s election, be either (i) actual, separate accounts or (ii) notional accounts reflected in the Collateral Agent’s records as accounting entries with respect to the actual Qualified Investments Account maintained by the Depository Bank. Each such subaccount shall constitute a Pledged Account hereunder, and each actual subaccount shall be established and maintained by the Depository Bank as a securities account at its offices in New York City, New York, in the name of the Collateral Agent.

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     (d) Unless otherwise specified in this Agreement, all references to the Qualified Investments Account shall include references to all subaccounts thereof, and such subaccounts shall be subject to the same restrictions and limitations as the Qualified Investments Account.

     (e) The Company shall not have any rights against or to moneys or funds on deposit in, or credited to, the Pledged Accounts, as third-party beneficiary or otherwise, except the right of the Company (a) to receive moneys or funds on deposit in, or credited to, the Pledged Accounts, as required or permitted by this Agreement or by the provisions of any other Loan Document (to the extent such provisions are not inconsistent with this Agreement), and (b) to direct the Collateral Agent as to the investment of moneys held in the Pledged Accounts as permitted by Section 4.05. In no event shall any amounts or Cash Equivalents deposited into, or credited to, any Pledged Account, be registered in the name of the Company, payable to the order of the Company, or specially endorsed to the Company, except to the extent that the foregoing have been specially endorsed to the Depository Bank or endorsed in blank.

     Section 4.02. Cash Collateral Account. (a) [Reserved].

     (b) Amounts deposited in the Cash Collateral Account shall be held therein, subject to the following provisions:

     (i) If any Letter of Credit is drawn, in whole or in part, and not reimbursed by the applicable Borrower within the period specified in Section 2.04(e) of the Credit Agreement, the Issuing Bank with respect to such Letter of Credit may request, whereupon the Collateral Agent shall within three Business Days after receipt of such request, direct the Depository Bank to promptly distribute to such Issuing Bank an amount equal to the lesser of (x) the amount of the LC Disbursement in respect of such Letter of Credit that has not been reimbursed by or on behalf of such Borrower and (y) the total amount available in the Cash Collateral Account at such time.

     (ii) Upon the request of the Company at a time when no Event of Default is continuing, the Collateral Agent shall direct the Depository Bank to distribute any funds in the Cash Collateral Account (other than, prior to the Final Payment Date, funds deposited in the Cash Collateral Account pursuant to Section 2.09(c) of the Credit Agreement) to the Company (or to the Company’s designee) to be used by the Company for general corporate purposes, or to be used by such designee for any lawful purpose.

     (iii) If an Event of Default shall have occurred and be continuing, the Collateral Agent may, at the direction of the Majority

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Lenders, apply funds in the Cash Collateral Account in accordance with Section 6.02.

     (c) If any Letter of Credit, or any portion thereof, has terminated, expired or otherwise been released or satisfied undrawn and, as a result, the total amount of funds in the Cash Collateral Account, as of such date, exceeds 105% of the aggregate amount of LC Exposure, as of such date, then (i) the Collateral Agent shall, upon any request therefor from the Company, direct the Depository Bank to transfer such excess of funds on deposit in the Cash Collateral Account (any such amount, “Unused Cash Collateral”) into the Collateral Account; and (ii) such Unused Cash Collateral shall be applied in accordance with Section 2.09 of the Credit Agreement and Section 6.02.

     Section 4.03. Qualified Investments Account. (a) If a FERC-Regulated Restricted Subsidiary receives Net Cash Proceeds from the Disposition of a Covered Asset as described in clause (d) of the definition of “Mandatory Asset Reduction Event”, then the Company shall deposit, or cause to be deposited, into the Collateral Account, within five days after such receipt, the amount, if any, by which the portion of such Net Cash Proceeds that is not deemed to have been invested in Qualified Investments described in clause (a)(ii) or (a)(iii) of the definition thereof exceeds $100,000,000.

     (b) If an Unregulated Restricted Subsidiary receives Net Cash Proceeds from the Disposition of a Covered Asset as described in clause (d) of the definition of “Mandatory Asset Reduction Event”, then the Company shall deposit, or cause to be deposited, into the Collateral Account, within five days after such receipt, the portion of such Net Cash Proceeds that is not deemed to have been invested in Qualified Investments described in clause (b)(ii) or (b)(iii) of the definition thereof.

     (c) So long as no Event of Default has occurred and is continuing within one Business Day after receipt, the Collateral Agent shall direct the Depository Bank to transfer the funds deposited into the Collateral Account pursuant to Error! Reference source not found. or 4.03(b) (in either case, for each Disposition, the “Remaining Reinvestment Amount”) to the Qualified Investments Account.

     (d) If funds are to be transferred to the Qualified Investments Account pursuant to Section 4.03(c) and after giving effect to such transfer the Qualified Investments Account would contain funds in respect of the Covered Assets of more than one Restricted Subsidiary, or in respect of more than one Covered Asset of a single Restricted Subsidiary, the Collateral Agent shall cause the Depository Bank to establish and maintain individual securities subaccounts, or the Collateral Agent shall establish in its accounting records notional subaccounts (each, a “Qualified Investments Subaccount”), in each case within the Qualified

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Investments Account, for each such Restricted Subsidiary or each such Covered Asset.

     (e) For the period from the initial transfer of the Remaining Reinvestment Amount to the Qualified Investments Account, until the date, if ever, on which the failure of the applicable Restricted Subsidiary to invest such Remaining Reinvestment Amount in Qualified Investments, requires application of all or a portion thereof in connection with a reduction of the Commitments pursuant to Section 2.07(d) of the Credit Agreement, the Collateral Agent shall, at the written direction of the Company from time to time, direct the Depository Bank to pay such funds on deposit in the Qualified Investments Account (or any applicable Qualified Investments Subaccount) to the Restricted Subsidiary identified by the Company in the Officer’s Certificate described in the following sentence. The written direction described in the preceding sentence shall be accompanied by an Officer’s Certificate (i) setting forth the name of the Restricted Subsidiary whose Disposition of Covered Assets resulted in the deposit of the Remaining Reinvestment Amount that is being requested to be paid pursuant to such written direction, (ii) if such Restricted Subsidiary is a FERC-Regulated Restricted Subsidiary, stating that all funds retained by such FERC-Regulated Restricted Subsidiary pursuant to Error! Reference source not found. from the Net Cash Proceeds of all of its Dispositions of Covered Assets prior to the date of such certificate have been, or (by making the currently proposed Qualified Investment(s)) will be, used to make Qualified Investments, and (iii) describing the Qualified Investment(s) to be made (or deemed made) by such Restricted Subsidiary with such funds, pursuant to the definition of “Qualified Investment”. Notwithstanding the foregoing, the Company shall have the right to direct that funds on deposit in the Qualified Investments Account or any applicable Qualified Investments Subaccount be paid to a FERC-Regulated Restricted Subsidiary in respect of new Qualified Investments made or deemed made by such FERC-Regulated Restricted Subsidiary only if, on the proposed date of such payment from the Qualified Investments Account or applicable Qualified Investments Subaccount, the aggregate amount of Qualified Investments made by such FERC-Regulated Restricted Subsidiary after April 16, 2003 equals or exceeds the sum of the product of (x) $100,000,000 times (y) the number of such Dispositions of Covered Assets by such FERC-Regulated Restricted Subsidiary that have resulted in a deposit in the Collateral Account, plus the aggregate Net Cash Proceeds of Dispositions of Covered Assets by such FERC-Regulated Restricted Subsidiary after April 16, 2003 that have not resulted in deposits into the Collateral Account.

     (f) If a Mandatory Asset Reduction Event described in clause (d) of the definition thereof shall occur with the result that the Company is required to cause Loans to be prepaid or Letters of Credit to be Cash Collateralized pursuant to Section 2.09(c) of the Credit Agreement (a “2.09 Application”), the Collateral Agent shall direct the Depository Bank to transfer (i) if such Mandatory Asset

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Reduction Event does not occur during the pendency of an Event of Default, (A) an amount equal to the lesser of (x) the required 2.09 Application and (y) 80% of the funds remaining in the Qualified Investments Account (or the applicable Qualified Investments Subaccount) in respect of the applicable Disposition of Covered Assets to the Collateral Account to be applied in accordance with Section 2.09(c) of the Credit Agreement, and (B) any remaining funds in the Qualified Investments Account (or the applicable Qualified Investments Subaccount) to the Company, or as the Company directs, to be used for general corporate purposes, or (ii) if such Mandatory Asset Reduction Event occurs concurrently with or during the pendency of an Event of Default, 100% of the funds remaining in the Qualified Investments Account (and in all applicable Qualified Investments Subaccounts) in respect of the applicable Disposition of Covered Assets to the Collateral Account to be applied (x) to the extent of the required 2.09 Application, in accordance with Section 2.09(c) of the Credit Agreement and (y) the balance, in accordance with Section 6.02 hereof.

     (g) If following the application of a Mandatory Asset Reduction Amount in accordance with Section 2.07(d) of the Credit Agreement and any prepayment of Loans or Cash Collateralization of outstanding Letters of Credit in connection therewith pursuant to Section 2.09(c) of the Credit Agreement, there are remaining funds in the Qualified Investments Account attributable to such Mandatory Asset Reduction Amount, the Collateral Agent shall direct the Depository Bank to transfer such remaining funds (i) if no Event of Default exists at the time, to the Company, or as the Company directs, to be used for general corporate purposes, or (ii) if an Event of Default exists at the time, to the Collateral Account to be applied in accordance with Section 6.02 hereof.

     (h) The Collateral Agent shall effectuate any transfer required pursuant to Section 4.03(f) or 4.03(g) by giving appropriate entitlement orders to the Depository Bank.

     Section 4.04. Payments In Trust. If, notwithstanding the instructions given or required to be given in accordance with this Article 4, any payments required by any Security Document to be remitted to the Collateral Agent are instead remitted to the Company or its Affiliates (it being the intent and understanding of the parties hereto that such payments are not to be made directly to the Company but directly to the Collateral Agent for deposit into, or credit to, the relevant Pledged Account for application in accordance with this Article 4), then, to the fullest extent permitted by Applicable Law, the Company or such other Person shall receive such payments into a constructive trust for the benefit of the Secured Parties and subject to the Secured Parties’ security interest, and shall (or shall use its best efforts to cause the Person receiving such payments to) promptly remit them to the Collateral Agent for deposit into, or credit to, the applicable Pledged Account designated by this Article 4.

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     Section 4.05. Investment of Funds In Pledged Accounts. (a) The Collateral Agent will promptly direct the Depository Bank to (i) invest amounts on deposit in, or credited to, the Pledged Accounts, (ii) reinvest any interest paid on the amounts referred to in clause Error! Reference source not found. above, and (iii) reinvest other proceeds of any such amounts that may mature or be sold, in each case, in Cash Equivalents which are deposited into, or credited to, such Pledged Account, in each case as the Company may select and instruct the Collateral Agent, unless, to the knowledge of the Collateral Agent, any Event of Default has occurred and is continuing, in which event the Collateral Agent shall direct the Depository Bank to invest such amounts in Cash Equivalents as the Collateral Agent may direct. If no Event of Default then exists, interest and proceeds resulting from an investment of funds in any Pledged Account in Cash Equivalents shall be, promptly upon request of the Company, transferred to the Company to be used for general corporate purposes. In addition, subject to any instructions from the Company (if not during the pendency of an Event of Default), the Collateral Agent shall have the right at any time to direct the Depository Bank to exchange such Cash Equivalents for similar Cash Equivalents of smaller or larger denominations.

     (b) Unless it has received instructions from the Company in accordance with this Section 4.05 as to the investment of such funds, the Collateral Agent may direct the Depository Bank to invest or reinvest any funds in any Pledged Account. All investments and reinvestments of funds in the Pledged Accounts shall be made in the name of the Depository Bank.

     (c) Whenever directed to make a transfer of funds from any of the Pledged Accounts in accordance with this Article 4, the Collateral Agent is hereby directed and authorized by the Company, the Borrowers and the Grantors (for themselves and their respective Subsidiaries) to direct the Depository Bank to liquidate (or cause to be liquidated) Cash Equivalents (in order of their respective maturities with the Cash Equivalents with the shortest maturities being liquidated first), to the extent that, after application of all other funds available for such purpose pursuant to this Article 4, the liquidation of any Cash Equivalent is necessary to make such transfer.

     (d) Neither the Collateral Agent nor the Depository Bank shall (in the absence of gross negligence or willful misconduct, as finally determined by a court of competent jurisdiction) have any liability with respect to any interest, cost or penalty on the liquidation of any Cash Equivalent pursuant to this Agreement, nor shall the Collateral Agent (in the absence of gross negligence or willful misconduct, as finally determined by a court of competent jurisdiction) have any liability with respect to Cash Equivalents (including purchases or conversions of foreign exchange) or moneys deposited into, or credited to, the Pledged Accounts (or any losses resulting therefrom) invested in accordance with this Agreement. Without limiting the generality of the foregoing, in the absence of

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gross negligence or willful misconduct, as finally determined by a court of competent jurisdiction, the Collateral Agent shall have no responsibility for any investment losses resulting from the investment, reinvestment or liquidation of all or a portion of funds in the Pledged Accounts, if the Collateral Agent has made such investment, reinvestment or liquidation, as applicable, in accordance with this Agreement.

     (e) All references in this Agreement to Pledged Accounts and to cash, moneys or funds therein or balances thereof, shall include the Cash Equivalents in which such cash, moneys, funds or balances are then invested and the proceeds thereof, and all financial assets and security entitlements carried in or credited to such Pledged Accounts.

     (f) (i) Neither the Collateral Agent nor any of its Affiliates assume any duty or liability for monitoring the rating or performance of any Cash Equivalent. Subject to Section 4.06, in the event an investment selection is not made by the Company in accordance with this Section 4.05, the funds in the Pledged Accounts shall not be required to be invested but may be invested at the discretion of the Collateral Agent, and the Collateral Agent shall not incur any liability for interest or income thereon. The Collateral Agent shall have no obligation to cause the investment or reinvestment of the funds in the Pledged Accounts on the day of deposit if all or a portion of such funds is deposited with the Collateral Agent after 11:00 a.m. (New York City time) on such day of deposit. Instructions to invest or reinvest that are received after 11:00 a.m. (New York City time) will be treated as if received on the following Business Day in New York. Requests or instructions received after 11:00 a.m. (New York City time) by the Collateral Agent to liquidate all or a portion of funds in any Pledged Account will be treated as if received on the following Business Day in New York.

     (ii) The Credit Parties acknowledge that non-deposit investment products (A) are not obligations of, nor guaranteed, by JPMCB or any of its Affiliates; (B) are not FDIC insured; and (C) are subject to investment risks, including the possible loss of principal amount invested.

     Section 4.06. Transfers From Accounts During The Continuance of An Event of Default. During the existence and continuance of an Event of Default, the Collateral Agent shall not be obligated to accept any instructions from the Company with respect to any transfer or withdrawal of funds on deposit in, or credited to, any Pledged Account and, in such circumstances, the Collateral Agent may direct the investment, transfer or withdrawal of funds in the Pledged Accounts without further consent by the Company.

     Section 4.07. Reports, Certification And Instructions. (a) The Collateral Agent shall maintain all such accounts, books and records as may be necessary to properly record all transactions carried out by it under this Agreement. The

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Collateral Agent shall permit the Company and its Affiliates and their authorized representatives to examine such accounts, books and records; provided that any such examination shall occur upon reasonable notice and during normal business hours.

     (b) The Collateral Agent shall deliver to the Company copies of the account statements for all Pledged Accounts (including all subaccounts) for each month. Such account statements shall indicate, with respect to each such account, deposits, credits and transfers, investments made and closing balances. The Collateral Agent shall provide any additional information or reports relating to the Pledged Accounts and the transactions therein reasonably requested from time to time by the Company or any Secured Party.

     (c) Each time the Company directs the Collateral Agent to make or cause to be made a transfer or withdrawal from a Pledged Account, it shall be deemed to represent and warrant for the benefit of the Collateral Agent and the other Secured Parties that such transfer or withdrawal is being made in an amount, and shall be applied solely for the purposes permitted by, and is and will otherwise be in accordance with, this Agreement and the Credit Agreement. Except to the extent any officer or officers of the Collateral Agent responsible for the administration of this Agreement has actual knowledge to the contrary, the Collateral Agent may conclusively rely on, and shall incur no liability in so relying on, any such direction.

     (d) Notwithstanding any provision to the contrary contained in this Agreement, all notices, certifications, approvals, directions, instructions or other communication given to the Collateral Agent with respect to any payments, transfers, credits, deposits, withdrawals or investments with respect to, or otherwise relating to, any Pledged Account, in each case, by the Company or by any other Secured Party shall be given in writing, and the Collateral Agent shall not be required to take any action with respect to any payments, transfers, credits, deposits, withdrawals or investments unless it has received such written instructions specifying the date, amount and Pledged Account with respect to which such payment, transfer, credit, deposit, withdrawal or investment is to be made.

     Section 4.08. Depository Bank Undertakings. The Depository Bank hereby represents and warrants to, and agrees with the Company and the Collateral Agent as follows:

     (a) The Depository Bank (i) is a securities intermediary on the date hereof and (ii) so long as this Agreement remains in effect and such Depository Bank remains the Depository Bank hereunder, shall remain a securities intermediary, and shall act as such with respect to the Company, the Collateral Agent, the Pledged Accounts and all of the Account Collateral and any other

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property (including all financial assets and security entitlements maintained or carried in the Pledged Accounts) from time to time transferred to, credited to, deposited in, or maintained in the Pledged Accounts.

     (b) Each of the Pledged Accounts is, and shall remain, and the Depository Bank shall maintain each of the Pledged Accounts as, a securities account, with the Collateral Agent (and no other Person) as the entitlement holder and under the sole dominion and control of the Collateral Agent for the ratable benefit of the Collateral Agent and the other Secured Parties.

     (c) The Depository Bank (i) has identified (and will continue to identify) the Collateral Agent for the ratable benefit of the Secured Parties in its records as, and will treat the Collateral Agent as (A) the sole Person having a security entitlement against the Depository Bank with respect to the Pledged Accounts and the Account Collateral from time to time carried in the Pledged Accounts, (B) the sole entitlement holder against the Depository Bank with respect to each of the Pledged Accounts, (C) the sole Person having dominion and control over each of the Pledged Accounts and any and all assets, property and items from time to time carried in such Pledged Accounts (including cash) and (D) the sole Person entitled to exercise the rights with respect to the Pledged Accounts; and (ii) has credited and will continue to credit such assets, property and items to the Pledged Accounts in accordance with written instructions given pursuant to, and the other terms and conditions of, this Agreement.

     (d) All of the property, including Account Collateral and cash, from time to time carried in or credited to the Pledged Accounts, shall constitute financial assets, and the Depository Bank shall treat all such property as financial assets under Article 8 of the UCC.

     (e) Notwithstanding any other provision in this Agreement to the contrary, the Depository Bank (i) shall comply with any and all entitlement orders and other directions originated by, and only by, the Collateral Agent in respect of the Pledged Accounts and the Account Collateral from time to time carried therein without any further consent or action by the Company or any other Person and (ii) shall not comply with the entitlement orders of any other Person.

     (f) The “securities intermediary’s jurisdiction” (within the meaning of Section 8-110(e) of the UCC) of the Depository Bank is and will continue to be the State of New York.

     (g) To be binding on the Depository Bank, all instructions by the Collateral Agent pursuant to this Agreement with respect to the Account Collateral carried in the Pledged Accounts must be given to the Depository Bank, and only pursuant to and subject to the terms and conditions of this Agreement.

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     (h) Anything herein to the contrary notwithstanding, the Depository Bank will not be required to follow any instruction that would violate any Applicable Law, decree, regulation or order of any Governmental Authority (including any court or tribunal) or the terms of this Agreement.

     (i) The Depository Bank has not entered into and will not enter into any agreement with any other Person relating to the Pledged Accounts or any Pledged Financial Assets credited thereto pursuant to which it has agreed or will agree to comply with entitlement orders of such Person. The Depository Bank has not entered into any other agreement with the Company or any other Person purporting to limit or condition the duties of the Depository Bank to comply with entitlement orders originated by the Collateral Agent as set forth in Section 4.08(e).

     (j) The Depository Bank hereby permanently waives and releases any Lien, right of setoff or other right it may have against the Pledged Accounts and any Pledged Financial Assets or Pledged Security Entitlements carried in or credited to the Pledged Accounts and any credit balance or cash in the Pledged Accounts, and agrees that it will not assert any such Lien or other right in, to or against the Pledged Accounts or any Pledged Financial Asset or Pledged Security Entitlement carried therein or credited thereto, or any credit balance or cash in the Pledged Accounts.

     (k) The Depository Bank will send copies of all statements and confirmations for and in respect of the Pledged Accounts simultaneously to the Company and the Collateral Agent.

     (l) All securities or other property underlying any financial assets consisting of Account Collateral deposited in or credited to a Pledged Account shall be registered in the name of the Depository Bank, endorsed to the Depository Bank or in blank or credited to another securities account or securities accounts maintained in the name of the Depository Bank, and in no case will any financial asset consisting of Account Collateral deposited in or credited to a Pledged Account be registered in the name of the Company, payable to the order of the Company or specially endorsed to the Company, except to the extent the foregoing have been specially endorsed by the Company to the Depository Bank or in blank.

     (m) If any Person (other than the Collateral Agent) asserts to the Depository Bank any Lien, encumbrance or adverse claim (including any writ, garnishment, judgment, warrant of attachment, execution or similar process) against any Account Collateral, the Depository Bank will as promptly as practicable thereafter notify the Company and the Collateral Agent thereof.

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     Section 4.09. Force Majeure. Neither the Collateral Agent nor the Depository Bank shall incur any liability for not performing any act or fulfilling any obligation hereunder by reason of any occurrence beyond its control (including any provision of any present or future law or regulation or any act of any Governmental Authority, any act of God, war or terrorism, or the unavailability of the Federal Reserve Bank wire services or any electronic communication facility).

     Section 4.10. Clearing Agency. The Account Collateral in the Pledged Accounts may be held by the Collateral Agent directly or through any clearing agency or depository including the Federal Reserve/Treasury Book-Entry System for United States and federal agency securities, and the Depository Trust Company (collectively, the “Clearing Agency”). The Collateral Agent shall not have any responsibility or liability for the actions or omissions to act on the part of any Clearing Agency. The Collateral Agent is authorized, for any Collateral at any time held hereunder, to register the Collateral in the name of one or more of its nominee(s) or the nominee(s) of any Clearing Agency in which the Collateral Agent has a participant account, and such nominee(s) may sign the name of any Credit Party and guarantee such signature in order to transfer securities or certify ownership thereof to tax or other Governmental Authorities.

     Section 4.11. Return of Funds to the Company. Upon any request by the Company following the release of the Transaction Liens in accordance with Section 5.07(b), the Collateral Agent shall direct the Depository Bank to, and the Depository Bank shall promptly pay, transfer and deliver to or to the order of the Company all moneys, investments, and other property held in, or credited to, the Pledged Accounts, in each case, in accordance with the instructions of the Company and at the Company’s expense.

ARTICLE 5
Security Interests

     Section 5.01. Grant of Security Interests. (a) Each Subsidiary Grantor hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in such Subsidiary Grantor’s right, title and interest in and to the following, in each case, as to each type of property described below, whether now owned or hereafter acquired by such Subsidiary Grantor, wherever located, and whether now or hereafter existing or arising (collectively, the “Security Collateral”):

     (i) the Initial Pledged Equity and the certificates, if any, representing the Initial Pledged Equity, and all dividends, distributions, return of capital, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of, in exchange for,

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or in conversion of, any or all of the Initial Pledged Equity and all subscription warrants, rights or options issued thereon or with respect thereto;

     (ii) all additional shares of stock and other Equity Interests of or in any Pledged Company from time to time acquired by such Subsidiary Grantor in any manner (such shares and other Equity Interests, together with the Initial Pledged Equity, being the “Pledged Equity”), and the certificates, if any, representing such additional shares or other Equity Interests, and all dividends, distributions, return of capital, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of such Pledged Equity and all subscription warrants, rights or options issued thereon or with respect thereto;

     (iii) all books and records of such Grantor pertaining to the Security Collateral;

     (iv) all supporting obligations, general intangibles and contract rights (including rights under limited liability company agreements, limited partnership agreements and any other organizational or constituent documents pursuant to which Pledged Equity has been issued or which sets out rights with respect thereto), warranties, indemnities or guaranties, in each case to the extent relating to, or payable in respect of, interests in the Security Collateral, and any tort claims (including all commercial tort claims) arising in connection with interests in the Security Collateral; and

     (v) all proceeds of the foregoing Security Collateral.

     (b) Each Subsidiary Grantor hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in such Subsidiary Grantor’s right, title and interest in and to the following (but excluding Excluded Subsidiary Grantor Assets), in each case, as to each type of property described below, whether now owned or hereafter acquired by such Subsidiary Grantor, wherever located, and whether now or hereafter existing or arising (all such property in which a security interest is granted under this Section 5.01(b) being, collectively, the “Subsidiary Grantor Payment Collateral”):

     (i) all accounts and payment intangibles owing to such Subsidiary Grantor by (A) any Pipeline Company Borrower or (B) any other Grantor;

     (ii) all instruments owing to such Subsidiary Grantor by (A) any Pipeline Company Borrower or (B) any other Grantor;

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     (iii) all chattel paper in respect of obligations payable to such Subsidiary Grantor with respect to which the account debtor is (A) any Pipeline Company Borrower or (B) any other Grantor; and

     (iv) all proceeds of the foregoing Subsidiary Grantor Payment Collateral.

Notwithstanding the foregoing, the Subsidiary Grantor Payment Collateral shall not include, and the Liens created under this Section 5.01(b) shall not encumber, (A) any (1) accounts owing to the Exempted Guarantor by the Company, (2) payment intangibles owing to the Exempted Guarantor by the Company, (3) instruments owing to the Exempted Guarantor by the Company or chattel paper in respect of obligations payable to the Exempted Guarantor with respect to which the account debtor is the Company, or (B) any Excluded Payment Property of any Grantor (all of the property described in clause (A) and (B) of this sentence being, collectively, the “Excluded Subsidiary Grantor Assets”).

     (c) The Company hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in the Company’s right, title and interest in and to the following (but excluding Excluded Payment Property of the Company), in each case, as to each type of property described below, whether now owned or hereafter acquired by the Company, wherever located, and whether now or hereafter existing or arising (all such property in which a security interest is granted under this Section 5.01(c) being, collectively, the “Company Payment Collateral”, and together with the Subsidiary Grantor Payment Collateral, the “Payment Collateral”):

     (i) all accounts or payment intangibles owing to the Company by (A) any Pipeline Company Borrower or (B) any Grantor (other than the Exempted Guarantor);

     (ii) all instruments owing to the Company by (A) any Pipeline Company Borrower or (B) any Grantor (other than the Exempted Guarantor);

     (iii) all chattel paper in respect of obligations payable to the Company with respect to which the account debtor is (A) any Pipeline Company Borrower or (B) any Grantor (other than the Exempted Guarantor); and

     (iv) all proceeds of the foregoing Company Payment Collateral.

     Notwithstanding the foregoing, the Company Payment Collateral shall not include, and the Liens created under this Section 5.01(c) shall not encumber, any Excluded Payment Property of the Company.

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     (d) Each Grantor hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in such Grantor’s right, title and interest in and to the following, in each case, as to each type of property described below, whether now owned or hereafter acquired by such Grantor, wherever located, and whether now owned or hereafter existing or arising (collectively, the “Account Collateral”):

     (i) the Pledged Accounts, all Pledged Financial Assets, all Pledged Security Entitlements and all property, funds, interest, dividends, distributions, cash, instruments and other property from time to time carried in or credited to any Pledged Account or received, receivable or otherwise distributed in respect of or in exchange for any or all of the foregoing, and all certificates and instruments, if any, from time to time representing or evidencing the Pledged Accounts;

     (ii) all promissory notes, certificates of deposit, deposit accounts, checks and other instruments delivered (or required to be delivered) to or otherwise possessed by the Collateral Agent for or on behalf of such Grantor in connection with the Account Collateral, including those received in substitution for or in addition to any or all of the Account Collateral;

     (iii) all interest, dividends, distributions, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of the Account Collateral;

     (iv) all books and records of such Grantor pertaining to any of the Account Collateral;

     (v) all supporting obligations, general intangibles, contract rights, warranties, indemnities and guaranties, in each case to the extent relating to, or payable in respect of, the Account Collateral; and

     (vi) all proceeds of the foregoing Account Collateral.

     Section 5.02. Security For Obligations. (a) In the case of each Grantor, the security interests granted by such Grantor pursuant to Sections 5.01(a) through (d) secure the payment and performance of all such Grantor’s Secured Obligations, whether now existing or hereafter arising.

     (b) Without limiting the generality of subsection (a) of this Section 5.02, as to each Grantor, the security interests granted by such Grantor pursuant to Sections 5.01(a) through (d) secure the payment of all amounts that constitute part of such Grantor’s Secured Obligations and would be owed by such Grantor but

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for the fact they are unenforceable or not allowable due to the existence of an Insolvency Proceeding involving such Grantor.

     Section 5.03. Delivery And Control of Collateral. (a) All certificates or instruments representing or evidencing Security Collateral shall be delivered to and held by or on behalf of the Collateral Agent pursuant hereto and shall be in suitable form for transfer by delivery, or shall be accompanied by duly indorsed instruments of transfer or assignment in blank, all in form and substance reasonably satisfactory to the Collateral Agent, but excluding checks, certificates of title and other similar instruments. If an Event of Default has occurred and is continuing, the Collateral Agent shall have the right, in its discretion and without notice to any Credit Party, to transfer to or to register in the name of the Collateral Agent or any of its nominees any or all of the Security Collateral, subject only to the revocable rights specified in Section 5.08. In addition, the Collateral Agent shall have the right at any time to exchange certificates or instruments representing or evidencing Security Collateral for certificates or instruments of smaller or larger denominations.

     (b) With respect to any Security Collateral in which any Grantor has any right, title or interest and that constitutes an uncertificated security, such Grantor will cause the issuer thereof to agree in an authenticated record with such Grantor and the Collateral Agent that such issuer will comply with instructions with respect to such Security Collateral originated by the Collateral Agent without further consent of such Grantor, such authenticated record to be in form and substance satisfactory to, and to be delivered to, the Collateral Agent. With respect to any Security Collateral in which any Grantor has any right, title or interest and that is not an uncertificated security, upon the request of the Collateral Agent, such Grantor will notify each such issuer of Pledged Equity that such Pledged Equity is subject to the security interest granted hereunder.

     (c) Each Grantor shall deliver to the Collateral Agent all Payment Collateral pledged by it that constitutes instruments or tangible chattel paper, accompanied by duly indorsed instruments of transfer or assignment in blank, which instruments of transfer or assignment shall be in form reasonably satisfactory to the Collateral Agent.

     Section 5.04. Further Assurances; Etc. (a) Each Grantor agrees that from time to time, at the expense of such Grantor, such Grantor will promptly do, execute, acknowledge, deliver, record, re-record, file, re-file, register and re-register any and all such further acts, pledge agreements, collateral assignments, account control agreements, financing statements and continuations thereof, termination statements, notices of assignment, transfers, certificates, assurances and other instruments as the Collateral Agent or the Depository Bank may reasonably require from time to time in order to (i) carry out more effectively the purposes of the Security Documents with respect to the Collateral, (ii) to the

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fullest extent permitted by Applicable Law, subject its right, title and interest in and to the Collateral to the Transaction Liens, (iii) perfect and maintain the validity and effectiveness of the Security Documents and the validity, effectiveness and priority of the Transaction Liens and (iv) assure, grant, collaterally assign, transfer, preserve, protect and confirm more effectively unto the Secured Parties the rights granted or now or hereafter stated to be granted to the Secured Parties in respect of the Collateral under any Security Document or under any other instrument executed in connection with any Security Document to which it is a party. Without limiting the generality of the foregoing, each Grantor will promptly with respect to Collateral of such Grantor: (A) execute or authenticate and file such financing or continuation statements, or amendments thereto, and such other instruments or notices, as may be necessary or desirable, or as the Collateral Agent may reasonably request, in order to perfect and preserve the Transaction Liens; (B) deliver and pledge to the Collateral Agent for benefit of the Secured Parties certificates representing Security Collateral that constitutes certificated securities, accompanied by undated stock powers indorsed in blank, and deliver and pledge to the Collateral Agent for the benefit of the Secured Parties all tangible chattel paper and all instruments constituting Collateral, together with duly indorsed instruments of transfer or assignment in blank; (C) take all action necessary to ensure that the Collateral Agent has control of Collateral, if any, consisting of deposit accounts, as provided in Section 9-104 of the UCC, control of the Account Collateral as provided in Sections 8-106 and 9-106 of the UCC, and control of Payment Collateral consisting of electronic chattel paper as provided in Section 9-105 of the UCC; and (D) deliver to the Collateral Agent evidence that all other action that the Collateral Agent may reasonably request as necessary or desirable to perfect and preserve Transaction Liens has been taken.

     (b) Each Grantor hereby authorizes the Collateral Agent to file one or more financing or continuation statements, and amendments thereto, including one or more financing statements indicating that such financing statements cover all right, title and interest of such Grantor in and to the Collateral, in each case without the signature of such Grantor. The Collateral Agent shall provide a copy of each such financing statement to each Grantor. A photocopy or other reproduction of this Agreement or any financing statement covering the Collateral or any part thereof shall be sufficient as a financing statement where permitted by law. Each Grantor ratifies its authorization for the Collateral Agent to have filed such financing statements, continuation statements or amendments filed prior to the date hereof.

     Section 5.05. Grantors Remain Liable. Anything herein to the contrary notwithstanding, (a) each Grantor shall remain liable under any contracts and agreements included in such Grantor’s Collateral (including, with respect to Security Collateral, any obligations under limited liability company agreements, limited partnership agreements and any other organizational or constituent

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documents pursuant to which Pledged Equity has been issued or which sets out obligations with respect to Security Collateral) to the extent set forth therein to perform all of its duties and obligations thereunder to the same extent as if this Agreement had not been executed, (b) the exercise by the Collateral Agent of any of the rights hereunder shall not release any Grantor from any of its duties or obligations under the contracts and agreements included in the Collateral and (c) no Secured Party shall have any obligation or liability under the contracts and agreements included in the Collateral by reason of this Agreement or any other Security Document, nor shall any Secured Party be obligated to perform any of the obligations or duties of any Grantor thereunder or to take any action to collect or enforce any claim for payment assigned hereunder.

     Section 5.06. Additional Equity Interests. (a) Pledged Equity. Each Grantor agrees that (i) it will cause each Pledged Company the Pledged Equity in which has been pledged by such Grantor hereunder, not to issue any Equity Interests or other securities in addition to or in substitution for the Pledged Equity issued by such Pledged Company, except to such Grantor, (ii) it will pledge hereunder, immediately upon such Grantor’s acquisition (directly or indirectly) thereof, any and all additional Equity Interests issued by such Pledged Company, and (iii) it will cause all such Equity Interests issued by such Pledged Company to be certificated securities under Article 8 of the UCC and under Article 8 or Chapter 8 of the Uniform Commercial Code as in effect in the jurisdiction of organization of such Pledged Company; provided, however, that this Section 5.06 shall not limit any Grantor’s rights under Section 5.07(a)(ii).

     (b) Ownership of Equity Interests in Grantors. The Company agrees and covenants that it will at all times own, directly or indirectly, 100% of the outstanding Equity Interests (including all voting, economic and other rights associated therewith) in each Grantor, except for the rights of the Collateral Agent hereunder with respect to the Equity Interests in any Grantor that is a Pledged Company.

     (c) Ownership of Equity Interests in Pledged Companies. Each Grantor (including any successor thereto pursuant to a merger or consolidation permitted under Section 6.05 of the Credit Agreement) agrees and covenants that (i) it will at all times remain a registered organization, as defined in Section 9-102(70) of the UCC, and (ii) with respect to each Pledged Company in which such Grantor has pledged Equity Interests hereunder, such Grantor will at all times own directly 100% of the outstanding Equity Interests issued by such Pledged Company (including voting, economic and other rights associated therewith), except to the extent permitted under Section 6.04(a)(iv) of the Credit Agreement and except for the rights of the Collateral Agent hereunder.

     Section 5.07. Release of Collateral. (a) Partial Release of Collateral.

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     (i) Payments out of Pledged Accounts. Upon any payment of amounts out of any Pledged Account (and not deposited into, or transferred to, another Pledged Account) to (A) the Administrative Agent, the Collateral Agent or the Depository Bank in respect of amounts due and payable hereunder to such Persons or other Secured Parties, (B) any Secured Party or (C) the Company or any Restricted Subsidiary (or any other Person designated in writing by the Company to the Collateral Agent to receive such payment), in each case in accordance with the Security Documents, the Transaction Liens on such amount shall be automatically released without further action or consent by the Collateral Agent or any other Person (including any Secured Party).

     (ii) Release of Lien on Collateral. Upon the Disposition of any Collateral in a transaction permitted under the Credit Agreement and the other Loan Documents, the Transaction Liens on such Collateral shall be automatically released without further action or consent by the Collateral Agent or any other Person (including any other Secured Party).

     (b) Full Release of Collateral. On the earlier of (A) the Final Payment Date or (B) the date on which the requisite percentage of the Lenders have approved the release of the Transaction Liens in accordance with Section 10.02 of the Credit Agreement, the Transaction Liens shall be fully and automatically released without further action by the Collateral Agent or any other Person (including any other Secured Party), and all rights to the Collateral shall revert to the applicable Grantor.

     (c) Delivery of Releases and Return of Collateral. Upon the release of any Transaction Lien pursuant to this Section 5.07, the Collateral Agent will, at the applicable Grantor’s expense, (i) execute and deliver to such Grantor such release or releases (including Uniform Commercial Code partial release or termination statements) as such Grantor shall reasonably request to evidence such release, and (ii) deliver to the applicable Grantors or their designees designated in writing to the Collateral Agent such Collateral, including any Assets in the Pledged Accounts and any certificates or instruments representing or evidencing any such Collateral that is Security Collateral.

     Section 5.08. Voting Rights, Dividends, Payments, Etc. (a) So long as no Event of Default shall have occurred and be continuing:

     (i) each Grantor shall be entitled to exercise any and all voting and other consensual rights pertaining to the Security Collateral (including rights relating to conversion or exchange thereof) of such Grantor or any part thereof at any time and for any purpose; provided that such Grantor will not exercise or refrain from exercising any such right if such action would violate this Agreement;

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     (ii) except as provided in Section 5.08(c), each Grantor shall be entitled to receive and retain any and all cash dividends, interest and other cash distributions paid in respect of the Security Collateral of such Grantor;

     (b) each Grantor shall be entitled to receive and retain all payments made on or in respect of Payment Collateral pledged by such Grantor; and

     (i) the Collateral Agent will (A) execute and deliver (or cause to be executed and delivered) to each Grantor all such proxies and other instruments as such Grantor may reasonably request for the purpose of enabling such Grantor to exercise the voting and other rights that it is entitled to exercise pursuant to paragraph (i) above (including, in the case of a conversion or exchange of Pledged Equity, the Collateral Agent’s delivering to the Pledged Company, as applicable, on behalf of the applicable Grantor, the certificate(s) or instrument(s) representing or evidencing any such Collateral for the purpose of effecting the exchange of such certificate(s) or instrument(s) for new certificate(s) or instrument(s)) and to receive the dividends, interest or other distributions that it is authorized to receive and retain pursuant to paragraph (ii) above, and (B) with respect to Payment Collateral, provide such instructions to account debtors and Persons obligated to make payments on instruments as will enable each Grantor to receive all payments it is authorized to receive and retain pursuant to paragraph (b) above. In the absence of instructions to vote or exercise other rights, the Collateral Agent shall not be obligated and shall incur no liability for its failure to take any action in respect of such rights.

     (c) The Collateral Agent shall be entitled to receive (whether or not an Event of Default has occurred and is continuing), (i) all non-cash dividends and distributions (including distributions upon conversion or exchange of Security Collateral) paid in respect of Security Collateral, which shall be held by the Collateral Agent as Security Collateral, and (ii) all cash dividends, interest and other cash distributions in respect of Security Collateral distributed in exchange for, in redemption of, or in connection with a partial or total liquidation or dissolution or with a reduction of capital, capital surplus or paid-in-surplus, which distributions described in this clause (ii) shall be deposited in the Collateral Account and held and administered as Account Collateral, provided, however, that a Credit Related Party that receives a dividend from a FERC-Regulated Restricted Subsidiary shall not be required to deliver such funds to the Collateral Agent so long as (x) such funds are not proceeds of a Mandatory Asset Reduction Event and (y) such funds are otherwise transferred to the Company. Each issuer of Pledged Equity that is a party to this Agreement agrees to pay and deliver all dividends, distributions and interest described in this Section 5.08(c) on such Pledged Equity directly to the Collateral Agent. With respect to any Pledged

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Equity issued in conversion or exchange of Pledged Equity issued by an issuer that is not a Pledged Company, the Grantor that has pledged such Pledged Equity shall instruct the issuer to deliver directly to the Collateral Agent the Pledged Equity so issued in the exchange or conversion. Any and all dividends, distributions and interest described in this Section 5.08(c) that are received by a Grantor contrary to the provisions of this Section 5.08(c), shall be received in trust for the benefit of the Collateral Agent, shall be segregated from the other property or funds of such Grantor, and shall promptly be delivered or paid over to the Collateral Agent and held and administered as above provided in this Section 5.08(c).

     (d) Upon the occurrence and during the continuance of any Event of Default:

     (i) all rights of each Grantor to exercise or refrain from exercising the voting and other consensual rights that it would otherwise be entitled to exercise pursuant to Section 5.08(a)(i) shall, upon delivery by the Collateral Agent to such Grantor of a written notice of such Event of Default, cease, and all such rights shall thereupon become vested in the Collateral Agent, which shall thereupon have the sole right to exercise or refrain from exercising such voting and other consensual rights;

     (ii) all rights of each Grantor to receive the dividends, interest and other distributions that it would otherwise be authorized to receive and retain pursuant to Section 5.08(a)(ii) shall, upon delivery by the Collateral Agent to such Grantor of a written notice of such Event of Default, cease, and all such rights shall thereupon become vested in the Collateral Agent, and any and all such cash dividends, interest and other cash distributions received by such Grantor shall be promptly delivered to the Collateral Agent who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered in accordance with Section 4.02(b)(iii). With respect to any issuer of Pledged Equity that is a party to this Agreement, upon delivery by the Collateral Agent to such issuer of a written notice of such Event of Default, such issuer shall thereafter pay and deliver all dividends, distributions and interest described in this Section 5.08(d)(ii) directly to the Collateral Agent, until such issuer has received written notice from the Collateral Agent that such Event of Default no longer exists. Each Grantor that has granted a security interest in Pledged Equity under this Agreement in an issuer that is not a party to this Agreement, agrees to cause such issuer to pay and deliver all dividends, distributions and interest described in this Section 5.08(d)(ii) directly to the Collateral Agent. Any such dividends, interest and distributions received by a Grantor contrary to the provisions of this Section 5.08(d)(ii) shall be received in trust for the benefit of the Collateral Agent, shall be segregated

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from the other funds of such Grantor and shall be promptly paid over to the Collateral Agent who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered as above provided in this Section 5.08(d)(ii); and

     (iii) all rights of each Grantor to receive the payments on Payment Collateral that it would otherwise be authorized to receive and retain pursuant to Section 5.08(b) shall, upon delivery by the Collateral Agent to the Grantors and the Pipeline Company Borrowers of a written notice of such Event of Default, cease and thereafter all such payments shall be made by the Grantor or the Pipeline Company Borrower, as applicable, that is the account debtor or Person obligated to make payment on such Payment Collateral, directly to the Collateral Agent, who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered in accordance with Section 4.02(b)(iii). Any such payments received by a Grantor contrary to the provisions of this Section 5.08(d)(iii) shall be received in trust for the benefit of the Collateral Agent, shall be segregated from the other funds of such Grantor and shall be promptly paid over by such Grantor to the Collateral Agent who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered in accordance with this Section 5.08(d)(iii).

     Section 5.09. The Collateral Agent Appointed Attorney-in-fact. Each Grantor hereby irrevocably appoints the Collateral Agent such Grantor’s attorney-in-fact, with full authority in the place and stead of such Grantor and in the name of such Grantor or otherwise, from time to time, in the Collateral Agent’s discretion, to take any action and to execute any instrument that the Collateral Agent may deem necessary or advisable to accomplish the purposes of this Agreement and any other Security Document with respect to the Collateral and the Collateral Agent’s rights and remedies with respect thereto, including:

     (a) to ask for, demand, collect, sue for, recover, compromise, receive and give acquittance and receipts for moneys due and to become due under or in respect of any of the Collateral;

     (b) to receive, indorse and collect any drafts or other instruments, documents and chattel paper, in connection with clause (a) above; and

     (c) to file any claims or take any action or institute any proceedings that the Collateral Agent may deem necessary or desirable for the collection of any of the Collateral or otherwise to enforce the rights of the Collateral Agent and any other Secured Party with respect to any of the Collateral;

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provided that the Collateral Agent shall not exercise the power and authority granted to it pursuant to this Section 5.09 except during such period as an Event of Default has occurred and is continuing.

     Section 5.10. Netting of Accounts. Notwithstanding any other provision of this Agreement or the Credit Agreement, so long as no Event of Default has occurred and in continuing, any Credit Related Party may reduce (through the exercise of set-off or similar rights) the principal amount of any accounts, payment intangibles, instruments or chattel paper owed by it to another Credit Related Party by the amount of any accounts, payment intangibles, instruments or chattel paper owed to it or any of its Subsidiaries by such other Credit Related Party or any Subsidiaries of such other Credit Related Party.

ARTICLE 6
Remedies And Enforcement`

     Section 6.01. Remedies And Enforcement. (a) At such time as any Event of Default has occurred and is continuing, the Collateral Agent shall have the right to take such actions as are necessary or appropriate to enforce, implement and administer the provisions hereof or of any other Security Document that are applicable to any period during which an Event of Default has occurred and is continuing, and without limiting the foregoing, the Collateral Agent shall have and may exercise, enforce, implement and administer all rights, privileges, powers, benefits and remedies granted to or arising in favor of the Collateral Agent under such provisions with respect to any such Event of Default, including in each case referenced above the provisions of Section 4.02(b)(iii), 4.03(f), 4.05(a), 4.06, 5.03(a), 5.08, and 5.09, with respect to any Net Cash Proceeds constituting Mandatory Asset Reduction Amounts, the application or non-application of funds in Pledged Accounts, deposits or transfers of funds into or from Pledged Accounts or subaccounts thereof, delivery of funds from Pledged Accounts to the Collateral Agent, the right to direct investments, voting rights with respect to Security Collateral and powers of attorney.

     (b) At such time as an Event of Default has occurred and is continuing, the Collateral Agent shall have and in its discretion may exercise any or all of the following rights and remedies:

     (i) Enforcement Actions. The Collateral Agent may take any Enforcement Action or Enforcement Actions (at such times, places and by such methods, as the Collateral Agent shall determine, including any actions incidental to carrying out any such Enforcement Action) in order to enforce the Security Documents and to realize upon the Collateral or, in the case of any Insolvency Proceeding against the Company or any of its

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Subsidiaries, seeking to enforce the claims and/or Transaction Liens, including claims under the Security Documents.

     (ii) Sale; Incidents of Sale. The Grantors agree that, to the extent notice of sale shall be required by Applicable Law with respect to the Disposition of any Collateral, at least ten days’ notice to the Company of the time and place of any public Disposition or the time after which any private Disposition is to be made shall constitute reasonable notification. The Collateral Agent shall not be obligated to make any Disposition of Collateral regardless of notice of Disposition having been given. The Collateral Agent may adjourn any public or private Disposition from time to time by announcement at the time and place fixed therefor, and such Disposition may, without further notice, be made at the time and place to which it was so adjourned. With respect to any Disposition of any of the Collateral made or caused to be made by the Collateral Agent, whether made under the power of Disposition hereby given or pursuant to judicial proceedings, to the extent permitted by Applicable Law:

     (A) Any Secured Party, the Company, and any of the Company’s Affiliates (including any Grantor) may bid for, and purchase, the Collateral offered for sale, and, upon compliance with the terms of sale and Applicable Law, may hold and Dispose of such property; and

     (B) Pursuant to the power of attorney granted under Section 5.09(a), the Collateral Agent may, but shall not be obligated to, make all necessary deeds, bills of sale and instruments of assignment and transfer covering the Collateral Disposed of, and for that purpose the Collateral Agent may execute all necessary deeds, bills of sale and instruments of assignment and transfer, and may substitute one or more Persons with like power.

     (iii) Collateral Agent May File Proofs of Claim. In case of the pendency of any Insolvency Proceeding relative to the Company or any of its Subsidiaries or the Collateral, the Collateral Agent (irrespective of whether any of the outstanding Secured Obligations shall then be due and payable) shall be entitled and empowered (but not obligated), by intervention in such proceeding or otherwise, (A) to file and prove a claim for the whole amount of the Secured Obligations owing and unpaid in order to protect the rights of the Secured Parties under the Security Documents and with respect to the Collateral, and to file such other papers or documents as may be necessary or advisable in order to have the claims of the Collateral Agent (including any claim for the reasonable compensation, disbursements and advances of the Collateral Agent in its

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individual or trust capacity and its agents and counsel) and of any other Secured Parties in respect of the Security Documents and the Collateral allowed in such judicial proceeding and (B) to collect and receive any moneys or other property payable or deliverable on any such claims and to distribute the same; and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Secured Party to make payments with respect to such claims to the Collateral Agent.

     (iv) Collateral Agent May Enforce Claims. All rights of action and claims under this Agreement and the other Security Documents may be prosecuted and enforced by the Collateral Agent; provided that the Collateral Agent is also hereby appointed as agent for the other Secured Parties for the purposes of protecting their interests in and to any portion of the Collateral and under the Security Documents, and the Collateral Agent shall take such action solely as agent for the Secured Parties.

     Section 6.02. Application of Proceeds. If an Event of Default shall have occurred and be continuing and the Collateral Agent applies (i) any cash held in the Pledged Accounts or (ii) the proceeds of any Disposition of all or any part of the Collateral, such cash and/or proceeds shall be applied to the Secured Obligations in the following order of priorities:

     first, to pay the expenses of such Disposition, including reasonable compensation to agents of and counsel for the Collateral Agent, and all expenses, liabilities and advances incurred or made by the Collateral Agent in connection with the Security Documents, and any other amounts then due and payable to the Collateral Agent in its capacity as such pursuant to Section 9.01 hereof or Section 10.03 of the Credit Agreement;

     second, to pay the unpaid principal of all Borrowings and all unreimbursed LC Disbursements and to Cash Collateralize all outstanding Letters of Credit, all ratably until the principal of all Borrowings and all unreimbursed LC Disbursements shall have been paid in full and all Letters of Credit shall have been Cash Collateralized;

     third, to pay all other amounts owed under the Credit Agreement and the other Loan Documents ratably, until all such other amounts shall have been paid in full;

     fourth, to pay all other Secured Obligations ratably, until payment in full of all such other Secured Obligations shall have been made; and

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     finally, to pay to the relevant Grantor, or as a court of competent jurisdiction may direct, any surplus then remaining from the proceeds of the Collateral owned by it;

provided that Collateral owned by a Subsidiary Grantor and any proceeds thereof shall be applied pursuant to the foregoing clauses first, second, third and fourth only to the extent permitted by the limitation in Section 2.01(b) of the Subsidiary Guarantee Agreement. The Collateral Agent may make such distributions hereunder in cash or in kind or, on a ratable basis, in any combination thereof.

     Section 6.03. Other Remedies of Secured Parties. Except as the same relates to the Collateral or as otherwise expressly prohibited by this Agreement or any other Security Document, each Secured Party may exercise any right or power, enforce any remedy, give any direction, consent or waiver or make any determination, under or in respect of any provision of any Financing Document to which it is a party. Notwithstanding the foregoing, no Secured Party other than the Collateral Agent shall have the right to take any Enforcement Action with respect to the Collateral or the Subsidiary Guarantee Agreement or seek to exercise and enforce the Transaction Liens, and all such Enforcement Actions shall be effected solely through the Collateral Agent. No reference in this Agreement to the Collateral Agent’s making a demand for payment under the Subsidiary Guarantee Agreement shall be construed to mean that such a demand is required in order to cause any obligation under the Subsidiary Guarantee Agreement to become due and payable, it being understood that obligations under the Subsidiary Guarantee Agreement shall become due and payable at such times as they become due and payable under the terms of the Subsidiary Guarantee Agreement.

ARTICLE 7
Depository Bank

     Section 7.01. Depository Bank. The provisions of Article 9 of the Credit Agreement shall inure to the benefit of the Depository Bank to the same extent as if it were named as an Agent therein.

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ARTICLE 8
[Reserved]

ARTICLE 9
Miscellaneous

     Section 9.01. Indemnity And Expenses. (a) Each Credit Party agrees to indemnify (without duplication), defend and save and hold harmless each of the Collateral Agent, the Depository Bank and the Secured Parties and each of their Affiliates and their respective officers, directors, employees, agents and advisors (each, an “Indemnified Party”) from and against, and shall pay, any and all claims, damages, losses, liabilities and expenses (including reasonable fees and expenses of counsel) that may be incurred by or asserted or awarded against any Indemnified Party, in each case arising out of or in connection with (i) this Agreement or the other Security Documents, or (ii) as a result of the execution or delivery of this Agreement or the other Security Documents or the performance by the Credit Parties hereto and thereto of their respective obligations hereunder and thereunder, except in each case of clause (i) and (ii), as to any particular Indemnified Party, to the extent such claim, damage, loss, liability or expense is found in a final, nonappealable judgment by a court of competent jurisdiction to have resulted from, or to be attributable to, the gross negligence or willful misconduct of such Indemnified Party or its employees or agents. The indemnification provisions of this Section 9.01(a) are not intended to constitute a guaranty of payment of any principal, interest, facility or commitment fees, rental or other lease payments, or analogous amounts, under any Secured Obligations; provided that nothing in this Section 9.01(a) shall limit the liability of any Credit Party for the payment of any Secured Obligation, to the extent such liability arises under any other Financing Document, including any liability arising under this Agreement.

     (b) Each Credit Party will pay to the Collateral Agent the amount of any and all reasonable out-of-pocket expenses, including the reasonable fees and expenses of its counsel and of any experts and agents, that the Collateral Agent may incur in connection with (i) the administration of this Agreement and the other Security Documents, (ii) the custody, preservation, or the sale of, collection from or other realization upon, any of the Collateral of such Credit Party, (iii) the exercise or enforcement of any of the rights of the Collateral Agent or any other Secured Party hereunder, or (iv) the failure by such Credit Party to perform or observe any of the provisions hereof required to be performed or observed by it.

     (c) The indemnities provided by the Credit Parties pursuant to this Agreement shall survive the expiration, cancellation, termination or modification of this Agreement or the other Security Documents, the resignation or removal of

36

the Collateral Agent, Depository Bank or Secured Parties and the provision of any subsequent or additional indemnity by any Person.

     (d) All amounts due under this Section 9.01 shall be payable not later than 30 days after the delivery of written demand to the Company therefor.

     Section 9.02. Amendments; Waivers, Etc. No amendment, modification or waiver of any provision of this Agreement or any other Security Document, and no consent with respect to any departure by the Collateral Agent, any other Secured Party or any Credit Party herefrom or therefrom, shall be effective unless the same shall be in writing and signed by the Credit Parties and the Collateral Agent in accordance with the Credit Agreement. Any such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given.

     Section 9.03. Security Interest Absolute And Waivers. (a) The obligations of each Credit Party under or in respect of this Agreement or any other Security Document to which such Credit Party is a party are independent of the Secured Obligations or any other obligations of any other Credit Party under or in respect of the Financing Documents, and a separate action or actions may be brought and prosecuted by the Collateral Agent against each Credit Party to enforce this Agreement or any other Security Document to which such Credit Party is a party, irrespective of whether any action is brought against the Company or any other Credit Party or whether the Company or any other Credit Party is joined in any such action or actions. All rights of the Collateral Agent and the other Secured Parties and the Liens granted by the Grantors hereunder, and all obligations of each Credit Party hereunder, shall be unaffected by, and each Credit Party hereby irrevocably waives (to the maximum extent permitted by applicable law) any defenses to its obligations under the Security Documents that it may now have or may hereafter acquire, which defenses in any way relate to, any or all of the following:

     (i) any lack of validity or enforceability of any Financing Document or any other agreement or instrument relating thereto;

     (ii) any change in the time, manner or place of payment of, or in any other term of, all or any of the Secured Obligations or any other obligations of any Credit Party under or in respect of the Financing Documents or any other amendment or waiver of or any consent to any departure from any Financing Document, including any increase in the Secured Obligations resulting from the extension of additional credit to any Credit Party or any of its Subsidiaries or otherwise;

     (iii) any Condemnation, exchange, release or non-perfection of any Collateral or any other collateral, or any release, amendment or waiver

37

of, or consent to, or departure from any Guaranty of all or any of the Secured Obligations;

     (iv) any manner of application of any Collateral or any other collateral, or proceeds thereof, to all or any of the Secured Obligations, or any manner of sale or other disposition of any Collateral or any other collateral for all or any of the Secured Obligations or any other obligations of any Credit Party under or in respect of the Financing Documents or any other assets of any Credit Party or any of its Subsidiaries;

     (v) any change, restructuring or termination of the corporate structure or existence of any Credit Party or any of its Subsidiaries;

     (vi) any failure of any Secured Party to disclose to any Credit Party any information relating to the business, condition (financial or otherwise), operations, performance, assets, nature of assets, liabilities or prospects of any other Credit Party now or hereafter known to such Secured Party (each Credit Party waiving any duty on the part of the Secured Parties to disclose such information);

     (vii) the failure of any other Person to execute or deliver this Agreement or any other Security Document, guaranty or agreement or the release or reduction of liability of any Credit Party or other grantor or surety with respect to the Secured Obligations; or

     (viii) any other circumstance (including any statute of limitations) or any existence of or reliance on any representation by any Secured Party that might otherwise constitute a defense available to, or a discharge of, such Credit Party or any other Credit Party or third party grantor of a secured interest, but specifically excluding any defense or discharge arising as a result of performance or indefeasible payment.

     (b) This Agreement shall continue to be effective or be reinstated, as the case may be, if at any time any payment of any of the Secured Obligations is rescinded or must otherwise be returned by any Secured Party or by any other Person upon the insolvency, bankruptcy or reorganization of any Credit Party or otherwise, all as though such payment had not been made.

     (c) Each Credit Party hereby unconditionally and irrevocably waives promptness, diligence, notice of acceptance, presentment, demand for performance, notice of nonperformance, default, notice of intent to accelerate, acceleration, protest or dishonor and any other notice with respect to any of the Secured Obligations and this Agreement or any other Security Document to which such Credit Party is a party and any requirement that any Secured Party protect, secure, perfect or insure any Lien or any property subject thereto or

38

exhaust any right or take any action against any Credit Party or any other Person or any Collateral.

     (d) Each Credit Party hereby unconditionally and irrevocably waives any right to revoke this Agreement or any other Security Document to which such Credit Party is a party and acknowledges that this Agreement or any other Security Document to which such Credit Party is a party is continuing in nature and applies to all Secured Obligations, whether existing now or in the future.

     (e) Each Credit Party hereby unconditionally and irrevocably waives (i) any defense arising by reason of any claim or defense based upon an election of remedies by the Collateral Agent that in any manner impairs, reduces, releases or otherwise adversely affects the subrogation, reimbursement, exoneration, contribution or indemnification rights of such Credit Party or other rights of such Credit Party to proceed against any other Credit Party, any other guarantor or any other Person or any Collateral and (ii) any defense based on any right of set-off or counterclaim against or in respect of the obligations of such Credit Party hereunder.

     (f) Each Credit Party and each of the Secured Parties confirms that it is the intention of all such Persons that this Agreement, the other Security Documents and the obligations of each Credit Party hereunder or thereunder do not constitute a fraudulent transfer or fraudulent conveyance for purposes of the Bankruptcy Code, the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent Transfer Act or any similar foreign, federal or state law to the extent applicable to this Agreement, any other Security Document and the obligations of each Credit Party hereunder or thereunder or in connection with any Insolvency Proceeding in respect of any Credit Party. To effectuate the foregoing intention, the Collateral Agent, the other Secured Parties and the Subsidiary Grantors hereby irrevocably agree that the obligations of each Subsidiary Grantor under this Agreement and the other Security Documents at any time shall not exceed the maximum amount as will result in the obligations of such Subsidiary Grantor under this Agreement and the other Security Documents not constituting a fraudulent transfer or fraudulent conveyance (after giving effect to Section 2.02 of the Subsidiary Guarantee Agreement).

     (g) Each Credit Party acknowledges that it will receive substantial direct and indirect benefits from the financing arrangements contemplated by the Security Documents and that the waivers set forth in this Section 9.03 are knowingly made in contemplation of such benefits.

     Section 9.04. Notices; Etc. (a) Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to paragraph (b) below), all notices and other communications provided for herein

39

shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

     (i) if to the Company, any Pipeline Borrower or the Collateral Agent, to it at its address specified in or pursuant to Section 10.01 of the Credit Agreement;

     (ii) if to any Grantor, to it c/o the Company at the address specified in or pursuant to clause (i) above;

     (iii) if to the Depository Bank, to it at JPMorgan Chase Bank, N.A., Institutional Trust Services, 4 New York Plaza, 21st Floor, New York, New York 10004, Attention of Linda Ramos-McCollum (Telecopy No. (212) 623-6168.

     (b) Notices and other communications among the Secured Parties, the Collateral Agent and/or the Depository Bank hereunder may be delivered or furnished by electronic communications. The Administrative Agent or a Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

     (c) Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given and effective, if sent by mail or courier on the date of delivery thereof to the address specified herein for such notice, or if by telecopier when the answerback is received or if by other means, on the date of receipt; provided that a notice given by telecopier or electronic communication in accordance with this Section 9.04 but received on any day other than a Business Day or after business hours in the place of receipt, will be deemed to be received on the next Business Day in that place.

     Section 9.05. Continuing Security Interest; Assignments. This Agreement and each other Security Document shall create a continuing security interest in the Collateral and shall (a) remain in full force and effect until terminated in accordance with its terms, (b) be binding upon each Credit Party, its successors and assigns and (c) inure, together with the rights and remedies of the Collateral Agent hereunder, to the benefit of the Secured Parties and their respective successors, transferees and assigns. Without limiting the generality of the foregoing clause (c), each Secured Party may assign, sell or otherwise transfer all or any portion of its rights and obligations in respect of any Secured Obligations held by it to any other Person, and such other Person shall thereupon become

40

vested with all the benefits in respect thereof granted to such Secured Party herein or otherwise, in each case subject to the Financing Documents.

     Section 9.06. [Reserved].

     Section 9.07. Execution In Counterparts. This Agreement may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by telecopier shall be effective as delivery of an original executed counterpart of this Agreement.

     Section 9.08. Severability. If any provision of this Agreement shall be invalid, illegal or unenforceable, then to the extent permitted by law, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

     Section 9.09. Integration. This Agreement and the other Financing Documents represent the agreement of the parties hereto with respect to the subject matter hereof, and there are no promises, undertakings, representations or warranties by any party relative to subject matter hereof not expressly set forth or referred to herein or in the other Financing Documents.

     Section 9.10. No Partnership. Nothing contained in this Agreement and no action by any Secured Party is intended to constitute or shall be deemed to constitute the Secured Parties (or any of them) a partnership, association, joint venture or other entity.

     Section 9.11. No Reliance. No Secured Party has relied on any representation or warranty of any other Secured Party with respect to this Agreement and the transactions contemplated hereunder unless such representation or warranty has been set forth expressly in this Agreement.

     Section 9.12. Release. On the date hereof, without further action by any party to this Agreement or the Existing Security Agreement, each of the Released Parties shall cease to be a Subsidiary Grantor under the Existing Security Agreement, and shall not be deemed a Subsidiary Grantor under this Agreement.

     Section 9.13. No Impairment. Nothing in this Agreement is intended or shall be construed to impair, diminish or otherwise adversely affect any other rights the Secured Parties may have or may obtain against the Company, any other Credit Party or any other Person.

     Section 9.14. Equitable Remedies. Each party to this Agreement acknowledges that the breach by it of any of the provisions of this Agreement is

41

likely to cause irreparable damage to the other party. Therefore, the relief to which any party shall be entitled in the event of any such breach or threatened breach shall include, but not be limited to, a mandatory injunction for specific performance, injunctive or other judicial relief to prevent a violation of any of the provisions of this Agreement, damages and any other relief to which it may be entitled at law or in equity.

     Section 9.15. Remedies. (a) Other than as stated expressly herein, no remedy herein conferred upon the Collateral Agent or any other Secured Party is intended to be exclusive of any other remedy and each and every such remedy shall be cumulative and shall be in addition to every other remedy given under this Agreement or the other Financing Documents, or now or hereafter existing at law or in equity or by statute or otherwise.

     (b) As between the Credit Parties and each Secured Party, it is agreed that the amounts payable by the Company at any time in respect of the Secured Obligations shall be a separate and independent debt and each Secured Party shall be entitled, subject to Section 6.03, to protect and enforce its rights arising out of the Financing Documents to which it is a party and its right, pursuant to the terms of any Financing Document to which it is a party, to cancel or suspend its commitments thereunder and to accelerate the maturity of any of the Secured Obligations, in each case in accordance with the applicable Financing Documents, and, except as aforesaid, it shall not be necessary for any other Secured Party to consent to, or be joined as an additional party in, any proceedings for such purposes.

     (c) In case the Collateral Agent shall have proceeded to enforce any right, remedy or power under this Agreement or any other Security Document and the proceeding for the enforcement thereof shall have been discontinued or abandoned for any reason or shall have been determined adversely to the Collateral Agent, then and in every such case the Credit Parties and the Secured Parties shall, subject to any effect of or determination in such proceeding, severally and respectively be restored to their former positions and rights under this Agreement or any other Security Document and thereafter all rights, remedies and powers of the Secured Parties shall continue as though no such proceeding had been taken.

     Section 9.16. Limitations. (a) The obligations, liabilities or responsibilities of any party hereunder shall be limited to those obligations, liabilities or responsibilities expressly set forth and attributed to such party pursuant to this Agreement or otherwise applicable under Applicable Law.

     (b) In no event shall any Secured Party be liable for, and each of the Credit Parties hereby agrees not to assert any claim against any Secured Party, on any theory of liability, for consequential, incidental, indirect, punitive or special

42

damages arising out of or otherwise relating to this Agreement, the other Financing Documents, any of the transactions contemplated herein or therein, or the actual or proposed use of the proceeds of any Loan, Letter of Credit or Secured Hedging Agreement.

     Section 9.17. Survival. Notwithstanding anything in this Agreement to the contrary, Sections 9.01, 9.17, 9.19, 9.20 and 9.21 shall survive any termination of this Agreement. In addition, each representation and warranty made or deemed to be made hereunder shall survive the Effective Date.

     Section 9.18. [Reserved].

     Section 9.19. Jurisdiction, Etc. (a) Each of the parties hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the Supreme Court of the State of New York, sitting in New York County, and of the United States District Court for the Southern District of New York, and any appellate court from any thereof, in any action or proceeding by the Collateral Agent or any Secured Party arising out of or relating to this Agreement or any of the other Security Documents to which it is a party or under which it is a beneficiary, or for recognition or enforcement of any judgment obtained in any such action or proceeding, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State court or, to the fullest extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that any Secured Party may otherwise have to bring any action or proceeding relating to this Agreement, the Security Documents or any of the other Financing Documents in the courts of any jurisdiction.

     (b) Each of the parties irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection that it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or any of the other Security Documents to which it is a party in any court referred to in paragraph Error! Reference source not found. of this Section. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

     (c) Each party to this Agreement irrevocably consents to service of process in any action or proceeding referred to in this Section 9.19 by the mailing thereof by certified mail, return receipt requested, addressed as provided in Section 9.04(a), with a copy thereof to the “General Counsel” of such Person at

43

such same address. Nothing in this Agreement will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

     Section 9.20. GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

     Section 9.21. Waiver of Jury Trial. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (a) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, AND (b) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

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     IN WITNESS WHEREOF, each party hereto has caused this Agreement to be duly executed and delivered by its officer thereunto duly authorized as of the date first above written.

THE COMPANY	EL PASO CORPORATION
	By:
		Name: John Hopper
		Title: Vice President
PIPELINE COMPANY BORROWERS:	EL PASO NATURAL GAS COMPANY
	By:
		Name: John Hopper
		Title: Vice President
	TENNESSEE GAS PIPELINE COMPANY
	By:
	Name:	John Hopper
	Title:	Vice President
SUBSIDIARY GRANTORS:	EL PASO EPNG INVESTMENTS, L.L.C.
	By:
		Name: John Hopper
		Title: Vice President
	EL PASO TENNESSEE PIPELINE CO.
	By:
	Name:	John Hopper
	Title:	Vice President
	EL PASO TGPC INVESTMENTS, L.L.C.
	By:
	Name:	John Hopper
	Title:	Vice President

RELEASED PARTIES:	EL PASO CNG COMPANY, L.L.C.
	By:
		Name: John Hopper
		Title: Vice President
	EL PASO NORIC INVESTMENTS III, L.L.C.
	By:
	Name:	John Hopper
	Title:	Vice President
	EPPP CIG GP HOLDINGS, L.L.C.
	By:
	Name:	John Hopper
	Title:	Vice President

COLLATERAL AGENT:	JPMORGAN CHASE BANK, N.A., as Collateral Agent
	By:
		Name:
		Title:
DEPOSITORY BANK:	JPMORGAN CHASE BANK, N.A., as Depository Bank
	By:
		Name:
		Title:

SCHEDULE I

SUBSIDIARY GRANTORS

El Paso EPNG Investments, L.L.C.
El Paso Tennessee Pipeline Co.
El Paso TGPC Investments, L.L.C.

Schedule I

1

SCHEDULE II

INITIAL PLEDGED EQUITY

Percentage

Jurisdiction

of

of

Outstanding

Organization

Class of

Number

Equity

Name of

of

Equity

Certificate

of

Interests of

Grantor

Name of Issuer

Issuer

Interest

Par Value

No.

Shares

Issuer

El Paso EPNG Investments, L.L.C.

El Paso Natural Gas Company

Delaware

Common Stock

1.00

2

1,000

100

%

El Paso Tennessee Pipeline Co.

El Paso TGPC Investments, L.L.C.

Delaware

Membership Interests

n/a

1

n/a

100

%

El Paso TGPC Investments, L.L.C.

Tennessee Gas Pipeline Company

Delaware

Common Stock

5.00

4

208

100

%

Schedule I

1

SCHEDULE III

NAME, LOCATION, CHIEF EXECUTIVE OFFICE, TYPE OF ORGANIZATION, JURISDICTION OF ORGANIZATION,
AND ORGANIZATIONAL IDENTIFICATION NUMBER

			Type of	Jurisdiction of	Organizational
Company Name	Location	Chief Executive Office	Organization	Organization	I.D. No.
El Paso Corporation	Delaware	El Paso Building 1001 Louisiana St. Houston, Texas 77002	Corporation	Delaware		2884676
El Paso EPNG Investments, L.L.C.	Delaware	El Paso Building 1001 Louisiana St. Houston, Texas 77002	Limited Liability Company	Delaware		3640051
El Paso Tennessee Pipeline Co.	Delaware	El Paso Building 1001 Louisiana St. Houston, Texas 77002	Corporation	Delaware		2140052
El Paso TGPC Investments, L.L.C.	Delaware	El Paso Building 1001 Louisiana St. Houston, Texas 77002	Limited Liability Company	Delaware		3640033

Schedule III

1

SCHEDULE IV

CHANGES
Scope: Within Last 5 Years Prior to Effective Date

			Changes in	Changes in the	Changes in the	Changes in the
	Changes in the	Changes in	the Chief	Type of	Jurisdiction of	Organizational
Company	Company Name	Location	Executive Office	Organization	Organization	I.D. No.
El Paso Corporation	None	None	None	None	None	None
El Paso EPNG Investments, L.L.C.	None	None	None	None	None	None
El Paso Tennessee Pipeline Co.	None	None	None	None	None	None
El Paso TGPC Investments, L.L.C.	None	None	None	None	None	None

Schedule VI

1

SCHEDULE V

SECURED HEDGING AGREEMENTS

1. None.

Schedule V

1

EXHIBIT A

FORM OF OFFICER’S CERTIFICATE FOR QUALIFIED INVESTMENTS

     The undersigned hereby certifies that [he/she] is the duly appointed [President, Vice-President, Treasurer, or Chief Financial Officer] of El Paso Corporation, a Delaware corporation (the “Company”), and that, as such, [he/she] is authorized to execute and deliver this certificate of the Company pursuant to Section 4.03(e) of that certain Third Amended and Restated Security Agreement, dated as of November ___, 2007 among the Company, the Pipeline Company Borrowers, the Subsidiary Grantors and JPMorgan Chase Bank N.A. (“JPMCB”), in its capacity as Collateral Agent for the Secured Parties and Depository Bank (as amended, supplemented or otherwise modified from time to time, the “Security Agreement”.

     The undersigned hereby directs, on behalf of the Company, that $                     (the “Transfer Amount”) be withdrawn from [the Qualified Investments Account] [identify applicable Qualified Investments Subaccount] and transferred to [                    ] (the “Restricted Subsidiary”) pursuant to Section 4.03(e) of the Security Agreement.

     The undersigned further certifies, on behalf of the Company, that (i) the Transfer Amount resulted from a Disposition of Covered Assets of the Restricted Subsidiary; [(ii) if the Restricted Subsidiary is a FERC-Related Restricted Subsidiary; all funds retained by the Restricted Subsidiary pursuant to Section 4.03(a) of the Security Agreement from the Net Cash Proceeds of all of such Restricted Subsidiary’s Dispositions of Covered Assets prior to the date hereof have been, or (by making the Qualified Investment(s) described in clause (iii) below) will be, used to make Qualified Investments;] and (iii) the Restricted Subsidiary will invest the Transfer Amount as follows, which investment constitutes one or more Qualified Investments: [Describe Qualified Investments to be made with the Transfer Amount].

     Each capitalized term used but not defined herein shall have the meaning ascribed thereto in the Security Agreement.

     This certificate shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York.

     IN WITNESS WHEREOF, I have set my hand on this certificate this ___ day of                     ,                       .

EL PASO CORPORATION

By:

Name:

Title:

Exhibit A

1

SCHEDULE VI

MATERIAL AGREEMENTS OF EL PASO CORPORATION

     a. Indenture, dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee.

     (i) First Supplemental Indenture, dated as of April 4, 2007.

     b. Indenture, dated as of May 10, 1999, between El Paso Corporation (f/k/a El Paso Energy Corporation) and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by HSBC Bank USA).

     (i) First Supplemental Indenture dated as of May 10, 1999 ($500 Million 6.75% Senior Notes due May 15, 2009).

     (ii) Sixth Supplemental Indenture dated as of May 14, 2001 ($500 Million 7% Notes due May 15, 2011).

     (iii) Seventh Supplemental Indenture dated as of June 10, 2002 ($600 Million 7.875% Notes due June 15, 2012 (Private Placement)).

     (iv) Eighth Supplemental Indenture dated as of June 26, 2002 (up to $575 Million 6.14% Senior Notes due 8/16/07).

     (v) Ninth Supplemental Indenture dated as of July 1, 2005 (Remarked $272,102,350 of 6.14% Senior Note due August 16, 2007 issued pursuant to the Eight Supplemental Indenture dated June 26, 2002 (held as collateral for the Purchase Contract portion of the Equity Security Units) for $272,102,000 of 7.625% Senior Notes due August 16, 2007).

     (vi) Tenth Supplemental Indenture dated as of December 28, 2005 (10.75% Senior Notes due 2010, 9.625% Senior Notes due 2012, 7.75% Senior Notes due 2032, 7.42% due 2037, 6.95% Senior Notes due 2028, 6.375% Senior Notes due 2009, 7.75% Senior Notes due 2010, 6.50% Senior Notes due 2008, 7.625% Senior Notes due 2008, 6.50% Senior Notes due 2006, 6.70% Senior Notes due 2027, 7.50% Senior Notes due 2007).

     (vii) Eleventh Supplemental Indenture dated as of August 31, 2006 (for the issuance of up to $150,000,000 of 7.75% Medium Term Notes due 2032 or 2035, as applicable, to be exchanged for 7.75% Senior Notes due 2032 or 7.75% Senior Debentures due October 15, 2035).

Third Amended and Restated Credit Agreement

Exhibit E - Page 1

     (viii) $300 Million 8.05% Global Medium Term Notes (Senior Fixed Rate Notes), due October 15, 2030, as described in the Pricing Supplement No. 1 dated October 5, 2000 to Supplemental Prospectus dated December 14, 1999 and Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (ix) $300 Million 7.375% Global Medium Term Notes (Senior Fixed Rate Notes), due December 15, 2012, as described in the Pricing Supplement No. 2 dated December 6, 2000 to Supplemental Prospectus dated December 14, 1999 and Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (x) $300 Million 6.95% Global Medium Term Notes (Senior Fixed Rate Notes), due December 15, 2007, as described in the Pricing Supplement No. 3 dated December 14, 2000, to Supplemental Prospectus dated December 13, 2000, to Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (xi) $700 Million 7.8% Global Medium Term Notes (Senior Fixed Rate Notes), due August 1, 2031, as described in the Pricing Supplement No. 01 dated July 25, 2001, to Supplemental Prospectus dated July 24, 2001, to Base Prospectus dated May 4, 2001, Registration No. 333-59704.

     (xii) $1,100 Million 7.75% Global Medium Term Notes (Senior Fixed Rate Notes), due January 15, 2032, as described in the Pricing Supplement No. 01 dated January 9, 2002 to Prospectus Supplement dated January 7, 2002, to Base Prospectus dated May 4, 2001.

     (xiii) Twelfth Supplemental Indenture dated as of June 18, 2007 ($375,000,000 6.875% Senior Notes due 2014, $900,000,000 7.000% Senior Notes due 2017).

     c. Indenture dated as of March 1, 1998 between El Paso Natural Gas Company (by assignment now El Paso Corporation) and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Law Debenture Trust Company).

     (i) First Supplemental Indenture dated as of March 17, 1998 ($334.75 Million 4.75% Convertible Subordinated Debentures due March 17, 2028, El Paso Energy Capital Trust I).

     (ii) Second Supplemental Indenture dated August 1, 1998 (the Holding Company formation transaction which authorized the merger of

Schedule VI

2

El Paso Natural Gas Company with El Paso Merger Company, with El Paso Natural Gas Company as the surviving corporation, and then El Paso Natural Gas Company stock was converted to into El Paso Energy Corporation (now El Paso Corporation) common stock and the debt was assumed by El Paso Corporation).

     (iii) Amended and Restated Declaration of Trust of El Paso Energy Capital Trust I, dated as of March 16, 1998, among El Paso Natural Gas Company, Chase Manhattan Bank, Chase Manhattan Bank Delaware and Administrative Trustees.

     d. Indenture, dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank).

     (i) First Supplemental Indenture dated as of June 10, 2002 ($300 Million 8.375% Notes due June 15, 2032).

     (ii) Second Supplemental Indenture dated as of April 4, 2007 ($355 Million 5.95% Notes due April 15, 2017).

     e. Indenture, dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.).

     f. Indenture, dated as of June 1, 1986, between Sonat Inc. (by merger now El Paso Corporation) and Manufacturers Hanover Trust Company (by merger now JPMorgan Chase Bank and subsequently replaced by HSBC BANK USA).

     (i) First Supplemental Indenture dated as of June 1, 1995 (Various amendments).

     (ii) Second Supplemental Indenture dated as of October 25, 1999 (assumption of Sonat obligations under Indenture dated June 1, 1986).

     (iii) $100 Million 6.75% Notes due October 1, 2007, as described in the Prospectus Supplement dated September 25, 1997 to Prospectus dated July 27, 1993.

     (iv) $100 Million 6.625% Notes due February 1, 2008, as described in the Prospectus Supplement dated January 27, 1998 to Prospectus dated July 27, 1993.

Schedule VI

3

     (v) $100 Million 7% Notes due February 1, 2018, as described in the Prospectus Supplement dated January 29, 1998 to Prospectus dated July 27, 1993.

     (vi) $600 Million 7.625% Notes due July 15, 2011, as described in the Prospectus Supplement dated July 7, 1999 to Prospectus dated September 9, 1998.

     g. Indenture, dated as of March 30, 1992, between Valero Energy Corporation (by merger PG&E Gas Transmission, Texas Corporation, then El Paso Gas Transmission Company (“GTT”) and now El Paso Corporation) and Bankers Trust Company (by merger now Deutsche Bank Trust Company Americas).

     (i) First Supplemental Indenture dated as of March 13, 1995 (authorized the issuance of $284 Million in Medium-Term Notes, various interest rates and maturities, 9 months to 30 years).

     (ii) Second Supplemental Indenture dated as of March 11, 2002 (conform Indenture dated March 30, 1992 to El Paso Corporation May 10, 1999 Indenture).

     (iii) Third Supplemental Indenture dated as of April 5, 2002 (merged GTT into El Paso Corporation).

     h. Indenture, dated as of October 1, 1990 between El Paso CGP Company, L.L.C. (f/k/a El Paso CGP Company and The Coastal Corporation) and The Bank of New York Trust Company, N.A. (f/k/a The Bank of New York) ($150 Million 10.75% Senior Debentures due October 1, 2010).

     (i) First Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso CGP Company, L.L.C. October 1, 1990 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (ii) Second Supplemental Indenture, dated as of December 31, 2005 among El Paso CGP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso CGP Company, L.L.C., assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso CGP Company, L.L.C.).

     i. Indenture, dated as of May 15, 1992 between El Paso CGP Company, L.L.C. (f/k/a El Paso CGP Company and The Coastal Corporation) and

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Bank of Montreal Trust Company (subsequently replaced by The Bank of New York Trust Company, N.A.).

     (i) First Supplemental Indenture, dated as of May 20, 1992 ($150 Million 9.625% Senior Debentures due May 15, 2012).

     (ii) Second Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso COP Company, L.L.C. May 15, 1992 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (iii) Third Supplemental Indenture, dated as of December 31, 2005 among El Paso COP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso COP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso COP Company, L.L.C.).

     j. Indenture, dated as of September 15, 1992 between El Paso COP Company, L.L.C. (f/k/a El Paso COP Company and The Coastal Corporation) and NationsBank, N.A. (subsequently replaced by The Bank of New York Trust Company, RA.).

     (i) Second Supplemental Indenture dated as of October 19, 1995 ($150 Million 7.75% Senior Debentures due October 15, 2035).

     (ii) Third Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso COP Company, L.L.C. September 15, 1992 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (iii) Fourth Supplemental Indenture, dated as of December 31, 2005 among El Paso COP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso COP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso COP Company, L.L.C.).

     k. Indenture, dated as of February 24, 1997 between El Paso COP Company, L.L.C. (f/k/a El Paso COP Company and The Coastal Corporation) and Harris Trust and Savings Bank (subsequently replaced by The Bank of New York Trust Company, N.A.).

     (i) First Supplemental Indenture dated as of February 24, 1997 ($200 Million 6.70% Senior Debentures due February 15, 2027, put date February 15, 2007).

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5

     (ii) Second Supplemental Indenture dated as of February 24, 1997 ($200 Million 7.42% Senior Debentures due February 15, 2037).

     (iii) Third Supplemental Indenture dated as of June 5, 1998 ($200 Million 6.5% Senior Debentures due June 1, 2008).

     (iv) Fourth Supplemental Indenture dated as of June 5, 1998 ($200 Million 6.95% Senior Debentures due June 1, 2028).

     (v) Fifth Supplemental Indenture dated as of February 10, 1999 ($200 Million 6.375% Senior Debentures due February 1, 2009).

     (vi) Eighth Supplemental Indenture dated as of June 16, 2000 ($400 Million 7.75% Notes due June 15, 2010).

     (vii) Eleventh Supplemental Indenture dated as of September 6, 2000 ($215 Million 7.625% Notes due 9/1/08).

     (viii) Twelfth Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso CGP Company, L.L.C. February 24, 1997 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (ix) Thirteenth Supplemental Indenture, dated as of December 31, 2005 among El Paso CGP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso CGP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso CGP Company, L.L.C.).

     l. Indenture, dated as of March 4, 1997, between Tennessee Gas Pipeline Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank).

     (i) First Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.5% Debentures due April 1, 2017).

     (ii) Second Supplemental Indenture dated as of March 13, 1997 ($300 Million 7% Debentures due March 15, 2027).

     (iii) Third Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.625% Debentures due April 1, 2037).

     (iv) Fourth Supplemental Indenture dated as of October 9, 1998 ($400 Million 7% Debentures due October 15, 2028).

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6

     (v) Fifth Supplemental Indenture dated June 10, 2002 ($240 Million 8.375% Senior Notes due June 15, 2032).

     m. Indenture, dated as of March 15, 1988, between Tenneco, Inc. (now El Paso Tennessee Pipeline Co.) and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company).

     (i) Second Supplemental Indenture dated as of March 30, 1988 ($250 Million 10% Debentures due March 15, 2008, outstanding balance $26.4 Million).

     (ii) Tenth Supplemental Indenture dated as of November 15, 1992 ($150 Million 9% Debentures due November 15, 2012, outstanding principal $1.1 Million).

     (iii) Twelfth Supplemental Indenture dated as of December 15, 1995 ($300 Million 7.25% Debentures due December 15, 2025, outstanding principal $23.2 Million).

     (iv) Thirteenth Supplemental Indenture dated as of December 10, 1996.

     n. Indenture, dated as of December 15, 1981, between Tenneco Inc. (now Tennessee Gas Pipeline Company) and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company) ($400 Million 6% Debentures due December 15, 2011, current balance $85.8 Million).

     (i) First Supplemental Indenture dated as of December 10, 1996.

     (ii) Second Supplemental Indenture dated as of December 10, 1996.

     o. Fiscal Agency Agreement dated May 6, 2002 among El Paso Corporation, Citibank, N.A. and Societe Generale Bank and Trust, 6 S.A. relating to €500 Million 7.125% Euro Notes due May 6, 2009.

     p. Credit Agreement dated as of June 20, 2007, among El Paso Corporation, the Lenders party thereto, Citicorp USA, Inc., as Administrative Agent and as Issuing Agent, and the Bank of New York as Paying Agent.

     (i) The Reimbursement Agreement dated as of June 20, 2007, between El Paso Corporation and Citibank, N. A.

Schedule VI

7

     (ii) Credit Agreement First Amendment dated as of August 28, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (iii) Credit Agreement Second Amendment dated as of September 6, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (iv) Credit Agreement Third Amendment dated as of September 17 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (v) Credit Agreement Fourth Amendment dated as of September 20, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (vi) Credit Agreement Fifth Amendment dated as of September 28, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (vii) Credit Agreement Sixth Amendment dated as of October 3, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (viii) Credit Agreement Seventh Amendment dated as of October 11, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (ix) Credit Agreement Eighth Amendment dated as of October 18, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     q. Other Credit and Facility Agreements

     (i) Discretionary Facility Agreement dated as of February 21, 2003, between El Paso Corporation and Compass Bank.

     (ii) Credit Agreement dated July 19, 2006 among El Paso Corporation and Deutsche Bank AG New York Branch as Initial Lender and Issuing Bank and Deutsche Bank AG New York Branch as Administrative Agent and Collateral Agent.

     (iii) First Tier Receivables Sale Agreement dated August 31, 2006, between Tennessee Gas Pipeline Company and TGP Finance Company, L.L.C.

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8

     (iv) Second Tier Receivables Sale Agreement dated August 31, 2006, between TGP Finance Company, L.L.C. and TGP Funding Company, L.L.C.

     (v) Receivables Purchase Agreement dated August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, Starbird Funding Corporation, the other investors from time to time parties thereto, BNP Paribas, New York Branch, and the other Managing Agents from time to time parties thereto.

     (a) Amendment No 1, dated as of December 1, 2006, to the Receivables Purchase Agreement dated as of August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, Starbird Funding Corporation and the other funding entities from time to time party thereto, BNP Paribas, New York Branch, and the other financial institutions from time to time party thereto.

     (vi) Facility Agreement dated as of January 4, 2007, between El Paso Corporation and Morgan Stanley Capital Services Inc.

     r. Letters of Credit with a Face Amount Exceeding $50,000,000

     (i) Application and Agreement for irrevocable Standby Letter of Credit, dated as of December 15, 2004, by El Paso Corporation to JPMorgan Chase Bank, N.A., in favor of Midland Cogeneration Venture Limited Partnership for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $110 Million 100 Thousand.

     (ii) Application for Irrevocable Standby Letter of Credit, dated as of July 29, 2006 by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Midland Cogeneration Venture Limited Partnership for the account of El Paso Merchant Energy, L.P. for the aggregate amount not exceeding $74 Million.

     (iii) Application for Irrevocable Standby Letter of Credit, dated as of September 1, 2005, by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Williams Power Company for the account of El Paso Merchant Energy, L.P. for the aggregate amount not exceeding $219 Million 900 Thousand.

     (iv) Application for Standby Letter of Credit, dated as of November 10, 2006, by El Paso Corporation to BNP Paribas in favor of

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9

Southeast Supply Header, LLC for the account of Southern Natural Gas Company in the amount of $60 Million.

     (v) Application for Standby Letter of credit, dated as of July 19, 2006, by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. in the amount of $184 Million.

     (vi) Application for Irrevocable Standby Application for Irrevocable Standby Letter of Credit, dated as of February 6, 2007, by El Paso Corporation to Fortis Bank S.A./N.V., in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $162 Million 100 Thousand.

     (vii) Application for Irrevocable Standby Letter of Credit, dated as of September 24, 2003, by El Paso Corporation to JPMorgan Chase Bank, N.A., in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $85 Million 750 Thousand.

     s. ISDA Master Agreements

     (i) 1992 ISDA Master Agreement dated October 24, 2001, between El Paso Corporation and Credit Suisse First Boston International.

     (ii) 1992 ISDA Master Agreement dated March 5, 2001, between El Paso Corporation and Westdeutsche Landesbank Girozentrale.

     (iii) 2002 ISDA Master Agreement dated August 29, 2003 between El Paso Corporation and Citibank, N.A.

     (iv) 2002 ISDA Master Agreement dated June 24, 2004, between El Paso Corporation and Deutsche Bank A.G.

     (v) 2002 ISDA Master Agreement dated November 22, 2004, between El Paso Corporation and Citigroup Financial Products Inc.

     t. Various Guaranties and Other Documents

     (i) Guaranty Agreements dated as of July 12, 2005 and December 13, 2006, by El Paso Corporation in favor of Mt. Franklin Insurance Ltd.

     (ii) Guaranty Agreement dated as of February 15, 2006, by El Paso Corporation in favor of Coastal Offshore Insurance Ltd.

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10

     (iii) Guaranty Agreement dated as of April 25, 2006 by El Paso Corporation in favor of Petroleo Brasileiro S.A. — Petrobas.

     (iv) Terms of 4.99% Convertible Perpetual Preferred Stock, pursuant to the Offering Memorandum dated as of April 11, 2005 by El Paso Corporation.

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11

EXHIBIT E

FORM OF

THIRD AMENDED AND RESTATED
SUBSIDIARY GUARANTEE AGREEMENT

THIRD AMENDED AND RESTATED
SUBSIDIARY GUARANTEE AGREEMENT

made by

CERTAIN SUBSIDIARIES OF

EL PASO CORPORATION

in favor of

JPMORGAN CHASE BANK, N.A.,
as Collateral Agent,
for the benefit of the Secured Parties referred to herein

Dated as of November __, 2007

TABLE OF CONTENTS

	Page
ARTICLE 1
Defined Terms
Section 1.01. Definitions		2
Section 1.02. Other Definitional Provisions		3
ARTICLE 2
Guarantee
Section 2.01.Guarantee		4
Section 2.02.Right of Contribution		5
Section 2.03.No Subrogation		5
Section 2.04.Amendments, Etc. With Respect to the Guaranteed Obligations		6
Section 2.05. Guarantee Absolute And Unconditional		6
Section 2.06. Reinstatement		7
Section 2.07. Payments		7
ARTICLE 3
Miscellaneous
Section 3.01. Amendments In Writing		8
Section 3.02. Notices		8
Section 3.03. No Waiver By Course of Conduct; Cumulative Remedies		8
Section 3.04. Enforcement Expenses; Indemnification		8
Section 3.05. Successors And Assigns		9
Section 3.06. Set-Off		9
Section 3.07. Counterparts		10
Section 3.08. Severability		10
Section 3.09. Section Headings		10
Section 3.10. Integration		10
Section 3.11. Governing Law		11
Section 3.12. Submission to Jurisdiction; Waivers		11
Section 3.13. Acknowledgements		11
Section 3.14. Releases		12
Section 3.15. WAIVER OF JURY TRIAL		12
Section 3.16. Sole Right of Enforcement; Demand Not Required		12

i

THIRD AMENDED AND RESTATED
SUBSIDIARY GUARANTEE AGREEMENT

     This THIRD AMENDED AND RESTATED SUBSIDIARY GUARANTEE AGREEMENT (this “Agreement”), dated as of November ___, 2007, made by each of the signatories hereto (each individually, a “Subsidiary Guarantor” and collectively, the “Subsidiary Guarantors”), in favor of JPMorgan Chase Bank, N.A. (“JPMCB”), as Collateral Agent (in such capacity, the “Collateral Agent”) for the ratable benefit of (i) the banks and other financial institutions or entities (the “Lenders”) from time to time parties to the Third Amended and Restated Credit Agreement, dated as of November ___, 2007 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among El Paso Corporation, a Delaware corporation (the “Company”), certain of its Subsidiaries as Pipeline Company Borrowers (the “Pipeline Company Borrowers”), the Lenders and JPMCB, as administrative agent and collateral agent thereunder, and (ii) the other Secured Parties (as defined in the Security Agreement identified below).

W I T N E S S E T H:

     WHEREAS, pursuant to the Credit Agreement, the Lenders have severally agreed to make extensions of credit to the Company and the Pipeline Company Borrowers, the Issuing Banks have agreed to issue Letters of Credit and the Administrative Agent and the Collateral Agent have agreed to serve in such capacities, in each case upon the terms and subject to the conditions set forth therein;

     WHEREAS, the Subsidiary Guarantors and the Collateral Agent on behalf of the Lenders and other Secured Parties have entered into that certain Amended and Restated Subsidiary Guarantee Agreement dated as of July 31, 2006 (the “Existing Subsidiary Guarantee Agreement”) with respect to the guarantees made by the Subsidiary Guarantors to the Collateral Agent;

     WHEREAS, the Company and the Pipeline Company Borrowers are members of an affiliated group of companies that includes each Subsidiary Guarantor (the “Affiliated Group”);

     WHEREAS, the Company, the Pipeline Company Borrowers and the Subsidiary Guarantors have entered into the Third Amended and Restated Security Agreement dated as of the date hereof (as amended, supplemented or otherwise modified from time to time, the “Security Agreement”) with the Collateral Agent and JPMCB, in its capacity as Depository Bank, pursuant to which, inter alia, the Company and the Subsidiary Guarantors have pledged certain property and assets as collateral to the Collateral Agent for the ratable benefit of the Secured Parties to secure the respective obligations of the Company and the Subsidiary Guarantors under the Credit Agreement and this Agreement; and

     WHEREAS, the proceeds of the extensions of credit made under the Credit Agreement may be used in part to enable the Borrowers to make valuable transfers to one or more of the Subsidiary Guarantors and the other Restricted Subsidiaries in connection with the operation of their respective businesses;

     WHEREAS, the Company, the Pipeline Company Borrowers, the Subsidiary Guarantors and the other Restricted Subsidiaries are engaged in related businesses, and each Subsidiary Guarantor will derive substantial direct and indirect benefit from the making and availability of the extensions of credit under the Credit Agreement; and

     WHEREAS, it is a condition precedent to the effectiveness of the Credit Agreement that the Subsidiary Guarantors shall have executed and delivered this Agreement to the Collateral Agent for the ratable benefit of the Secured Parties;

     NOW, THEREFORE, in consideration of the premises and to induce the Agents, the Issuing Banks and the Lenders to enter into the Credit Agreement, each Subsidiary Guarantor hereby agrees, jointly and severally, with the Collateral Agent, for the benefit of the Secured Parties that the Existing Subsidiary Guarantee Agreement shall be amended and restated in its entirety as follows:

ARTICLE 10
Defined Terms

     Section 10.01. Definitions. Unless otherwise defined herein, terms defined in the Credit Agreement and/or the Security Agreement are used herein as therein defined.

     The following terms have the following meanings:

     “Agreement” has the meaning set forth in the introductory paragraph hereof.

     “Company” has the meaning set forth in the introductory paragraph hereof.

     “Credit Agreement” has the meaning set forth in the introductory paragraph hereof.

     “Guarantee Release Date” has the meaning set forth in Section 2.01(d).

     “Guaranteed Obligations” means, with respect to each Subsidiary Guarantor, collectively, the payment obligations of the Company, the Pipeline Company Borrowers and each other Subsidiary Guarantor with respect to the Financing Documents to which such person is a party, in each case of whatsoever nature and howsoever evidenced, due or to become due, now existing or hereafter

2

arising, whether direct or indirect, absolute or contingent, which may arise under, out of or in connection with the obligations of the Company, the Pipeline Company Borrowers, or any other Subsidiary Guarantor (as applicable) under the Financing Documents and any amendment, restatement or modification of any of the foregoing, including, in each case to the extent owing by the Company, the Pipeline Company Borrowers, or any Subsidiary Guarantor, as the case may be, the full and punctual payment when due of any unpaid principal, interest (including interest accruing at any post-default rate and Post-Petition Interest), fees, reimbursement obligations, guaranty obligations, penalties, indemnities, legal and other fees, charges and expenses, and amounts advanced and expenses incurred in order to (x) preserve any Collateral or the Transaction Liens and (y) preserve any other property pledged to secure such obligations as collateral or the Liens and security interests with respect thereto, whether due at stated maturity or by acceleration or otherwise.

     “Indemnified Party” has the meaning set forth in Section 3.04(a).

     “Lenders” has the meaning set forth in the introductory paragraph hereof.

     “Maximum Liability” has the meaning set forth in Section 2.01(b).

     “Pipeline Company Borrowers” has the meaning set forth in the introductory paragraph hereof.

     “Security Agreement” has the meaning set forth in the recitals hereof.

     “Subsidiary Guarantors” has the meaning set forth in the introductory paragraph hereof.

     Section 10.02. Other Definitional Provisions. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (c) any reference herein to any Applicable Law means such Applicable Law as amended, modified, codified, replaced or reenacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder and reference to any section or other provision of any Applicable Law means that section or provision of such Applicable Law from time to time in effect and any amendment, modification codification, replacement,

3

or reenactment of such section or other provision, (d) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) all references herein to Articles, Sections, Exhibits, Appendices and Schedules shall be construed to refer to Articles and Sections of, and Exhibits, Appendices and Schedules to, this Agreement, (f) all references to “days” shall mean calendar days and (g) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, Equity Interests, accounts and contract rights. This Agreement is the result of negotiations among the parties hereto and their respective counsel. Accordingly, this Agreement shall be deemed the product of all parties hereto, and no ambiguity in this Agreement shall be construed in favor of or against any Credit Party or any Secured Party.

ARTICLE 11
Guarantee

     Section 11.01. Guarantee. (a) Each of the Subsidiary Guarantors hereby, jointly and severally, unconditionally and irrevocably, guarantees to the Collateral Agent, for the ratable benefit of the Secured Parties and their respective indorsees and transferees, the prompt and complete payment when due (whether at the stated maturity, by acceleration or otherwise) of the Guaranteed Obligations.

     (b) Each Subsidiary Guarantor, and by its acceptance of this Agreement and the rights hereunder or benefits hereof the Collateral Agent and each other Secured Party, hereby agrees and confirms that (i) it is the intention of all such Persons that this Agreement and the obligations of such Subsidiary Guarantor under this Article 2 not constitute a fraudulent transfer or conveyance for purposes of Bankruptcy Law (as defined below), the Uniform Fraudulent Conveyance Act (as adopted by any applicable state), the Uniform Fraudulent Transfer Act (as adopted by any applicable state) or any similar foreign, federal or state law to the extent applicable to this Agreement and the obligations of such Subsidiary Guarantor under this Article 2 and (ii) the aggregate liability of each Subsidiary Guarantor under this Article 2 and under the other Security Documents at any time (but after giving effect to the right of contribution described in Section 2.02) shall not exceed the maximum amount (as to any Subsidiary Guarantor, its “Maximum Liability”) that will result in the aggregate obligations of such Subsidiary Guarantor under this Article 2 and under the Security Documents not constituting a fraudulent transfer or conveyance under Bankruptcy Law or any of the other aforementioned acts and laws. For purposes hereof, “Bankruptcy Law” means the Bankruptcy Code, or any similar foreign, federal or state law for the relief of debtors.

     (c) Each Subsidiary Guarantor agrees that the Guaranteed Obligations may at any time and from time to time exceed the Maximum Liability of such Subsidiary Guarantor hereunder without impairing the guarantee contained in this

4

Article 2 or affecting the rights and remedies of the Collateral Agent or any Secured Party hereunder.

     (d) The guarantee contained in this Article 2 shall remain in full force and effect until the later (the “Guarantee Release Date”) of (i) the Final Payment Date and (ii) the date on which all payment obligations, if any, of each Subsidiary Guarantor in respect of the Guaranteed Obligations and the payment obligations, if any, under the guarantee contained in this Article 2 shall have been satisfied by indefeasible payment in full in cash.

     (e) No payment or payments made by the Company, any Pipeline Company Borrower, any of the Subsidiary Guarantors, any other guarantor or any other Person, or received or collected by the Collateral Agent or any Secured Party from the Company, any Pipeline Company Borrower, any of the Subsidiary Guarantors, any other guarantor or any other Person, by virtue of any action or proceeding or any set-off or appropriation or application at any time or from time to time in reduction of or in payment of Guaranteed Obligations shall be deemed to modify, reduce, release or otherwise affect the liability of any Subsidiary Guarantor under this Article 2 which shall, notwithstanding any such payment or payments (other than any payment or payments made by such Subsidiary Guarantor in respect of the Guaranteed Obligations or any payment received or collected from such Subsidiary Guarantor in respect of Guaranteed Obligations), remain liable for the Guaranteed Obligations up to the Maximum Liability of such Subsidiary Guarantor under this Article 2 until the Guarantee Release Date.

     Section 11.02. Right of Contribution. Each Subsidiary Guarantor hereby agrees that to the extent that a Subsidiary Guarantor shall have paid or be obligated to pay more than its proportionate share of any payment made hereunder, such Subsidiary Guarantor shall be entitled to contribution from and against any other Subsidiary Guarantor that has not paid its proportionate share of such payment. Each Subsidiary Guarantor’s right of contribution shall be subject to the terms and conditions of Section 2.03. The provisions of this Section 2.02 shall in no respect limit the obligations and liabilities of any Subsidiary Guarantor to the Collateral Agent and the Secured Parties, and each Subsidiary Guarantor shall remain liable to the Collateral Agent and the Secured Parties for the full amount guaranteed by such Subsidiary Guarantor hereunder.

     Section 11.03. No Subrogation. Notwithstanding any payment made by any Subsidiary Guarantor hereunder or any set-off or application of funds of any Subsidiary Guarantor by the Collateral Agent or any Secured Party, no Subsidiary Guarantor shall be entitled to be subrogated to any of the rights of the Collateral Agent or any Secured Party against the Company or any other Subsidiary Guarantor or any collateral security or guarantee or right of offset held by the Collateral Agent or any Secured Party for the payment of Guaranteed Obligations, nor shall any Subsidiary Guarantor seek or be entitled to seek any contribution or reimbursement from the Company or any other Subsidiary Guarantor in respect of payments made by such Subsidiary Guarantor hereunder, until the Guarantee

5

Release Date. If any amount shall be paid to any Subsidiary Guarantor on account of such subrogation rights prior to the Guarantee Release Date, such amount shall be held by such Subsidiary Guarantor in trust for the Collateral Agent and the Secured Parties, segregated from other funds of such Subsidiary Guarantor, and shall, forthwith upon receipt by such Subsidiary Guarantor, be turned over to the Collateral Agent in the exact form received by such Subsidiary Guarantor (duly indorsed by such Subsidiary Guarantor to the Collateral Agent, if required), to be applied against Guaranteed Obligations, whether matured or unmatured, in accordance with the terms and provisions of the Credit Agreement and Security Agreement.

     Section 11.04. Amendments, Etc. With Respect to the Guaranteed Obligations. Each Subsidiary Guarantor shall remain obligated under this Article 2 notwithstanding that, without any reservation of rights against such Subsidiary Guarantor and without notice to or further assent by such Subsidiary Guarantor, (a) any demand for payment of any of the Guaranteed Obligations made by the Collateral Agent or any other Secured Party may be rescinded by the Collateral Agent or any other Secured Party and any of the Guaranteed Obligations continued, (b) any Guaranteed Obligations, or the liability of any other Person upon or for any part thereof, or any collateral security or guarantee therefor or right of offset with respect thereto, may, from time to time, in whole or in part, be renewed, extended, amended, modified, accelerated, compromised, waived, surrendered or released by the Collateral Agent or any Secured Party, and (c) the Credit Agreement or the other Financing Documents and any other documents executed and delivered in connection therewith, in each case may be amended, modified, supplemented or terminated, in whole or in part, pursuant to the terms and conditions of each such applicable document from time to time, and any collateral security, guarantee or right of offset at any time held by the Collateral Agent or any other Secured Party for the payment of any Guaranteed Obligations may be sold, exchanged, waived, surrendered or released.

     Section 11.05. Guarantee Absolute And Unconditional. Each Subsidiary Guarantor waives any and all notice of the creation, renewal, extension or accrual of any of the Guaranteed Obligations and notice of or proof of reliance by the Collateral Agent or any other Secured Party upon the guarantee contained in this Article 2 or acceptance of the guarantee contained in this Article 2. Each Subsidiary Guarantor waives diligence, presentment, protest, demand for payment, notice of intent to accelerate, notice of acceleration and notice of default or nonpayment to or upon the Company, any Pipeline Company Borrower or any of the Subsidiary Guarantors with respect to Guaranteed Obligations. Each Subsidiary Guarantor understands and agrees that the guarantee contained in this Article 2 shall be construed as a continuing, absolute, irrevocable and unconditional guarantee of payment without regard to (a) the validity or enforceability or perfection of the Credit Agreement or any other Financing Document, any of the Guaranteed Obligations or any other collateral security therefor or guarantee or right of offset with respect thereto at any time or from time to time held by the Collateral Agent or any Secured Party, (b) any defense,

6

set-off or counterclaim whatsoever (other than a defense of payment or performance) which may at any time be available to or be asserted by the Company or any other Person against the Collateral Agent or any other Secured Party, or (c) any other circumstance whatsoever (with or without notice to or knowledge of the Company or such Subsidiary Guarantor or any other Credit Party), other than payment or performance, which constitutes, or might be construed to constitute, an equitable or legal discharge of the Company, any Pipeline Company Borrower or any other Subsidiary Guarantor for any of its respective portion of the Guaranteed Obligations or of such Subsidiary Guarantor under the guarantee contained in this Article 2, in bankruptcy or in any other instance. When making any demand hereunder or otherwise pursuing its rights and remedies hereunder against any Subsidiary Guarantor, the Collateral Agent may, but shall be under no obligation to, make a similar demand on or otherwise pursue such rights and remedies as it may have against the Company, any Pipeline Company Borrower, any other Subsidiary Guarantor or any other Person or against any collateral security or guarantee for the Guaranteed Obligations or any right of offset with respect thereto, and any failure by the Collateral Agent to make any such demand, to pursue such other rights or remedies or to collect any payments from the Company, any Pipeline Company Borrower, any other Subsidiary Guarantor or any other Person or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of the Company, any Pipeline Company Borrower, any other Subsidiary Guarantor or any other Person or any such collateral security, guarantee or right of offset, shall not relieve such Subsidiary Guarantor of any obligation or liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of the Collateral Agent against such Subsidiary Guarantor. For the purposes hereof “demand” shall include the commencement and continuance of any legal proceedings.

     Section 11.06. Reinstatement. The guarantee contained in this Article 2 shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Guaranteed Obligations is rescinded or must otherwise be restored or returned by the Collateral Agent or any Secured Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Company, any Pipeline Company Borrower, or any Subsidiary Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Company, any Pipeline Company Borrower, or any Subsidiary Guarantor or any substantial part of its property, or otherwise, all as though such payments had not been made.

     Section 11.07. Payments. Each Subsidiary Guarantor hereby agrees that payments required to be made by it hereunder will be paid to the Collateral Agent without set-off or counterclaim in dollars at the office of the Collateral Agent identified in Section 9.04 of the Security Agreement.

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ARTICLE 12
Miscellaneous

     Section 12.01. Amendments In Writing. None of the terms or provisions of this Agreement may be waived, amended, supplemented or otherwise modified except in accordance with Section 9.02 of the Security Agreement and Section 10.02 of the Credit Agreement.

     Section 12.02. Notices. All notices, requests and demands to or upon the Collateral Agent or any Subsidiary Guarantor hereunder shall be effected in the manner provided for in Section 9.04 of the Security Agreement.

     Section 12.03. No Waiver By Course of Conduct; Cumulative Remedies. Neither the Collateral Agent nor any other Secured Party shall by any act (except by a written instrument in accordance with Section 3.01), delay, indulgence, omission or otherwise be deemed to have waived any right or remedy hereunder or to have acquiesced in any Default. No failure to exercise, nor any delay in exercising, on the part of the Collateral Agent or any Secured Party, any right, power or privilege hereunder shall operate as a waiver thereof. No single or partial exercise of any right, power or privilege hereunder shall preclude any other or further exercise thereof or the exercise of any other right, power or privilege. A waiver by the Collateral Agent or any Secured Party of any right or remedy hereunder on any one occasion shall not be construed as a bar to any right or remedy which the Collateral Agent or any Secured Party would otherwise have on any future occasion. The rights and remedies herein provided are cumulative, may be exercised singly or concurrently and are not exclusive of any other rights or remedies provided by law.

     Section 12.04. Enforcement Expenses; Indemnification.

     (a) Each Subsidiary Guarantor (without duplication) agrees to indemnify, defend and save and hold harmless the Collateral Agent, each other Secured Party and each of their respective Affiliates and their respective officers, directors, employees, agents, advisors and trustees (each, an “Indemnified Party”) from and against, and (without duplication) shall pay, any and all claims, damages, losses, liabilities and expenses (including reasonable fees and expenses of counsel) that may be incurred by or asserted or awarded against any Indemnified Party, in each case arising out of or in connection with or as a result of the execution or delivery of this Agreement or the performance by the Subsidiary Guarantors of their respective obligations hereunder, except to the extent such claim, damage, loss, liability or expense is found in a final, nonappealable judgment by a court of competent jurisdiction to have resulted from, or to be attributable to, the gross negligence or willful misconduct of such Indemnified Party or its employees or agents.

     (b) Each Subsidiary Guarantor (without duplication) will pay to the Collateral Agent the amount of any and all reasonable out-of-pocket expenses,

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including the reasonable fees and expenses of its counsel and of any experts and agents, that the Collateral Agent may incur in connection with (i) the administration of this Agreement, (ii) the exercise or enforcement of any of the rights of the Collateral Agent or any other Secured Party hereunder or (iii) the failure by such Subsidiary Guarantor to perform or observe any of the provisions hereof required to be performed or observed by it.

     (c) Each Subsidiary Guarantor (without duplication) shall pay or reimburse the Collateral Agent for any transfer taxes or other taxes relating to or incurred in connection with this Agreement and shall indemnify and hold harmless the Collateral Agent and each other Secured Party from any amounts that it is obligated to pay in the way of such taxes.

     (d) Each Subsidiary Guarantor (without duplication) agrees to indemnify and hold harmless the Collateral Agent (in its agency capacity), and each other Secured Party from, and shall reimburse the Collateral Agent (in its agency capacity) and each other Secured Party for any present or future claim for liability for any stamp or other similar tax and any penalties or interest with respect thereto, which may be assessed, levied or collected by any jurisdiction in connection with this Agreement.

     (e) The indemnities and reimbursement provided by the Subsidiary Guarantors pursuant to this Agreement shall survive the expiration, cancellation, termination or modification of this Agreement, the resignation or removal of the Collateral Agent, and the provision of any subsequent or additional indemnity or any agreement to reimburse by any Person.

     (f) All amounts due under this Section 3.04 shall be payable not later than 30 days after the delivery of written demand to the applicable Subsidiary Guarantor therefor.

     Section 12.05. Successors And Assigns. This Agreement shall be binding upon the successors and assigns of each Subsidiary Guarantor and shall inure to the benefit of the Collateral Agent and its successors and assigns for the ratable benefit of the Secured Parties and their successors and assigns; provided that, except in connection with a transaction expressly permitted by Section 6.05 of the Credit Agreement, no Subsidiary Guarantor may assign, transfer or delegate any of its rights or obligations under this Agreement without the prior written consent of the Collateral Agent.

     Section 12.06. Set-Off. Each Subsidiary Guarantor hereby irrevocably authorizes the Collateral Agent and each Secured Party at any time and from time to time while an Event of Default shall have occurred and be continuing, without prior notice to such Subsidiary Guarantor or any other Subsidiary Guarantor, any such notice being expressly waived by each Subsidiary Guarantor, to set-off and appropriate and apply any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or

9

claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by the Collateral Agent or such Secured Party to or for the credit or the account of such Subsidiary Guarantor, or any part thereof in such amounts as the Collateral Agent or such Secured Party may elect, subject in all respects to the terms and provisions of the Credit Agreement, against and on account of the obligations and liabilities of such Subsidiary Guarantor to the Collateral Agent or such Secured Party hereunder or under the other Loan Documents and claims of every nature and description of the Collateral Agent or such Secured Party against such Subsidiary Guarantor, in any currency, whether arising hereunder, under the Credit Agreement or any other Loan Document, as the Collateral Agent or such Secured Party may elect, subject in all respects to the terms and provisions of the Credit Agreement, whether or not the Collateral Agent or such Secured Party has made any demand for payment and although such obligations, liabilities and claims may be contingent or unmatured. The Collateral Agent or the applicable Secured Party shall notify such Subsidiary Guarantor promptly of any such set-off and the application made by the Collateral Agent or such Secured Party of the proceeds thereof, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of the Collateral Agent and the Secured Parties under this Section 3.06 are in addition to other rights and remedies (including, without limitation, other rights of set-off) which the Collateral Agent and the Secured Party may have under Applicable Law pursuant to the terms and provisions of the Credit Agreement.

     Section 12.07. Counterparts. This Agreement may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by telecopier shall be effective as delivery of an original executed counterpart of this Agreement.

     Section 12.08. Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

     Section 12.09. Section Headings. The Section headings used in this Agreement are for convenience of reference only and are not to affect the construction hereof or be taken into consideration in the interpretation hereof.

     Section 12.10. Integration. This Agreement and the other Loan Documents to which each Subsidiary Guarantor is a party represent the agreement of such Subsidiary Guarantor, the Collateral Agent and the Secured Parties with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Collateral Agent or any

10

Secured Party relative to the subject matter hereof and thereof not expressly set forth or referred to herein or in such other Loan Documents.

     Section 12.11. Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

     Section 12.12. Submission to Jurisdiction; Waivers. Each Subsidiary Guarantor hereby irrevocably and unconditionally:

     (a) submits for itself and its property in any legal action or proceeding by the Collateral Agent against it relating to this Agreement and the other Loan Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non-exclusive general jurisdiction of the Supreme Court of the State of New York, sitting in New York County, the courts of the United States of America for the Southern District of New York, and appellate courts from any thereof;

     (b) consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

     (c) agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to such Subsidiary Guarantor at its address referred to in Section 3.02 or at such other address of which the Collateral Agent shall have been notified pursuant thereto;

     (d) agrees that nothing herein shall affect the right to effect service of process on it in any other manner permitted by law or shall limit the right to sue in any other jurisdiction; and

     (e) waives, to the maximum extent not prohibited by law, any right it may have to claim or recover in any legal action or proceeding referred to in this Section 3.12 any special, indirect, exemplary, punitive or consequential damages.

     Section 12.13. Acknowledgements. Each Subsidiary Guarantor hereby acknowledges that:

     (a) it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Loan Documents to which it is a party;

     (b) neither the Collateral Agent nor any Secured Party has any fiduciary relationship with or duty to such Subsidiary Guarantor arising out of or in connection with this Agreement or any of the other Loan Documents, and the relationship between the Subsidiary Guarantors, on the one hand, and the

11

Collateral Agent and the Secured Parties, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and

     (c) no joint venture is created hereby or by the other Loan Documents or otherwise exists by virtue of the transactions contemplated hereby among the Secured Parties or among the Subsidiary Guarantors and the Secured Parties.

     Section 12.14. Releases. (a) On the Guarantee Release Date this Agreement and all obligations (other than those expressly stated to survive such termination and in all cases subject to Section 2.06 hereof) of each Subsidiary Guarantor and any other party hereto shall terminate, all without delivery of any instrument or performance of any act by any Person. At the request and sole expense of the Company or any Subsidiary Guarantor following any such termination, the Collateral Agent shall promptly execute and deliver to the Company or such Subsidiary Guarantor, as the case may be, such agreements, instruments and other documents as such Subsidiary Guarantor shall reasonably request to evidence such termination.

     (b) On the date hereof, without further action by any party to this Agreement or the Existing Subsidiary Guarantee Agreement, each of the Released Parties shall cease to be a Subsidiary Guarantor under the Existing Subsidiary Guarantee Agreement, and shall not be deemed a Subsidiary Guarantor under this Agreement.

     Section 12.15. WAIVER OF JURY TRIAL. EACH PARTY TO THIS AGREEMENT HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT TO WHICH IT IS A PARTY AND FOR ANY COUNTERCLAIM THEREIN.

     Section 12.16. Sole Right of Enforcement; Demand Not Required. Notwithstanding any other provision of this Agreement, no Secured Party other than the Collateral Agent shall have the right to take any Enforcement Action with respect to this Agreement and all such Enforcement Actions shall be effected solely through the Collateral Agent. No reference in this Agreement to the Collateral Agent’s making a demand for payment under this Agreement shall be construed to mean that such a demand is required in order to cause any obligation under this Agreement to become due and payable, it being understood that obligations under this Agreement shall become due and payable as, and at such time as, provided in Section 2.01(a).

     [Remainder of Page Intentionally Left Blank]

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     IN WITNESS WHEREOF, each of the undersigned has caused this Amended and Restated Subsidiary Guarantee Agreement to be duly executed and delivered as of the date first above written.

SUBSIDIARY GUARANTORS:	EL PASO EPNG INVESTMENTS, L.L.C.
	By:
		Name: John Hopper
		Title: Vice President

EL PASO TENNESSEE PIPELINE CO.
By:
Name:	John Hopper
Title:	Vice President

EL PASO TGPC INVESTMENTS, L.L.C.
By:
Name:	John Hopper
Title:	Vice President

RELEASED PARTIES:	EL PASO CNG COMPANY, L.L.C.
	By:
		Name: John Hopper
		Title: Vice President

EL PASO NORIC INVESTMENTS III, L.L.C.
By:
Name:	John Hopper
Title:	Vice President

EPPP CIG GP HOLDINGS, L.L.C.
By:
Name:	John Hopper
Title:	Vice President

2

EXHIBIT F-1

FORM OF

OPINION OF BRACEWELL & GIULIANI LLP, SPECIAL NEW YORK COUNSEL TO
THE COMPANY

November ___, 2007

To the Administrative Agent and the Collateral Agent under the
Credit Agreement described below and to each Lender party to
such Credit Agreement

     Re: El Paso Corporation $1,500,000,000 Revolving Credit Facility

Ladies and Gentlemen:

     We have acted as special counsel for El Paso Corporation (“El Paso”), Tennessee Gas Pipeline Company and El Paso Natural Gas Company, each a Delaware corporation (collectively, the “Borrowers”), and El Paso EPNG Investments, L.L.C., a Delaware limited liability company, El Paso Tennessee Pipeline Co., a Delaware corporation, and El Paso TGPC Investments, L.L.C., a Delaware limited liability company (collectively, the “Subsidiary Guarantors” and together with the Borrowers, the “Opinion Parties”), in connection with the Third Amended and Restated Credit Agreement dated as of November ___, 2007 (the “Credit Agreement”) among the Borrowers, JPMorgan Chase Bank, N.A. (“JPMorgan”), as Administrative Agent (in such capacity, the “Administrative Agent”), JPMorgan, as Collateral Agent (in such capacity, the “Collateral Agent”) and the lenders party thereto (the “Lenders”). This opinion letter is delivered to you pursuant to Section 3.01(b)(vi) of the Credit Agreement.

     Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement. As used herein, (i) “Opinion Documents” means (A) the Credit Agreement, (B) the Subsidiary Guarantee Agreement, (C) the Security Agreement and (D) the UCC Financing Statements (as defined below), (ii) “New York UCC” means the Uniform Commercial Code as in effect in the State of New York, and (iii) “Applicable Law” means those laws, rules, and regulations of the State of New York and of the United States of America as in effect on the date hereof which in our experience are normally applicable to the Opinion Parties and to transactions of the type provided for in the Opinion Documents and of the Uniform Commercial Code as in effect in the State of Delaware (the “Delaware UCC”); provided, however, that Applicable Law does not include (i) except with respect to our opinions in paragraphs 4 and 5 below, any federal or state securities, commodities, insurance, or investment company laws and regulations; (ii) any federal or state labor, pension, or other employee benefit laws and regulations; (iii) any federal or state antitrust, trade or unfair competition laws and regulations; (iv) any federal or state laws and regulations relating to the environment, safety, health, or other similar matters; (v) building, zoning, land use and subdivision laws and regulations; (vi) any federal or state tax laws or regulations; and (vii) any federal or state laws or regulations relating to copyrights, patents, trademarks, or other intellectual property.

To the Administrative Agent and the Collateral Agent under the Credit Agreement
described below and to each Lender party to such Credit Agreement
November ___, 2007
Page 2

     In connection with the opinions expressed herein, we have examined such documents, records and matters of law as we have deemed necessary for the purposes of such opinions. We have examined an executed copy of the Opinion Documents.

     In all such examinations, we have assumed the legal capacity of all natural persons executing documents, the genuineness of all signatures, the authenticity of original and certified documents, and the conformity to original or certified copies of all copies submitted to us as conformed or reproduction copies. As to various questions of fact relevant to the opinions expressed herein, we have relied upon, and assumed the accuracy of, representations and warranties contained in the Opinion Documents and certificates and oral or written statements and other information of or from representatives of the Opinion Parties and others and assumed compliance on the part of the Opinion Parties with its covenants and agreements contained therein.

     Based upon the foregoing, and subject to the limitations, qualifications and assumptions set forth herein, we are of the opinion that:

     1. 1. Approvals; Other Required Actions. The execution and delivery by each of the Opinion Parties of each Opinion Document to which it is a party and the performance by each Opinion Party of its obligations thereunder, do not require under Applicable Law any filing or registration by such Opinion Party with, or notice to or approval, consent, authorization or order of, any Governmental Authority that has not been made or obtained, except those filings (a) required to perfect security interests, if any, granted by such Opinion Party thereunder, (b) those filings required pursuant to securities and other laws that may be applicable to the disposition of any collateral subject thereto, and (c) filings, registrations, consents or approvals in each case not required to be made or obtained by the date hereof.

     2. 2. Enforceability. Each Opinion Document constitutes a valid and binding agreement of each Opinion Party thereto, enforceable against such Opinion Party in accordance with its terms.

     3. 3. “No Violation.” The execution and delivery by each of the Opinion Parties of each Opinion Document to which it is a party and the performance of its obligations thereunder, do not violate or otherwise constitute a default under (a) any Applicable Law, (b) any provision of any other Opinion Document or (c) any of the agreements identified in the attached Schedule I; provided that we express no opinion with respect to any violation arising under or based upon any cross default provision insofar as it relates to a default under an agreement not identified to us, or arising under or based upon any covenant or other provision of a financial or numerical nature or requiring computation.

     4. 4. Margin Regulations. The borrowings by the Borrowers under the Credit Agreement and the application of the proceeds thereof as provided in the Credit Agreement will not violate Regulation U or X of the Board of Governors of the Federal Reserve System (the “Margin Regulations”).

2

To the Administrative Agent and the Collateral Agent under the Credit Agreement
described below and to each Lender party to such Credit Agreement
November ___, 2007
Page 3

     5. 5. Investment Company Act. No Opinion Party is required to register as an “investment company” (under, and as defined in, the Investment Company Act of 1940, as amended).

     6. 6. Creation of Security Interests. The provisions of the Security Agreement are effective to create in favor of the Collateral Agent to secure the obligations described therein, a valid security interest in all of the right, title and interests of El Paso and the Subsidiary Guarantors in and to the Collateral (as defined in the Security Agreement) to the extent that a security interest may be created under Article 9 of the Uniform Commercial Code as in effect in the State of New York (the “Article 9 Collateral”).

     7. 7. Central Filing Perfection. To the extent that the filing of a financing statement with the office of the Secretary of State of Delaware can be effective to perfect a security interest in the Article 9 Collateral under the Delaware UCC, the security interests in favor of the Collateral Agent in that portion of the Article 9 Collateral described in such financing statement will be perfected upon the filing of the financing statements attached as Exhibit A to this opinion (the “UCC Financing Statements”) in the office of the Secretary of State of the State of Delaware.

     8. 8. Delaware Filing. Once the UCC Financing Statements are filed as described in paragraph 7 above, no further or subsequent filing or refiling will be necessary in the State of Delaware in order to continue the perfection of the security interest referred to in paragraph 6 above except that (a) continuation statements with respect to the UCC Financing Statements must be filed under the Delaware UCC in the office where such statement was filed within six months prior to the expiration of five years from the date of such filing (or otherwise within the time permitted by Section 9-515 of the Delaware UCC), and subsequent continuation statements must be filed within six months prior to the end of each subsequent five-year period, and (b) amendments or supplements to the UCC Financing Statements or additional financing statements may be required to be filed in the event of a change in the name, identity, or structure of any debtor listed therein or in the event any such financing statement otherwise becomes inaccurate or incomplete.

     9. 9. Perfection of Security Interests in Certificated Securities. Assuming that the certificates representing the certificated securities (as defined in the New York UCC) constituting Article 9 Collateral, together with instruments of transfer or assignment in blank duly executed by an appropriate person, have been delivered on or prior to the date hereof to the Collateral Agent in the State of New York, the Collateral Agent has a perfected security interest in such certificated securities under the New York UCC.

     The opinions set forth above are subject to the following assumptions and qualifications, and with your permission, all of the following assumptions and statements of reliance have been made without any independent investigation or verification on our part except to the extent, if any, otherwise expressly stated, and we express no opinion with respect to the subject matter or accuracy of the assumptions or items upon which we have relied.

3

To the Administrative Agent and the Collateral Agent under the Credit Agreement
described below and to each Lender party to such Credit Agreement
November ___, 2007
Page 4

     (A) Our opinions are subject to (i) applicable bankruptcy, insolvency, reorganization, fraudulent transfer and conveyance, voidable preference, moratorium, receivership, conservatorship, arrangement or similar laws, and related regulations and judicial doctrines, affecting creditors’ rights and remedies generally, (ii) general principles of equity (including, without limitation, standards of materiality, good faith, fair dealing and reasonableness, equitable defenses, the exercise of judicial discretion and limits on the availability of equitable remedies), whether such principles are considered in a proceeding at law or in equity, and (iii) the qualification that certain provisions of the Opinion Documents may be unenforceable in whole or in part under the laws (including judicial decisions) of the State of New York or the United States of America, but the inclusion of such provisions does not affect the validity as against the Opinion Parties party thereto of the Opinion Documents as a whole and the Opinion Documents contain adequate provisions for the practical realization of the principal benefits provided by the Opinion Documents, in each case subject to the other qualifications contained in this letter.

     (B) Without limiting the generality of paragraph (A) above, we specifically express no opinion as to the validity or enforceability of any provision in the Opinion Documents:

     (i) providing that any person or entity may sell or otherwise dispose of, or purchase, any collateral subject thereto, or enforce any other right or remedy thereunder (including without limitation any self-help or taking-possession remedy), except in compliance with the New York UCC and other applicable laws;

     (ii) establishing standards for the performance of the obligations of good faith, diligence, reasonableness and care prescribed by the New York UCC or of any of the rights or duties referred to in Section 9-603 of the New York UCC;

     (iii) relating to indemnification, contribution, exculpation or release of liability in connection with violations of any securities laws or statutory duties or public policy, or in connection with willful, reckless or unlawful acts or gross negligence or strict liability of the indemnified, released or exculpated party or the party receiving contribution;

     (iv) providing that any person or entity may exercise set-off rights other than in accordance with and pursuant to applicable law;

     (vi) relating to choice of governing law to the extent that the enforceability of any such provision is to be determined by any court other than a court of the State of New York or may be subject to constitutional limitations;

     (vii) purporting to confer, or constituting an agreement with respect to, personal or subject matter jurisdiction of United States federal courts to adjudicate any matter;

     (viii) specifying that provisions may be waived only in writing, to the extent that an oral agreement or an implied agreement by trade practice or course of conduct has been created that modifies any provision of such Opinion Document;

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described below and to each Lender party to such Credit Agreement
November ___, 2007
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     (ix) giving any person or entity the power to accelerate obligations without any notice to the Opinion Parties;

     (x) providing that decisions by a party are conclusive or may be made in its sole discretion;

     (xi) purporting to create a power of attorney; or

     (xii) providing for restraints on alienation of property and purporting to render transfers of such property void and of no effect or prohibiting or restricting the assignment or transfer of property or rights to the extent that any such prohibition or restriction is ineffective pursuant to Sections 9-406 through 9-409 of the New York UCC.

     (C) Our opinions as to enforceability are subject to the effect of generally applicable rules of law that:

     (i) provide that forum selection clauses in contracts are not necessarily binding on the court(s) in the forum selected; and

     (ii) may, where less than all of a contract may be unenforceable, limit the enforceability of the balance of the contract to circumstances in which the unenforceable portion is not an essential part of the agreed exchange, or that permit a court to reserve to itself a decision as to whether any provision of any agreement is severable.

     (D) We express no opinion as to the enforceability of any purported waiver, release, variation, disclaimer, consent or other agreement to similar effect (all of the foregoing, collectively, a “Waiver”) by any Opinion Party under the Opinion Documents to the extent limited by Sections 9-602 or 9-624 of the New York UCC or to the extent ineffective under applicable law

     (E) We have assumed that each Opinion Party is a corporation or limited liability company, as the case may be, validly existing and in good standing in its jurisdiction of organization or formation, has all requisite power and authority, and has obtained all requisite corporate, and governmental authorizations, consents and approvals, and made all requisite filings and registrations, necessary to execute, deliver and perform each Opinion Document to which it is a party, and that such execution, delivery, and performance will not violate or conflict with any law, rule, regulation, order, decree, judgment, instrument or agreement binding upon or applicable to it or its properties (except to the extent noted in paragraph 3 above). To the extent it may be relevant to the opinions expressed herein, we have assumed that (i) the parties to the Opinion Documents have the power to enter into and perform such documents and to consummate the transactions contemplated thereby and that such documents have been duly authorized, executed and delivered by such parties, (ii) each Opinion Document constitutes legal, valid and binding obligations of the parties thereto (other than the Opinion Parties), and (iii) the execution and delivery of each Opinion Document by each of the parties thereto (other than the Opinion Parties to the extent expressly set forth in paragraph 3 above), and the performance of

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described below and to each Lender party to such Credit Agreement
November ___, 2007
Page 6

such party’s obligations thereunder, do not violate and will not violate or conflict with any law, rule, regulation, order, decree, judgment, instrument or agreement binding upon or applicable to it or its properties.

     (F) For purposes of our opinion in paragraph 4 above, we have assumed that (i) neither the Collateral Agent nor any Lender has or will have the benefit of any agreement or arrangement (excluding the Opinion Documents) pursuant to which any extensions of credit to the Borrowers are directly or indirectly secured by “margin stock” (as defined under the Margin Regulations), (ii) neither the Collateral Agent nor any Lender nor any of their respective affiliates has extended or will extend any other credit to the Borrowers directly or indirectly secured by margin stock and (iii) neither the Collateral Agent nor any Lender has relied and will rely upon any margin stock as collateral in extending or maintaining any extensions of credit pursuant to the Opinion Documents, as to which we express no opinion.

     (G) Our opinions are limited to those expressly set forth herein, and we express no opinions by implication.

     (H) We express no opinion as to the compliance or noncompliance, or the effect of the compliance or noncompliance, of each of the addressees or any other person or entity with any state or federal laws or regulations (including, without limitation, the policies, procedures, guidelines, and practices of any regulatory authority with respect thereto) applicable to each of them by reason of their status as or affiliation with a federally insured depository institution, a financial holding company, a bank holding company, a state-chartered non-federally insured depository institution, a securities dealer, an investment company or an insurance company, except as expressly set forth in paragraphs 4 and 5 above.

     (I) We express no opinion as to the validity, binding effect or enforceability of any provisions contained in the Loan Documents which: (i) purports to establish evidentiary standards; (ii) restricts access to courts or to legal or equitable remedies or purporting to affect jurisdiction or venue as to courts; (iii) relates to delay or omission of enforcement of remedies; (iv) entitles any party to the appointment of a receiver, to the extent contrary to applicable law; (v) purports to permit the Administrative Agent, the Collateral Agent or any Lender or any other person acting on behalf of the Administrative Agent, Collateral Agent or any Lender to purchase, sell or otherwise dispose of any property subject thereto except in compliance with applicable law; (vi) purports to provide standards for the care of property in possession of any person other than as provided by applicable law; (vii) purports to irrevocably appoint any person as attorney-in-fact for the Opinion Parties, or (viii) purports to permit the transfer of securities without compliance with applicable securities laws.

     (J) We have made no examination of and express no opinion with respect to (i) titles to or rights in or descriptions of the properties described in the Loan Documents, (ii) the priority of any security interest or whether there are of record any security interests, charges or encumbrances thereon, (iii) the creation, existence or perfection of any security interests purported to be created under the Loan Documents or the filing or recording of the Loan Documents or any financing statements or other instruments relating thereto except as set forth in

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described below and to each Lender party to such Credit Agreement
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paragraphs 6-9 hereof, or (iv) whether the properties described in the Security Agreement are the properties and interests intended to be encumbered thereby.

     (K) Our opinions in paragraphs 6-9 are limited to Articles 8 and 9 of the New York UCC and Article 9 of the Delaware UCC, and therefore such opinions do not address laws of jurisdictions other than New York and Delaware, except for Articles 8 and 9 of the New York UCC and Article 9 of the Delaware UCC.

     (L) We are qualified to practice law in the State of New York, and this opinion letter is limited in all respects to the Applicable Law; however, we are not members of the bar of the State of Delaware and our opinions as to any matters governed by the Delaware UCC are based solely upon our review of the Delaware UCC, without any review or consideration of any decisions or opinions of courts or other adjudicative bodies or governmental authorities of the State of Delaware.

     (M) Our opinions in paragraphs 6-9 are subject to the following assumptions, qualifications and limitations:

     (i) Insofar as any of the opinions herein expressed concern the perfection of a security interest in “proceeds” (as such term is defined in the Delaware UCC) please be advised that the continuation of the existence and perfection of such security interest are limited as provided in Section 9-315 of the Delaware UCC;

     (ii) We express no opinion as to the perfection of any security interest or other encumbrance (A) covering any asset to which the Delaware UCC or the New York UCC is not applicable or (B) covering property acquired by a debtor after the commencement of a case under the Federal Bankruptcy Code; and

     (iii) We assume that all filings will be timely made and duly filed as necessary for perfection (a) in the event of any change in the name, identity or corporate structure of El Paso or the Subsidiary Guarantors, (b) in the event of a change in the jurisdiction of formation of El Paso or the Subsidiary Guarantors, (c) in the event of a change in the location of the Collateral, if applicable, and (d) to continue and maintain the effectiveness of the original filings.

     (iv) We express no opinion as to the nature or extent of the rights, or the power to transfer rights, of any Opinion Party in, or title of El Paso or any Subsidiary Guarantor to, any collateral under any of the Opinion Documents, or property purporting to constitute such collateral, or the value, validity, enforceability or effectiveness for any purpose of any such collateral or purported collateral, and we have assumed that El Paso and each Subsidiary Guarantor has sufficient rights in, or power to transfer rights in, all such collateral or purported collateral for the security interests provided for under the Opinion Documents to attach.

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described below and to each Lender party to such Credit Agreement
November ___, 2007
Page 8

     (v) We express no opinion as to the priority of any pledge, security interest, assignment for security, lien or other encumbrance, as the case may be, that may be created or purported to be created under the Opinion Documents.

     (vi) In the case of property that becomes collateral under the Opinion Documents after the date hereof, Section 552 of the United States Bankruptcy Code limits the extent to which property acquired by a debtor after the commencement of a case under the United States Bankruptcy Code may be subject to a lien arising from a security agreement entered into by the debtor before the commencement of such case.

     (vii) We express no opinion as to the enforceability of the security interests under the Opinion Documents in any item of collateral subject to any restriction on or prohibition against transfer contained in or otherwise applicable to such item of collateral or any contract, agreement, license, permit, security, instrument or document constituting, evidencing or relating to such item, except to the extent that any such restriction is rendered ineffective pursuant to any of Sections 9-406 through 9-409, inclusive, of the New York UCC.

     (N) Insofar as our opinion in paragraph 2 above relates to the enforceability under New York law of the choice-of-law provision of the Opinion Documents choosing New York law as the governing law thereof, it is rendered in reliance upon the Act of July 19, 1984, ch. 421, 1984 McKinney’s Sess. Law of N.Y. 1406 (codified at N.Y. Gen. Oblig. Law §§ 5-1401, 5-1402 (McKinney 1989) and N.Y. CPLR 327(b) (McKinney 1990) (the “Act”). Furthermore, the application of New York law pursuant to the Act to a transaction that has no contact or only insignificant contact with the parties and the transaction may raise constitutional and comity issues. We direct your attention to Lehman Brothers Commercial Corporation v. Minmetals International Non-Ferrous Metals Trading Company, 2000 U.S. Dist. LEXIS 16445 (S.D.N.Y. 2000), in which the court analyzed the Act and noted that “[i]t remains to be seen, however, whether a state with no connection to either of the parties or the transactions could apply its own law, consonant with the Full Faith and Credit Clause [of the U.S. Constitution], when doing so would violate an important public policy of a more-interested state.”

     The opinions expressed herein are solely for the benefit of the addressees hereof in connection with the transaction referred to herein and may not be relied on by such addressees for any other purpose or in any manner or for any purpose by any other person or entity other than any Person that may become a Lender after the date hereof. This opinion letter is rendered as of the date set forth above. We expressly disclaim any obligation to update this letter after such date.

Very truly yours,

Bracewell & Giuliani LLP
 

8

SCHEDULE I

LIST OF MATERIAL AGREEMENTS
El PASO CORPORATION

     a. Indenture, dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee.

     (i) First Supplemental Indenture, dated as of April 4, 2007.

     b. Indenture, dated as of May 10, 1999, between El Paso Corporation (f/k/a El Paso Energy Corporation) and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by HSBC Bank USA).

     (i) First Supplemental Indenture dated as of May 10, 1999 ($500 Million 6.75% Senior Notes due May 15, 2009).

     (ii) Sixth Supplemental Indenture dated as of May 14, 2001 ($500 Million 7% Notes due May 15, 2011).

     (iii) Seventh Supplemental Indenture dated as of June 10, 2002 ($600 Million 7.875% Notes due June 15, 2012 (Private Placement)).

     (iv) Eighth Supplemental Indenture dated as of June 26, 2002 (up to $575 Million 6.14% Senior Notes due 8/16/07).

     (v) Ninth Supplemental Indenture dated as of July 1, 2005 (Remarked $272,102,350 of 6.14% Senior Note due August 16, 2007 issued pursuant to the Eight Supplemental Indenture dated June 26, 2002 (held as collateral for the Purchase Contract portion of the Equity Security Units) for $272,102,000 of 7.625% Senior Notes due August 16, 2007).

     (vi) Tenth Supplemental Indenture dated as of December 28, 2005 (10.75% Senior Notes due 2010, 9.625% Senior Notes due 2012, 7.75% Senior Notes due 2032, 7.42% due 2037, 6.95% Senior Notes due 2028, 6.375% Senior Notes due 2009, 7.75% Senior Notes due 2010, 6.50% Senior Notes due 2008, 7.625% Senior Notes due 2008, 6.50% Senior Notes due 2006, 6.70% Senior Notes due 2027, 7.50% Senior Notes due 2007).

     (vii) Eleventh Supplemental Indenture dated as of August 31, 2006 (for the issuance of up to $150,000,000 of 7.75% Medium Term Notes due 2032 or 2035, as applicable, to be exchanged for 7.75% Senior Notes due 2032 or 7.75% Senior Debentures due October 15, 2035).

     (viii) $300 Million 8.05% Global Medium Term Notes (Senior Fixed Rate Notes), due October 15, 2030, as described in the Pricing Supplement No. 1 dated October 5, 2000 to Supplemental Prospectus dated December 14, 1999 and Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (ix) $300 Million 7.375% Global Medium Term Notes (Senior Fixed Rate Notes), due December 15, 2012, as described in the Pricing Supplement No. 2 dated December 6, 2000 to Supplemental Prospectus dated December 14, 1999 and Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (x) $300 Million 6.95% Global Medium Term Notes (Senior Fixed Rate Notes), due December 15, 2007, as described in the Pricing Supplement No. 3 dated December 14, 2000, to Supplemental Prospectus dated December 13, 2000, to Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (xi) $700 Million 7.8% Global Medium Term Notes (Senior Fixed Rate Notes), due August 1, 2031, as described in the Pricing Supplement No. 01 dated July 25, 2001, to Supplemental Prospectus dated July 24, 2001, to Base Prospectus dated May 4, 2001, Registration No. 333-59704.

     (xii) $1,100 Million 7.75% Global Medium Term Notes (Senior Fixed Rate Notes), due January 15, 2032, as described in the Pricing Supplement No. 01 dated January 9, 2002 to Prospectus Supplement dated January 7, 2002, to Base Prospectus dated May 4, 2001.

     (xiii) Twelfth Supplemental Indenture dated as of June 18, 2007 ($375,000,000 6.875% Senior Notes due 2014, $900,000,000 7.000% Senior Notes due 2017).

     c. Indenture dated as of March 1, 1998 between El Paso Natural Gas Company (by assignment now El Paso Corporation) and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Law Debenture Trust Company).

     (i) First Supplemental Indenture dated as of March 17, 1998 ($334.75 Million 4.75% Convertible Subordinated Debentures due March 17, 2028, El Paso Energy Capital Trust I).

     (ii) Second Supplemental Indenture dated August 1, 1998 (the Holding Company formation transaction which authorized the merger of El Paso Natural Gas Company with El Paso Merger Company, with El Paso Natural Gas Company as the surviving corporation, and then El Paso Natural Gas Company stock was converted to into El Paso Energy Corporation (now El Paso Corporation) common stock and the debt was assumed by El Paso Corporation).

     (iii) Amended and Restated Declaration of Trust of El Paso Energy Capital Trust I, dated as of March 16, 1998, among El Paso Natural Gas Company, Chase Manhattan Bank, Chase Manhattan Bank Delaware and Administrative Trustees.

     d. Indenture, dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank).

     (i) First Supplemental Indenture dated as of June 10, 2002 ($300 Million 8.375% Notes due June 15, 2032).

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     (ii) Second Supplemental Indenture dated as of April 4, 2007 ($355 Million 5.95% Notes due April 15, 2017).

     e. Indenture, dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.).

     f. Indenture, dated as of June 1, 1986, between Sonat Inc. (by merger now El Paso Corporation) and Manufacturers Hanover Trust Company (by merger now JPMorgan Chase Bank and subsequently replaced by HSBC BANK USA).

     (i) First Supplemental Indenture dated as of June 1, 1995 (Various amendments).

     (ii) Second Supplemental Indenture dated as of October 25, 1999 (assumption of Sonat obligations under Indenture dated June 1, 1986).

     (iii) $100 Million 6.75% Notes due October 1, 2007, as described in the Prospectus Supplement dated September 25, 1997 to Prospectus dated July 27, 1993.

     (iv) $100 Million 6.625% Notes due February 1, 2008, as described in the Prospectus Supplement dated January 27, 1998 to Prospectus dated July 27, 1993.

     (v) $100 Million 7% Notes due February 1, 2018, as described in the Prospectus Supplement dated January 29, 1998 to Prospectus dated July 27, 1993.

     (vi) $600 Million 7.625% Notes due July 15, 2011, as described in the Prospectus Supplement dated July 7, 1999 to Prospectus dated September 9, 1998.

     g. Indenture, dated as of March 30, 1992, between Valero Energy Corporation (by merger PG&E Gas Transmission, Texas Corporation, then El Paso Gas Transmission Company (“GTT”) and now El Paso Corporation) and Bankers Trust Company (by merger now Deutsche Bank Trust Company Americas).

     (i) First Supplemental Indenture dated as of March 13, 1995 (authorized the issuance of $284 Million in Medium-Term Notes, various interest rates and maturities, 9 months to 30 years).

     (ii) Second Supplemental Indenture dated as of March 11, 2002 (conform Indenture dated March 30, 1992 to El Paso Corporation May 10, 1999 Indenture).

     (iii) Third Supplemental Indenture dated as of April 5, 2002 (merged GTT into El Paso Corporation).

     h. Indenture, dated as of October 1, 1990 between El Paso CGP Company, L.L.C. (f/k/a El Paso CGP Company and The Coastal Corporation) and The Bank of New York Trust Company, N.A. (f/k/a The Bank of New York) ($150 Million 10.75% Senior Debentures due October 1, 2010).

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     (i) First Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso CGP Company, L.L.C. October 1, 1990 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (ii) Second Supplemental Indenture, dated as of December 31, 2005 among El Paso CGP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso CGP Company, L.L.C., assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso CGP Company, L.L.C.).

     i. Indenture, dated as of May 15, 1992 between El Paso CGP Company, L.L.C. (f/k/a El Paso CGP Company and The Coastal Corporation) and Bank of Montreal Trust Company (subsequently replaced by The Bank of New York Trust Company, N.A.).

     (i) First Supplemental Indenture, dated as of May 20, 1992 ($150 Million 9.625% Senior Debentures due May 15, 2012).

     (ii) Second Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso COP Company, L.L.C. May 15, 1992 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (iii) Third Supplemental Indenture, dated as of December 31, 2005 among El Paso COP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso COP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso COP Company, L.L.C.).

     j. Indenture, dated as of September 15, 1992 between El Paso COP Company, L.L.C. (f/k/a El Paso COP Company and The Coastal Corporation) and NationsBank, N.A. (subsequently replaced by The Bank of New York Trust Company, RA.).

     (i) Second Supplemental Indenture dated as of October 19, 1995 ($150 Million 7.75% Senior Debentures due October 15, 2035).

     (ii) Third Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso COP Company, L.L.C. September 15, 1992 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (iii) Fourth Supplemental Indenture, dated as of December 31, 2005 among El Paso COP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso COP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso COP Company, L.L.C.).

     k. Indenture, dated as of February 24, 1997 between El Paso COP Company, L.L.C. (f/k/a El Paso COP Company and The Coastal Corporation) and Harris Trust and Savings Bank (subsequently replaced by The Bank of New York Trust Company, N.A.).

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     (i) First Supplemental Indenture dated as of February 24, 1997 ($200 Million 6.70% Senior Debentures due February 15, 2027, put date February 15, 2007).

     (ii) Second Supplemental Indenture dated as of February 24, 1997 ($200 Million 7.42% Senior Debentures due February 15, 2037).

     (iii) Third Supplemental Indenture dated as of June 5, 1998 ($200 Million 6.5% Senior Debentures due June 1, 2008).

     (iv) Fourth Supplemental Indenture dated as of June 5, 1998 ($200 Million 6.95% Senior Debentures due June 1, 2028).

     (v) Fifth Supplemental Indenture dated as of February 10, 1999 ($200 Million 6.375% Senior Debentures due February 1, 2009).

     (vi) Eighth Supplemental Indenture dated as of June 16, 2000 ($400 Million 7.75% Notes due June 15, 2010).

     (vii) Eleventh Supplemental Indenture dated as of September 6, 2000 ($215 Million 7.625% Notes due 9/1/08).

     (viii) Twelfth Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso CGP Company, L.L.C. February 24, 1997 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (ix) Thirteenth Supplemental Indenture, dated as of December 31, 2005 among El Paso CGP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso CGP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso CGP Company, L.L.C.).

     l. Indenture, dated as of March 4, 1997, between Tennessee Gas Pipeline Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank).

     (i) First Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.5% Debentures due April 1, 2017).

     (ii) Second Supplemental Indenture dated as of March 13, 1997 ($300 Million 7% Debentures due March 15, 2027).

     (iii) Third Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.625% Debentures due April 1, 2037).

     (iv) Fourth Supplemental Indenture dated as of October 9, 1998 ($400 Million 7% Debentures due October 15, 2028).

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     (v) Fifth Supplemental Indenture dated June 10, 2002 ($240 Million 8.375% Senior Notes due June 15, 2032).

     m. Indenture, dated as of March 15, 1988, between Tenneco, Inc. (now El Paso Tennessee Pipeline Co.) and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company).

     (i) Second Supplemental Indenture dated as of March 30, 1988 ($250 Million 10% Debentures due March 15, 2008, outstanding balance $26.4 Million).

     (ii) Tenth Supplemental Indenture dated as of November 15, 1992 ($150 Million 9% Debentures due November 15, 2012, outstanding principal $1.1 Million).

     (iii) Twelfth Supplemental Indenture dated as of December 15, 1995 ($300 Million 7.25% Debentures due December 15, 2025, outstanding principal $23.2 Million).

     (iv) Thirteenth Supplemental Indenture dated as of December 10, 1996.

     n. Indenture, dated as of December 15, 1981, between Tenneco Inc. (now Tennessee Gas Pipeline Company) and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company) ($400 Million 6% Debentures due December 15, 2011, current balance $85.8 Million).

     (i) First Supplemental Indenture dated as of December 10, 1996.

     (ii) Second Supplemental Indenture dated as of December 10, 1996.

     o. Fiscal Agency Agreement dated May 6, 2002 among El Paso Corporation, Citibank, N.A. and Societe Generale Bank and Trust, 6 S.A. relating to €500 Million 7.125% Euro Notes due May 6, 2009.

     p. Credit Agreement dated as of June 20, 2007, among El Paso Corporation, the Lenders party thereto, Citicorp USA, Inc., as Administrative Agent and as Issuing Agent, and the Bank of New York as Paying Agent.

     (i) The Reimbursement Agreement dated as of June 20, 2007, between El Paso Corporation and Citibank, N. A.

     (ii) Credit Agreement First Amendment dated as of August 28, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (iii) Credit Agreement Second Amendment dated as of September 6, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (iv) Credit Agreement Third Amendment dated as of September 17 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

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     (v) Credit Agreement Fourth Amendment dated as of September 20, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (vi) Credit Agreement Fifth Amendment dated as of September 28, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (vii) Credit Agreement Sixth Amendment dated as of October 3, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (viii) Credit Agreement Seventh Amendment dated as of October 11, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (ix) Credit Agreement Eighth Amendment dated as of October 18, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     q. Other Credit and Facility Agreements

     (i) Discretionary Facility Agreement dated as of February 21, 2003, between El Paso Corporation and Compass Bank.

     (ii) Credit Agreement dated July 19, 2006 among El Paso Corporation and Deutsche Bank AG New York Branch as Initial Lender and Issuing Bank and Deutsche Bank AG New York Branch as Administrative Agent and Collateral Agent.

     (iii) First Tier Receivables Sale Agreement dated August 31, 2006, between Tennessee Gas Pipeline Company and TGP Finance Company, L.L.C.

     (iv) Second Tier Receivables Sale Agreement dated August 31, 2006, between TGP Finance Company, L.L.C. and TGP Funding Company, L.L.C.

     (v) Receivables Purchase Agreement dated August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, Starbird Funding Corporation, the other investors from time to time parties thereto, BNP Paribas, New York Branch, and the other Managing Agents from time to time parties thereto.

     (a) Amendment No 1, dated as of December 1, 2006, to the Receivables Purchase Agreement dated as of August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, Starbird Funding Corporation and the other funding entities from time to time party thereto, BNP Paribas, New York Branch, and the other financial institutions from time to time party thereto.

     (vi) Facility Agreement dated as of January 4, 2007, between El Paso Corporation and Morgan Stanley Capital Services Inc.

     r. Letters of Credit with a Face Amount Exceeding $50,000,000

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     (i) Application and Agreement for irrevocable Standby Letter of Credit, dated as of December 15, 2004, by El Paso Corporation to JPMorgan Chase Bank, N.A., in favor of Midland Cogeneration Venture Limited Partnership for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $110 Million 100 Thousand.

     (ii) Application for Irrevocable Standby Letter of Credit, dated as of July 29, 2006 by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Midland Cogeneration Venture Limited Partnership for the account of El Paso Merchant Energy, L.P. for the aggregate amount not exceeding $74 Million.

     (iii) Application for Irrevocable Standby Letter of Credit, dated as of September 1, 2005, by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Williams Power Company for the account of El Paso Merchant Energy, L.P. for the aggregate amount not exceeding $219 Million 900 Thousand.

     (iv) Application for Standby Letter of Credit, dated as of November 10, 2006, by El Paso Corporation to BNP Paribas in favor of Southeast Supply Header, LLC for the account of Southern Natural Gas Company in the amount of $60 Million.

     (v) Application for Standby Letter of credit, dated as of July 19, 2006, by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. in the amount of $184 Million.

     (vi) Application for Irrevocable Standby Application for Irrevocable Standby Letter of Credit, dated as of February 6, 2007, by El Paso Corporation to Fortis Bank S.A./N.V., in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $162 Million 100 Thousand.

     (vii) Application for Irrevocable Standby Letter of Credit, dated as of September 24, 2003, by El Paso Corporation to JPMorgan Chase Bank, N.A., in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $85 Million 750 Thousand.

     s. ISDA Master Agreements

     (i) 1992 ISDA Master Agreement dated October 24, 2001, between El Paso Corporation and Credit Suisse First Boston International.

     (ii) 1992 ISDA Master Agreement dated March 5, 2001, between El Paso Corporation and Westdeutsche Landesbank Girozentrale.

     (iii) 2002 ISDA Master Agreement dated August 29, 2003 between El Paso Corporation and Citibank, N.A.

     (iv) 2002 ISDA Master Agreement dated June 24, 2004, between El Paso Corporation and Deutsche Bank A.G.

-8-

     (v) 2002 ISDA Master Agreement dated November 22, 2004, between El Paso Corporation and Citigroup Financial Products Inc.

     t. Various Guaranties and Other Documents

     (i) Guaranty Agreements dated as of July 12, 2005 and December 13, 2006, by El Paso Corporation in favor of Mt. Franklin Insurance Ltd.

     (ii) Guaranty Agreement dated as of February 15, 2006, by El Paso Corporation in favor of Coastal Offshore Insurance Ltd.

     (iii) Guaranty Agreement dated as of April 25, 2006 by El Paso Corporation in favor of Petroleo Brasileiro S.A. — Petrobas.

     (iv) Terms of 4.99% Convertible Perpetual Preferred Stock, pursuant to the Offering Memorandum dated as of April 11, 2005 by El Paso Corporation.

-9-

EXHIBIT A

(Financing Statements Attached)

Third Amended and Restated Credit Agreement

EXHIBIT F-2

FORM OF

OPINION OF GENERAL COUNSEL OR ASSOCIATE GENERAL COUNSEL TO THE
COMPANY

[LETTERHEAD OF EL PASO CORPORATION]
November __, 2007

To the Administrative Agent and the Collateral Agent under the
Credit Agreement described below and to each
Lender party to such Credit Agreement

     Re: Credit Agreement dated as of November ___, 2007

Ladies/Gentlemen:

     This opinion letter is furnished to you in connection with the Third Amended and Restated Credit Agreement, dated as of November ___, 2007 (the “Credit Agreement”), among E1 Paso Corporation, a Delaware corporation (the “Company”), Tennessee Gas Pipeline Company, a Delaware corporation (“TGPC”), and El Paso Natural Gas Company, a Delaware corporation (together with the Company and TGPC, the “Borrowers”), JPMorgan Chase Bank, N.A. (“JPMorgan”), as Administrative Agent (in such capacity, the “Administrative Agent”), JPMorgan, as Collateral Agent (in such capacity, the “Collateral Agent”) and the lenders party thereto (the “Lenders”). Unless the context otherwise requires, all capitalized terms used but not defined herein have the meanings assigned to such terms in the Credit Agreement.

     I am Executive Vice President and General Counsel of the Company, and I, or attorneys under my supervision and direction, have acted as counsel for the Borrowers and for El Paso EPNG Investments, L.L.C., a Delaware limited liability company, El Paso Tennessee Pipeline Co., a Delaware corporation, and El Paso TGPC Investments, L.L.C., a Delaware limited liability company (each, a “Subsidiary Guarantor”, and collectively, the “Subsidiary Guarantors” and together with the Borrowers, the “Opinion Parties”) in connection with the preparation, execution and delivery of the Credit Agreement and the other Opinion Documents (hereinafter defined).

     In that connection, I, or attorneys under my supervision and direction, have examined:

(1)	an executed counterpart of the Credit Agreement;
(2)	an executed counterpart of the Subsidiary Guarantee Agreement;
(3)	an executed counterpart of the Security Agreement (collectively with the Credit Agreement and the Subsidiary Guarantee Agreement, the “Opinion Documents”);

Third Amended and Restated Credit Agreement

Exhibit F-2 – Page 1

(4)	(a) true and correct copies of the certificate of incorporation or certificate of formation, as the case may be, and by-laws or limited liability company agreements, as the case may be, as amended to date, of each Opinion Party and (b) a copy of the certificate of good standing of each Opinion Party, dated as of a recent date, issued by the Secretary of State of the State of Delaware; and
(5)	other documents furnished to me by the Opinion Parties pursuant to or in connection with the Opinion Documents.

     I, or attorneys under my supervision and direction, have also examined the originals, or copies, certified or otherwise identified to our satisfaction, of the agreements, instruments and other documents, and all of the orders, writs, judgments, awards, injunctions and decrees, which affect or purport to affect each Opinion Party’s ability to enter into and to perform its obligations under the Opinion Documents. In addition, I, or attorneys under my supervision and direction, have examined the originals, or copies certified or otherwise identified to our satisfaction, of such other corporate records of the Opinion Parties, certificates of public officials and of officers of the Opinion Parties, and such other agreements, instruments and other documents, as I have deemed necessary or appropriate as a basis for the opinions hereinafter expressed. In all such examinations, I, or such attorneys under my supervision and direction, have assumed the legal capacity of all natural persons executing agreements and documents, the genuineness of all signatures on original, certified or reproduction copies of agreements and documents of all parties (other than, with respect to the Opinion Documents, the Opinion Parties), the authenticity of original and certified documents and the conformity to original or certified copies of all copies submitted to such attorneys or me as conformed or reproduction copies. As to various questions of fact relevant to the opinions expressed herein, I have relied upon, and assumed the accuracy of, representations and warranties contained in the Opinion Documents and certificates and oral or written statements and other information of or from public officials, officers and/or representatives of the Opinion Parties and others.

     I have assumed that the parties to the Opinion Documents (other than the Opinion Parties) have the power to enter into and perform such documents and that each such document has been duly authorized, executed and delivered by the parties thereto (other than the Opinion Parties), and constitutes the valid and binding obligation of each party thereto.

     The opinions expressed below are limited to the Federal laws of the United States and, to the extent relevant hereto, the General Corporation Law of the State of Delaware and the Delaware Limited Liability Company Act, each as currently in effect. I assume no obligation to supplement this opinion if any applicable laws change after the date hereof or if I become aware of any facts that might change the opinions expressed herein after the date hereof.

     Based on the foregoing and upon such investigation as I, or attorneys under my supervision and direction, have deemed necessary, and subject to the limitations, qualifications and assumptions set forth herein, I am of the following opinion:

(1) Each Opinion Party (i) is a corporation duly incorporated or a limited liability company duly formed, as the case may be, and validly existing in good standing under the laws of the State of Delaware and (ii) possesses all the corporate or

Third Amended and Restated Credit Agreement

Exhibit F-2 – Page 2

limited liability company, as applicable, powers and all other authorizations and licenses necessary to engage in its business and operations as now conducted, which the failure to obtain or maintain would have a Material Adverse Effect.

(2) The execution, delivery, and performance by each Opinion Party of each Opinion Document to which it is a party:

(a)	are within each Opinion Party’s corporate or limited liability company, as applicable, powers and have been duly authorized by all necessary corporate or limited liability company, as applicable, action of or by such Opinion Party;
(b)	do not and will not contravene the Opinion Party’s certificate of incorporation and by-laws or certificate of formation and limited liability company agreement, as the case may be, as amended to date;
(c)	do not and will not contravene any U.S. federal law or regulation applicable to the Opinion Parties (excluding provisions of U.S. federal law expressly referred to in and covered by the opinion of Bracewell & Giuliani LLP dated the date hereof and delivered to you in connection with the transactions contemplated hereby) or any provision of the General Corporation Law of the State of Delaware or the Delaware Limited Liability Company Act applicable to the Opinion Parties.

(3)

Each Opinion Document has been duly executed and delivered by each Opinion Party to it.

(4)

No authorization or approval or other action by, and no notice to or filing with, any U.S. federal governmental authority or regulatory body (including, without limitation, the Federal Energy Regulatory Commission), or any Delaware governmental authority or regulatory body pursuant to the General Corporation Law of the State of Delaware or the Delaware Limited Liability Company Act, is required for the due execution, delivery and performance by each Opinion Party of any Opinion Document to which it is a party, except for:

(a)	authorizations, approvals and other actions that have been obtained or taken and notices and filings that have been made, in each case that are in full force and effect; and
(b)	authorizations, approvals, other actions, notices and filings required in the ordinary course of business in connection with the performance by each Opinion Party of its obligations under certain covenants and warranties contained in the Opinion Documents to which it is a party and pursuant to securities and other laws that may be applicable to the disposition of any collateral subject thereto.

(5) To the best of my knowledge, there is no action, suit or proceeding pending or overtly threatened against or involving the Opinion Parties (a) that, in my

Third Amended and Restated Credit Agreement

Exhibit F-2 – Page 3

judgment (taking into account the exhaustion of all appeals), would have a Material Adverse Effect (provided that this opinion does not address any actions, suits, or proceedings that have been disclosed in the annual report on Form 10-K for the fiscal year ended December 31, 2006, or the quarterly report on Form 10-Q for the quarter ended June 30, 2007, filed by the Borrowers with the Securities and Exchange Commission or (b) that purports to affect the legality, validity, binding effect or enforceability of the Opinion Documents.

(6)

The Initial Pledged Equity identified on Schedule II to the Security Agreement has (to the extent applicable) been duly authorized and validly issued and is fully paid and non-assessable.

     The opinions expressed herein are given as of the date hereof. The opinions expressed herein are limited solely to those expressly set forth herein, and I express no opinions by implication. The opinions expressed herein are solely for the benefit of the addressees hereof and any other person or entity becoming an Administrative Agent, a Collateral Agent or Lender under the Credit Agreement in accordance therewith, and any participant of any Lender in accordance with the Credit Agreement, in each case above, in connection with the transactions referred to herein and may not be relied on by such addressees for any other purpose or in any manner or for any purpose by any other person or entity without my prior written consent.

Very truly yours,

Third Amended and Restated Credit Agreement

Exhibit F-2 – Page 4

EXHIBIT G

ACCEPTABLE SUBORDINATION PROVISIONS

     [NAME OF BORROWER], a [Delaware] corporation (together with its successors, the “Borrower”), and [NAME OF LENDER], a [Delaware] corporation (together with its successors, “Lender”), agree for the benefit of the Senior Debt (as defined below) that all indebtedness evidenced by this [PROMISSORY NOTE] (this “Note”), including principal, premium, if any, and interest, and all other amounts payable to Lender hereunder (including, for all purposes of this Note, any payment in respect of redemption or purchase or other acquisition hereof) (collectively, the “Subordinated Debt”) shall, to the extent hereinafter set forth, be subordinate and junior to all Senior Debt.

     Unless and until all principal of, premium, if any, and interest on, and all other obligations of the Borrower under, any Senior Debt shall have been paid in full and all commitments to extend Senior Debt shall have terminated, neither the Borrower nor any of its Subsidiaries or Affiliates shall make, and Lender shall not demand, accept or receive, or attempt to collect or commence any legal proceedings to collect, any direct or indirect payment (in cash or property or by setoff, exercise of contractual or statutory rights or otherwise) of or on account of any amount payable on or with respect to this Note (including any payment in respect of redemption or purchase or other acquisition) or any interest herein. Unless and until all principal of, premium, if any, and interest on, and all other obligations of the Borrower under, the Senior Debt shall have been paid in full and all commitments to extend Senior Debt shall have terminated, Lender will not commence or maintain any action, suit or any other legal or equitable proceeding against the Borrower, or join with any creditor in any such proceeding, under any insolvency, bankruptcy, receivership, liquidation, reorganization or other similar law, unless the holders of Senior Debt shall also join in bringing such proceeding; provided that the foregoing shall not prohibit Lender from filing a proof of claim or otherwise participating in any such proceeding not commenced by it.

     In the event of any insolvency or bankruptcy proceedings, and any receivership, liquidation, reorganization or other similar proceedings in connection therewith, relative to the Borrower or to its creditors, in their capacity as creditors of the Borrower, or to substantially all of its property, and in the event of any proceedings for voluntary liquidation, dissolution or other winding up of the Borrower, whether or not involving insolvency or bankruptcy, then:

     (a) the holders of the Senior Debt shall first be entitled to receive payment in full of the principal thereof, premium, if any, interest and all other amounts payable thereon (accruing before and after the commencement of the proceedings, whether or not allowed or allowable as a claim in such proceedings) before Lender is entitled to receive any payment on account or in respect of Subordinated Debt; and

     (b) any payment or distribution of assets of the Borrower of any kind or character, whether in cash, property or securities to which Lender would be entitled, but for the provisions of this Note, shall be paid or distributed by the liquidating trustee or agent or other person making such

Third Amended and Restated Credit Agreement

Exhibit G – Page 1

payment or distribution, whether a trustee in bankruptcy, a receiver or liquidating trustee or other trustee or agent, directly to the Agent (as defined below) and any other representative on behalf of the holders of Senior Debt to the extent necessary to make payment in full of all amounts of Senior Debt remaining unpaid, after giving effect to any concurrent payment or distribution to the holders of the Senior Debt.

     Should any payment or distribution or security or the proceeds of any thereof be collected or received by Lender in respect of the Subordinated Debt, at a time when the payment thereof by the Borrower is prohibited by the terms of this Note, Lender will forthwith deliver the same to the Agent and any other representative on behalf of the holders of Senior Debt for the equal and ratable benefit of the holders of the Senior Debt in precisely the form received (except for the endorsement or the assignment of or by Lender where necessary) for application to payment of all Senior Debt in full, after giving effect to any concurrent payment or distribution to the holders of Senior Debt and, until so delivered, the same shall be held in trust by Lender as the property of the holders of the Senior Debt.

     Lender shall not be subrogated to the rights of the holders of the Senior Debt to receive payments or distributions of assets of the Borrower until all amounts payable with respect to the Senior Debt shall be paid in full; and, for the purposes of such subrogation, no payments or distributions to the holders of the Senior Debt of any cash, property or securities to which Lender would be entitled except for these provisions shall, as between the Borrower, its creditors other than the holders of the Senior Debt, and Lender, be deemed to be a payment by the Borrower to or on account of the Senior Debt. The subordination provisions of this Note are and are intended solely for the purpose of defining the relative rights of Lender, on the one hand, and the holders of the Senior Debt, on the other hand.

     Subject to the payment in full of all of the Senior Debt, Lender shall be subrogated to the rights of the holders of Senior Debt to receive payments or distributions of cash, property or securities of the Borrower applicable to the Senior Debt until all amounts owing on the Subordinated Debt shall be paid in full. For purposes of such subrogation, no payments or distributions to Lender of cash, property, securities or other assets by virtue of the subrogation herein provided which otherwise would have been made to the holders of the Senior Debt shall, as between the Borrower, its creditors other than the holders of Senior Debt and Lender, be deemed to be a payment to or on account of the Subordinated Debt. Lender agrees that, in the event that all or any part of any payment made on account of the Senior Debt is recovered from the holders of Senior Debt as a preference, fraudulent transfer or similar payment under any bankruptcy, insolvency or similar law, any payment or distribution received by Lender on account of the Subordinated Debt at any time after the date of the payment so recovered, whether pursuant to the right of subrogation provided for in this Subordinated Note or otherwise, shall be deemed to have been received by Lender in trust as the property of the holders of the Senior Debt and Lender shall forthwith deliver the same to the Agent and any other representative on behalf of the holders of the Senior Debt for the equal and ratable benefit of the holders of the Senior Debt for application to payment of all Senior Debt in full.

Third Amended and Restated Credit Agreement

Exhibit G

     Lender hereby waives any and all notice in respect of the Senior Debt, present or future, and agrees and consents that without notice to or assent by any holder or holders of the Subordinated Debt:

     (i) the obligation and liabilities of the Borrower or any other party or parties for or upon the Senior Debt (or any promissory note, security document or guaranty evidencing or securing the same) may, from time to time, in whole or in part, be renewed, extended, modified, amended, restated, accelerated, compromised, supplemented, terminated, sold, exchanged, waived or released;

     (ii) the Agent and the holders of the Senior Debt may exercise or refrain from exercising any right, remedy or power granted by or in connection with any agreements relating to the Senior Debt; and

     (iii) any balance or balances of funds with any holders of the Senior Debt at any time standing to the credit of the Borrower may, from time to time, in whole or in part, be surrendered or released;

     all as the Agent or the holders of the Senior Debt may deem advisable and all without impairing, abridging, diminishing, releasing or affecting the subordination of the Subordinated Debt to the Senior Debt provided for herein.

     Nothing contained in the subordination provisions of this Note is intended to or shall impair, as between the Borrower, its creditors other than the holders of the Senior Debt, and Lender, the obligation of the Borrower, which is absolute and unconditional, to pay to Lender the principal of, premium, if any, and interest on this Note, as and when the same shall become due and payable (except as otherwise provided in this Note) in accordance with its terms, or is intended to or shall affect the relative rights of Lender and other creditors of the Borrower other than the holders of the Senior Debt.

     Lender acknowledges and agrees that the holders of the Senior Debt have relied upon and will continue to rely upon the subordination provided for herein in entering into the agreements relating to Senior Debt and in extending credit to the Borrower pursuant thereto.

     No present or future holder of Senior Debt shall be prejudiced in his right to enforce the subordination contained herein in accordance with the terms hereof by any act or failure to act on the part of the Borrower or Lender. The subordination provisions contained herein are for the benefit of the holders of the Senior Debt from time to time and, so long as any Senior Debt is outstanding under any agreement, may not be rescinded, cancelled or modified in any way without the prior written consent thereto of all holders of Senior Debt.

     Notwithstanding anything to the contrary in this Note, upon any payment or distribution of assets of the Borrower in any proceedings for reorganization, insolvency, liquidation, dissolution or other winding up, Lender shall be entitled to rely upon any final order or decree made by any court of competent jurisdiction in which any such proceedings are pending for the purpose of ascertaining the persons entitled to participate in such payment or distribution, the holders of the

Third Amended and Restated Credit Agreement

Exhibit G

Senior Debt and other debt of the Borrower, the amount thereof or payable thereon, the amount or amounts paid or distributed thereon and all other facts pertinent thereto.

     The subordination provisions hereof shall be binding upon any holder of Subordinated Debt and upon the successors and assigns of Lender; and all references herein to Lender shall be deemed to include any successor or successors, whether immediate or remote, to Lender.

     The following terms, as used herein, have the following respective meanings:

     “Agent” means (i) so long as the Credit Agreement is in effect, JPMorgan Chase Bank, N.A., in its capacity as Administrative Agent for the Lenders party to the Credit Agreement or any successor or other Administrative Agent appointed pursuant to the Credit Agreement and (ii) if there is no Credit Agreement in effect, thereafter any agent designated as representative of holders of all other Senior Debt.

     “Credit Agreement” means the Third Amended and Restated Credit Agreement dated as of November 16, 2007 among El Paso Corporation, certain of its subsidiaries as Pipeline Company Borrowers, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, as the same may be amended, restated, modified, extended or supplemented from time to time in accordance with its terms and any successor financial institution credit agreement refinancing all or a portion of the Credit Agreement and designated by the Borrower as the “Credit Agreement” for purposes hereof.

     “Senior Debt” means (a) all principal of, premium and interest (including, without limitation, any interest (“Post-Petition Interest”) which accrues (or which would accrue but for such case, proceeding or other action) after the commencement of any case, proceeding or other action relating to the bankruptcy, insolvency or reorganization of the Borrower (whether or not such interest is allowed or allowable as a claim in such case, proceeding or other action)) on any loan or reimbursement or other obligation under, and all notes issued pursuant to, the Credit Agreement or any other Financing Document, (b) any renewals, refinancings or extensions of any of the foregoing (or any portion thereof) (including Post-Petition Interest) and (c) all fees, expenses, indemnities and other amounts payable by the Borrower thereunder or with respect thereto.

     Other capitalized terms used but not defined herein have the meanings assigned to such terms in the Credit Agreement.

Third Amended and Restated Credit Agreement

Exhibit G

EX-10.W

EXHIBIT 10.W

EXECUTION VERSION

THIRD AMENDED AND RESTATED SECURITY AGREEMENT

dated as of November 16, 2007

among

EL PASO CORPORATION,

THE PERSONS REFERRED TO HEREIN AS
PIPELINE COMPANY BORROWERS,

THE PERSONS REFERRED TO HEREIN AS SUBSIDIARY GRANTORS

and

JPMORGAN CHASE BANK, N.A.,
as Collateral Agent and Depository Bank

TABLE OF CONTENTS

	Page
ARTICLE 1
Definitions And Interpretation
Section 1.01. Definitions		2
Section 1.02. Principles of Interpretation		7
ARTICLE 2
[Reserved]
ARTICLE 3
Representations And Warranties
Section 3.01. Representations and Warranties of the Credit Parties		8
ARTICLE 4
Pledged Accounts
Section 4.01. Creation of Pledged Accounts		10
Section 4.02. Cash Collateral Account		12
Section 4.03. Qualified Investments Account		12
Section 4.04. Payments in Trust		15
Section 4.05. Investment of Funds in Pledged Accounts		15
Section 4.06. Transfers from Accounts During the Continuance of an Event of Default		17
Section 4.07. Reports, Certification and Instructions		17
Section 4.08. Depository Bank Undertakings		18
Section 4.09. Force Majeure		20
Section 4.10. Clearing Agency		20
Section 4.11. Return of Funds to the Company		20
ARTICLE 5
Security Interests
Section 5.01. Grant of Security Interests		21
Section 5.02. Security for Obligations		24
Section 5.03. Delivery and Control of Collateral		24
Section 5.04. Further Assurances; Etc		25
Section 5.05. Grantors Remain Liable		26
Section 5.06. Additional Equity Interests		26

i 

	Page
Section 5.07. Release of Collateral		27
Section 5.08. Voting Rights, Dividends, Payments, Etc		28
Section 5.09. The Collateral Agent Appointed Attorney-in-Fact		30
Section 5.10. Netting of Accounts		31
ARTICLE 6
Remedies and Enforcement
Section 6.01. Remedies and Enforcement		31
Section 6.02. Application of Proceeds		33
Section 6.03. Other Remedies of Secured Parties		34
ARTICLE 7
Depository Bank
Section 7.01. Depository Bank		34
ARTICLE 8
[reserved]
ARTICLE 9
Miscellaneous
Section 9.01. Indemnity and Expenses		35
Section 9.02. Amendments; Waivers, Etc		36
Section 9.03. Security Interest Absolute and Waivers		36
Section 9.04. Notices; Etc		38
Section 9.05. Continuing Security Interest; Assignments		39
Section 9.06. [Reserved]		39
Section 9.07. Execution in Counterparts		40
Section 9.08. Severability		40
Section 9.09. Integration		40
Section 9.10. No Partnership		40
Section 9.11. No Reliance		40
Section 9.12. Release		40
Section 9.13. No Impairment		40
Section 9.14. Equitable Remedies		40
Section 9.15. Remedies		41
Section 9.16. Limitations		41
Section 9.17. Survival		41
Section 9.18. [Reserved]		42
Section 9.19. Jurisdiction, Etc		42
Section 9.20. GOVERNING LAW		42
Section 9.21. Waiver of Jury Trial		42

ii 

SCHEDULES

Schedule I	Subsidiary Grantors
Schedule II	Initial Pledged Equity
Schedule III	Name, Location, Chief Executive Office, Type of Organization, Jurisdiction of Organization and Organizational Identification Number
Schedule IV	Changes in Name, Location, Etc.
Schedule V	Secured Hedging Agreements
Schedule VI	Material Agreements of El Paso Corporation

EXHIBITS

Exhibit A Form of Officer’s Certificate for Qualified Investments

iii 

THIRD AMENDED AND RESTATED SECURITY AGREEMENT

     THIRD AMENDED AND RESTATED SECURITY AGREEMENT, dated as of November 16, 2007, made by and among:

     EL PASO CORPORATION, a Delaware corporation (the “Company”);

     EL PASO NATURAL GAS COMPANY, a Delaware corporation (“EPNGC”), TENNESSEE GAS PIPELINE COMPANY, a Delaware corporation (“TGPC”) (EPNGC and TGPC, collectively, the “Pipeline Company Borrowers” and, together with the Company, the “Borrowers”);

     Each of the Persons listed on Schedule I hereto as a Subsidiary Grantor (collectively, the “Subsidiary Grantors” and, together with the Company, the “Grantors”) (the Borrowers and the Subsidiary Grantors are sometimes referred to herein, collectively, as the “Credit Parties”; and the Credit Parties, together with the other Restricted Subsidiaries, are sometimes referred to herein, collectively, as the “Credit Related Parties”);

     JPMorgan Chase Bank, N.A. (“JPMCB”), not in its individual capacity but solely as collateral agent for the Secured Parties (solely in such capacity, the “Collateral Agent”); and

     JPMCB, not in its individual capacity but solely in its capacity as the Depository Bank (solely in such capacity, the “Depository Bank”).

PRELIMINARY STATEMENTS

     (1) Certain of the parties hereto are party to a Third Amended and Restated Credit Agreement dated as of the date hereof (the “Credit Agreement”) pursuant to which the Lenders have agreed to make Loans to the Borrowers and participate in Letters of Credit, the Issuing Banks have agreed to issue Letters of Credit for the account of the Borrowers, and the Administrative Agent and the Collateral Agent have agreed to serve in such capacities.

     (2) The Credit Parties, the Depository Bank, the Collateral Agent (on behalf of the Lenders, the Issuing Banks, the Agents and the other Secured Parties) and certain other parties have heretofore entered into that certain Amended and Restated Security Agreement dated as of July 31, 2006 (the “Existing Security Agreement”) with respect to their respective rights in respect of the Collateral and certain other matters related to the Financing Documents.

     NOW, THEREFORE, to secure the Secured Obligations, and in consideration of the premises and to induce each of the Lenders, the Issuing Banks and the Agents to enter into the Credit Agreement and for good and valuable consideration, the receipt and sufficiency of which are hereby

acknowledged, each of the Credit Parties and the Collateral Agent (on behalf of the Lenders, the Issuing Banks, the Agents and the other Secured Parties) agrees that the Existing Security Agreement shall be amended and restated in its entirety as follows:

ARTICLE 1
Definitions And Interpretation

     Section 1.01. Definitions. (a) Capitalized terms used but not defined herein shall have the respective meanings assigned to such terms in the Credit Agreement.

     (b) As used in this Agreement, the following terms have the meanings specified below:

     “Account Collateral” has the meaning set forth in Section 5.01(d).

     “Agreement” means this Security Agreement.

     “Applicable Law” means, with respect to any Person, any and all laws, statutes, regulations, rules, orders, injunctions, decrees, writs, determinations, awards and judgments issued by any Governmental Authority applicable to such Person.

     “Bankruptcy Code” means the Federal Bankruptcy Reform Act of 1978, as amended from time to time (11 U.S.C. §101, et seq.).

     “Borrowers” has the meaning set forth in the Preamble.

     “Cash Collateral Account” has the meaning set forth in Section 4.01(a)(ii).

     “Clearing Agency” has the meaning set forth in Section 4.10.

     “Collateral” means the Account Collateral, the Security Collateral, the Payment Collateral and all other property or assets with respect to which a Security Document executed by a Grantor creates or grants, or states that it creates or grants, a Transaction Lien.

     “Collateral Account” has the meaning set forth in Section 4.01(a)(i).

     “Collateral Agent” has the meaning set forth in the Preamble.

     “Company” has the meaning set forth in the Preamble.

2

     “Company Payment Collateral” has the meaning set forth in Section 5.01(c).

     “Credit Agreement” has the meaning set forth in the Preamble.

     “Credit Parties” has the meaning set forth in the Preamble.

     “Credit Related Parties” has the meaning set forth in the Preamble.

     “Depository Bank” has the meaning set forth in the Preamble.

     “Enforcement Action” means the taking of any or all of the following actions:

     (a) applying funds in the Pledged Accounts (including by charging or exercising any contractual or legal setoff rights) to the payment of the Secured Obligations;

     (b) making any demand for, or receiving any, payment under the Subsidiary Guarantee Agreement;

     (c) taking any Foreclosure Action or exercising any other power of sale or similar other rights or remedies under any of the Security Documents;

     (d) proceeding to protect and enforce the rights of the Secured Parties under this Agreement or any other Security Document by sale of the Collateral pursuant to judicial proceedings or by a proceeding in equity or at law or otherwise, whether for the enforcement of any Transaction Lien or for the enforcement of any other legal, equitable or other remedy available under this Agreement, any other Security Document or Applicable Law;

     (e) exercising any of the rights and remedies of a secured party with respect to the Collateral upon default under the Uniform Commercial Code as in effect in any applicable jurisdiction; and

     (f) exercising any other right or remedy provided in this Agreement or otherwise available to the Collateral Agent, to the extent permitted by Applicable Law.

     “Enforcement Proceeds” means any cash, securities or other consideration received from time to time by the Collateral Agent as a result of the taking of any Enforcement Action in accordance with the Security Documents and Applicable Law, including, without limitation (a) any balances then outstanding in the Pledged Accounts or received therein from time to time thereafter, including any Net Cash Proceeds then held in any Pledged Account,

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(b) the proceeds of any Disposition or other Enforcement Action taken pursuant to Article 6, and (c) proceeds of any Foreclosure Action or judicial or other non-judicial proceeding.

     “EPNGC” has the meaning set forth in the Preamble.

     “Excluded Payment Property” means any property of a Grantor of the type described in (and not excluded from) Section 5.01(b)(i) through (iv), to the extent that the grant of a security interest therein or a Lien thereon would result in (i) a breach of or a default under a provision which is not rendered ineffective by the UCC contained in any agreement in existence on the Effective Date to which the Company or any Subsidiary of the Company is a party (other than (x) an agreement listed on Schedule VI hereto or (y) an agreement that can be amended solely by the Company and/or one or more of its Subsidiaries), or (ii) a mandatory prepayment obligation under any such agreement, or allow any party to any such agreement (other than the Company or any Subsidiary of the Company) to accelerate obligations due thereunder, terminate any material contract right thereunder or exercise any put or call right, right of refusal, purchase option or similar right thereunder.

     “Excluded Subsidiary Grantor Assets” has the meaning set forth in Section 5.01(b).

     “Federal Book Entry Regulations” means (a) the federal regulations contained in Subpart B (“Treasury/Reserve Automated Debt Entry System (TRADES)”) governing book-entry securities consisting of U.S. Treasury bonds, notes and bills and Subpart D of 31 C.F.R. Part 357, 31 C.F.R. § 357.2, § 357.10 through § 357.14 and § 357.41 through § 357.44 and (b) to the extent substantially identical to the federal regulations referred to in clause (a) above (as in effect from time to time), the federal regulations governing other book-entry securities.

     “Financing Documents” means the Loan Documents and the Secured Hedging Agreements.

     “Foreclosure Action” means the sale, transfer or other Disposition by the Collateral Agent of all or any part of the Collateral at any public or private sale at such place and at such time as the Collateral Agent shall determine and in compliance with Applicable Law.

     “Grantors” has the meaning set forth in the Preamble.

     “Indemnified Party” has the meaning set forth in Section 9.01(a).

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     “Initial Pledged Equity” means, with respect to any Grantor, the Equity Interests set forth opposite such Grantor’s name on and as otherwise described in Schedule II and issued by the Persons named therein.

     “Insolvency Proceeding” means, with respect to any Person, that (a) such Person shall (i) admit in writing its inability to pay its debts generally, or shall fail to pay its debts generally as they become due; or (ii) make a general assignment for the benefit of creditors; or (b) any proceeding shall be instituted or consented to by such Person seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, or other similar official for it or for any substantial part of its property; or (c) any such proceeding shall have been instituted against such Person and either such proceeding shall not be stayed or dismissed for 60 consecutive days or any of the actions referred to above sought in such proceeding (including the entry of an order for relief against it or the appointment of a receiver, trustee, custodian or other similar official for it or any substantial part of its property) shall occur; or (d) such Person shall take any corporate (or other Business Entity) action to authorize any of the actions set forth above in this definition.

     “JPMCB” has the meaning set forth in the Preamble.

     “Officer’s Certificate” means, with respect to any Person, a certificate substantially in the form of Exhibit A hereto, signed by the president, any vice-president, the treasurer or the chief financial officer of such Person.

     “Payment Collateral” has the meaning set forth in Section 5.01(c).

     “Pipeline Company Borrowers” has the meaning set forth in the Preamble.

     “Pledged Accounts” has the meaning set forth in Section 4.01(a).

     “Pledged Company” means any issuer of the Initial Pledged Equity or any successor entity to any such issuer; provided that, if all of the Equity Interests issued by a Pledged Company and pledged by a Grantor to the Collateral Agent hereunder are released from the Transaction Liens in accordance with the terms of this Agreement and the Credit Agreement, then from and after such release, such issuer shall no longer be a Pledged Company.

     “Pledged Equity” has the meaning set forth in Section 5.01(a)(ii).

     “Pledged Financial Assets” means all financial assets credited from time to time to the Pledged Accounts.

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     “Pledged Security Entitlement” means all security entitlements with respect to the Pledged Financial Assets.

     “Qualified Investments Account” has the meaning set forth in Section 4.01(a)(iii).

     “Remaining Reinvestment Amount” has the meaning set forth in Section 4.03(c).

     “Secured Hedging Agreement” means any Hedging Agreement that (i) was entered into by any Borrower with a Person which was at the time such Hedging Agreement was entered into a Lender or an Affiliate of a Lender and (ii) either (A) is listed on Schedule V hereto or (B) has been designated as a Secured Hedging Agreement by the Company in a certificate signed by a Financial Officer delivered to the Collateral Agent and the Administrative Agent which (I) identifies such Hedging Agreement, including the name and address of the other party thereto (which must be a Lender or an Affiliate of a Lender at the time of such designation), the notional amount thereof and the expiration or termination date thereof, and (II) states that the applicable Borrower’s obligations thereunder shall from and after the date of delivery of such certificate be Secured Obligations for purposes hereof and of the other Security Documents.

     “Secured Obligations” means, with respect to each Grantor, the obligations, including all “Obligations” (as defined in the Credit Agreement) and all “Guaranteed Obligations” (as defined in the Subsidiary Guarantee Agreement) of such Grantor, under (a) the Credit Agreement and/or the Subsidiary Guarantee Agreement, as applicable, (b) this Agreement, (c) any other Loan Document to which such Grantor is a party, (d) any Secured Hedging Agreement to which such Grantor is a party and (e) any agreement relating to the refinancing of the obligations referred to in the foregoing clauses (a) through (d), and in the case of each of clauses (a) through (e) including interest accruing at any post-default rate and Post-Petition Interest.

     “Secured Parties” means, collectively, the Lenders, the Issuing Banks, the Administrative Agent, the Collateral Agent, each counterparty to a Secured Hedging Agreement and each other Person that is a holder of any Secured Obligations.

     “Security Collateral” has the meaning set forth in Section 5.01(a).

     “Subsidiary Grantor Payment Collateral” has the meaning set forth in Section 5.01(b).

     “Subsidiary Grantors” has the meaning set forth in the Preamble.

     “TGPC” has the meaning set forth in the Preamble.

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     “UCC” means the Uniform Commercial Code as in effect from time to time in the State of New York; provided that, if perfection or the effect of perfection or non-perfection or the priority of any Transaction Liens on any Collateral is governed by the Uniform Commercial Code as in effect in a jurisdiction other than New York, “UCC” means the Uniform Commercial Code as in effect from time to time in such other jurisdiction for purposes of the provisions hereof relating to such perfection, effect of perfection or non-perfection or priority.

     “Unused Cash Collateral” has the meaning set forth in Section 4.02(c).

     (c) Terms defined in Article 8 or 9 of the UCC and/or in the Federal Book Entry Regulations are used in this Agreement as such terms are defined in such Article 8 or 9 and/or the Federal Book Entry Regulations.

     Section 1.02. Principles of Interpretation. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (b) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (c) any reference herein to any Applicable Law means such Applicable Law as amended, modified, codified, replaced, or reenacted, in whole or in part, and in effect from time to time, including rules and regulations promulgated thereunder and reference to any section or other provision of any Applicable Law means that section or provision of such Applicable Law from time to time in effect and any amendment, modification, codification, replacement, or reenactment of such section or other provision, (d) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement and (f) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, Equity Interests, accounts and contract rights, and (g) all references to “days” shall mean calendar days. This Agreement is the result of negotiations among the parties thereto and their respective counsel. Accordingly, this Agreement shall be deemed the product of all parties thereto, and no ambiguity in this Agreement shall be construed in favor of or against any Credit Party or any Secured Party.

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ARTICLE 2
[Reserved]

ARTICLE 3
Representations And Warranties

     Section 3.01. Representations and Warranties of the Credit Parties. Each Credit Party, with respect to itself and its Subsidiaries, represents and warrants to the Collateral Agent, for the benefit of the Secured Parties, that:

     (a) With respect to any Credit Party that is a Grantor: (i) such Credit Party’s exact legal name is correctly set forth in Schedule III, (ii) such Credit Party is located (within the meaning of Section 9-307 of the UCC) and has its chief executive office, in the state or jurisdiction set forth in Schedule III, (iii) the information set forth in Schedule III with respect to such Credit Party is true and accurate in all respects and (iv) such Credit Party has not, within the last five years, changed its legal name, location, chief executive office, type of organization, jurisdiction of organization or organizational identification number from those set forth in Schedule III, except as disclosed in Schedule IV.

     (b) Such Credit Party is duly organized or formed, validly existing and, if applicable, in good standing in its jurisdiction of organization or formation. Such Credit Party possesses all applicable Business Entity powers and all other authorizations and licenses necessary to engage in its business and operations as now conducted, the failure to obtain or maintain which would have a Material Adverse Effect.

     (c) The execution, delivery and performance by such Credit Party of the Security Documents to which it is a party are within such Credit Party’s applicable Business Entity powers, have been duly authorized by all necessary applicable Business Entity action, and do not contravene (i) such Credit Party’s organizational documents or (ii) any material contractual restriction binding on or affecting such Credit Party.

     (d) No authorization or approval or other action by, and no notice to or filing with, any Governmental Authority is required for the due execution, delivery and performance by such Credit Party of any Security Document to which it is a party, except those necessary to comply (i) with Applicable Laws in the ordinary course of such Credit Party’s business or (ii) with ongoing obligations of such Credit Party under the Security Documents to which it is a party and Sections 5.01, 5.02 and 5.07 of the Credit Agreement.

     (e) This Agreement constitutes, and the other Security Documents when delivered shall constitute, the legal, valid and binding obligations of each Credit Party that is a party thereto, enforceable against such Credit Party in accordance

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with their respective terms, except as may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally or by general principles of equity.

     (f) With respect to any Credit Party that is a Grantor, all Collateral pledged by such Credit Party hereunder consisting of certificated securities has been delivered to the Collateral Agent.

     (g) With respect to any Credit Party that is a Grantor, this Agreement is effective to create in favor of the Collateral Agent, for the ratable benefit of the Secured Parties, a Lien on, and security interest in, all right, title and interest of such Grantor in the Collateral pledged by such Credit Party hereunder as security for the Secured Obligations, prior and superior in right to any other Lien (except for Collateral Permitted Liens), except in each case above as may be limited by any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally. All financing statements have been filed that are necessary to perfect any Transaction Lien that can be perfected by the filing of such financing statements. All actions required by Section 5.03 to provide control to the Collateral Agent with respect to Collateral pledged by such Credit Party hereunder for which control can be established have been taken, including delivery of such Collateral consisting of certificated securities to the Collateral Agent, duly endorsed for transfer or accompanied by duly executed instruments of transfer.

     (h) With respect to any Credit Party that is a Grantor, the Pledged Equity pledged as Collateral by such Credit Party to the Collateral Agent hereunder has (to the extent applicable) been duly authorized and validly issued and is (to the extent applicable) fully paid and non-assessable. With respect to any Equity Interests pledged by such Credit Party to the Collateral Agent hereunder that are uncertificated securities, such Credit Party has caused the issuer thereof to agree in an authenticated record with such Credit Party and the Collateral Agent that such issuer will comply with instructions with respect to such uncertificated securities originated by the Collateral Agent without further consent of such Credit Party and has delivered a copy of such authenticated record to the Collateral Agent. If such Credit Party is a Pledged Company, such Credit Party confirms that it has received notice of such security interest.

     (i) With respect to any Credit Party that is a Grantor, the Initial Pledged Equity as set forth on Schedule II (as such schedule may be amended or supplemented from time to time) pledged as Collateral by such Credit Party to the Collateral Agent hereunder constitutes 100% of the issued and outstanding Equity Interests of each issuer thereof.

All representations and warranties made by the Credit Parties herein, and in any other Security Document delivered pursuant hereto, shall survive the execution and delivery by the Credit Parties of the Security Documents. The Credit Parties

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shall deliver to the Collateral Agent amended and restated schedules (the “Amended Schedules”) to this Agreement in the event that any information contained on the schedules attached hereto becomes inaccurate. Such Amended Schedules shall replace the schedules provided by the Credit Parties on the Effective Date, and shall be deemed the schedules to this Agreement. Each Credit Party will not change its name, identity, corporate structure (including, without limitation, its jurisdiction of formation) or the location of its registered office without (i) giving the Collateral Agent at least 10 Business Days’ prior written notice clearly describing such new name, identity, corporate structure or new location and providing such other information in connection therewith as the Collateral Agent may reasonably request, and (ii) taking all action satisfactory to the Collateral Agent at the expense of such Credit Party as the Collateral Agent may request to maintain the security interest of the Collateral Agent in the Collateral intended to be granted hereby at all times fully perfected with the same priority and in full force and effect.

ARTICLE 4
Pledged Accounts

     Section 4.01. Creation of Pledged Accounts. (a) The Collateral Agent is hereby directed by the Company and each Grantor to cause to be established on or before the date hereof with, and maintained thereafter by, the Depository Bank at its offices in New York City, New York (ABA No. 021000021), in the name of the Collateral Agent as entitlement holder and under the sole control and dominion of the Collateral Agent and subject to the terms of this Agreement, the following segregated securities accounts (collectively, the “Pledged Accounts”):

     (i) a master collateral account, Account No. 10205184 (the “Collateral Account”), into which Mandatory Asset Reduction Amounts will be deposited and to which Unused Cash Collateral and certain amounts described in Section 4.03(f) will be transferred;

     (ii) a cash collateral account, Account No. 10205185 (the “Cash Collateral Account”), into which certain amounts will be deposited in respect of Letters of Credit; and

     (iii) an account, Account No. 10205186 (the “Qualified Investments Account”), from which the Company, on behalf of the Restricted Subsidiaries, may direct the Collateral Agent to direct the Depository Bank to pay funds to the Company to make Qualified Investments as permitted under the Loan Documents.

     (b) Commencing with the date hereof and continuing until the termination of the Transaction Liens in accordance with Section 5.07(b), each Pledged Account shall be established and maintained by the Depository Bank as a

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securities account or as a deposit account at its offices in New York City, New York, in the name of and under the sole dominion and control of the Collateral Agent; provided that the Cash Collateral Account may be terminated at such time as: (i) all Letters of Credit shall have expired or been paid, settled, satisfied, released, or otherwise terminated, (ii) all LC Disbursements shall have been reimbursed, (iii) all LC Commitments and all commitments of the Lenders to participate in Letters of Credit shall have been terminated and (iv) all amounts on deposit in the Cash Collateral Account shall have been transferred to the Collateral Account as Unused Cash Collateral, to be applied in accordance with Section 2.09 of the Credit Agreement and Section 6.02. The Collateral Agent shall cause each of the Pledged Accounts to be, and each Pledged Account shall be, separate from all other accounts held by or under the control or dominion of the Collateral Agent. The Company irrevocably confirms the authority of (and directs and authorizes) the Collateral Agent to, or to direct the Depository Bank to, and the Collateral Agent agrees to, or to direct the Depository Bank to, deposit into, or credit to, and transfer funds from the Pledged Accounts to the Collateral Agent, the Administrative Agent, the other Secured Parties and the Company (or its designee), in each case in accordance with this Agreement and the other Loan Documents.

     (c) The Credit Parties acknowledge that the Collateral Agent may cause the Depository Bank to establish subaccounts of the Qualified Investments Account, and that such subaccounts may, at the Collateral Agent’s election, be either (i) actual, separate accounts or (ii) notional accounts reflected in the Collateral Agent’s records as accounting entries with respect to the actual Qualified Investments Account maintained by the Depository Bank. Each such subaccount shall constitute a Pledged Account hereunder, and each actual subaccount shall be established and maintained by the Depository Bank as a securities account at its offices in New York City, New York, in the name of the Collateral Agent.

     (d) Unless otherwise specified in this Agreement, all references to the Qualified Investments Account shall include references to all subaccounts thereof, and such subaccounts shall be subject to the same restrictions and limitations as the Qualified Investments Account.

     (e) The Company shall not have any rights against or to moneys or funds on deposit in, or credited to, the Pledged Accounts, as third-party beneficiary or otherwise, except the right of the Company (a) to receive moneys or funds on deposit in, or credited to, the Pledged Accounts, as required or permitted by this Agreement or by the provisions of any other Loan Document (to the extent such provisions are not inconsistent with this Agreement), and (b) to direct the Collateral Agent as to the investment of moneys held in the Pledged Accounts as permitted by Section 4.05. In no event shall any amounts or Cash Equivalents deposited into, or credited to, any Pledged Account, be registered in the name of the Company, payable to the order of the Company, or specially

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endorsed to the Company, except to the extent that the foregoing have been specially endorsed to the Depository Bank or endorsed in blank.

     Section 4.02. Cash Collateral Account. (a) [Reserved]

     (b) Amounts deposited in the Cash Collateral Account shall be held therein, subject to the following provisions:

     (i) If any Letter of Credit is drawn, in whole or in part, and not reimbursed by the applicable Borrower within the period specified in Section 2.04(e) of the Credit Agreement, the Issuing Bank with respect to such Letter of Credit may request, whereupon the Collateral Agent shall within three Business Days after receipt of such request, direct the Depository Bank to promptly distribute to such Issuing Bank an amount equal to the lesser of (x) the amount of the LC Disbursement in respect of such Letter of Credit that has not been reimbursed by or on behalf of such Borrower and (y) the total amount available in the Cash Collateral Account at such time.

     (ii) Upon the request of the Company at a time when no Event of Default is continuing, the Collateral Agent shall direct the Depository Bank to distribute any funds in the Cash Collateral Account (other than, prior to the Final Payment Date, funds deposited in the Cash Collateral Account pursuant to Section 2.09(c) of the Credit Agreement) to the Company (or to the Company’s designee) to be used by the Company for general corporate purposes, or to be used by such designee for any lawful purpose.

     (iii) If an Event of Default shall have occurred and be continuing, the Collateral Agent may, at the direction of the Majority Lenders, apply funds in the Cash Collateral Account in accordance with Section 6.02.

     (c) If any Letter of Credit, or any portion thereof, has terminated, expired or otherwise been released or satisfied undrawn and, as a result, the total amount of funds in the Cash Collateral Account, as of such date, exceeds 105% of the aggregate amount of LC Exposure, as of such date, then (i) the Collateral Agent shall, upon any request therefor from the Company, direct the Depository Bank to transfer such excess of funds on deposit in the Cash Collateral Account (any such amount, “Unused Cash Collateral”) into the Collateral Account; and (ii) such Unused Cash Collateral shall be applied in accordance with Section 2.09 of the Credit Agreement and Section 6.02.

     Section 4.03. Qualified Investments Account. (a) If a FERC-Regulated Restricted Subsidiary receives Net Cash Proceeds from the Disposition of a Covered Asset as described in clause (d) of the definition of “Mandatory Asset

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Reduction Event”, then the Company shall deposit, or cause to be deposited, into the Collateral Account, within five days after such receipt, the amount, if any, by which the portion of such Net Cash Proceeds that is not deemed to have been invested in Qualified Investments described in clause (a)(ii) or (a)(iii) of the definition thereof exceeds $100,000,000.

     (b) If an Unregulated Restricted Subsidiary receives Net Cash Proceeds from the Disposition of a Covered Asset as described in clause (d) of the definition of “Mandatory Asset Reduction Event”, then the Company shall deposit, or cause to be deposited, into the Collateral Account, within five days after such receipt, the portion of such Net Cash Proceeds that is not deemed to have been invested in Qualified Investments described in clause (b)(ii) or (b)(iii) of the definition thereof.

     (c) So long as no Event of Default has occurred and is continuing within one Business Day after receipt, the Collateral Agent shall direct the Depository Bank to transfer the funds deposited into the Collateral Account pursuant to Section 4.03(a) or 4.03(b) (in either case, for each Disposition, the “Remaining Reinvestment Amount”) to the Qualified Investments Account.

     (d) If funds are to be transferred to the Qualified Investments Account pursuant to Section 4.03(c) and after giving effect to such transfer the Qualified Investments Account would contain funds in respect of the Covered Assets of more than one Restricted Subsidiary, or in respect of more than one Covered Asset of a single Restricted Subsidiary, the Collateral Agent shall cause the Depository Bank to establish and maintain individual securities subaccounts, or the Collateral Agent shall establish in its accounting records notional subaccounts (each, a “Qualified Investments Subaccount”), in each case within the Qualified Investments Account, for each such Restricted Subsidiary or each such Covered Asset.

     (e) For the period from the initial transfer of the Remaining Reinvestment Amount to the Qualified Investments Account, until the date, if ever, on which the failure of the applicable Restricted Subsidiary to invest such Remaining Reinvestment Amount in Qualified Investments, requires application of all or a portion thereof in connection with a reduction of the Commitments pursuant to Section 2.07(d) of the Credit Agreement, the Collateral Agent shall, at the written direction of the Company from time to time, direct the Depository Bank to pay such funds on deposit in the Qualified Investments Account (or any applicable Qualified Investments Subaccount) to the Restricted Subsidiary identified by the Company in the Officer’s Certificate described in the following sentence. The written direction described in the preceding sentence shall be accompanied by an Officer’s Certificate (i) setting forth the name of the Restricted Subsidiary whose Disposition of Covered Assets resulted in the deposit of the Remaining Reinvestment Amount that is being requested to be paid pursuant to such written direction, (ii) if such Restricted Subsidiary is a FERC-

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Regulated Restricted Subsidiary, stating that all funds retained by such FERC-Regulated Restricted Subsidiary pursuant to Section 4.03(a) from the Net Cash Proceeds of all of its Dispositions of Covered Assets prior to the date of such certificate have been, or (by making the currently proposed Qualified Investment(s)) will be, used to make Qualified Investments, and (iii) describing the Qualified Investment(s) to be made (or deemed made) by such Restricted Subsidiary with such funds, pursuant to the definition of “Qualified Investment”. Notwithstanding the foregoing, the Company shall have the right to direct that funds on deposit in the Qualified Investments Account or any applicable Qualified Investments Subaccount be paid to a FERC-Regulated Restricted Subsidiary in respect of new Qualified Investments made or deemed made by such FERC-Regulated Restricted Subsidiary only if, on the proposed date of such payment from the Qualified Investments Account or applicable Qualified Investments Subaccount, the aggregate amount of Qualified Investments made by such FERC-Regulated Restricted Subsidiary after April 16, 2003 equals or exceeds the sum of (1) the product of (x) $100,000,000 times (y) the number of such Dispositions of Covered Assets by such FERC-Regulated Restricted Subsidiary that have resulted in a deposit in the Collateral Account, plus (2) the aggregate Net Cash Proceeds of Dispositions of Covered Assets by such FERC-Regulated Restricted Subsidiary after April 16, 2003 that have not resulted in deposits into the Collateral Account.

     (f) If a Mandatory Asset Reduction Event described in clause (d) of the definition thereof shall occur with the result that the Company is required to cause Loans to be prepaid or Letters of Credit to be Cash Collateralized pursuant to Section 2.09(c) of the Credit Agreement (a “2.09 Application”), the Collateral Agent shall direct the Depository Bank to transfer (i) if such Mandatory Asset Reduction Event does not occur during the pendency of an Event of Default, (A) an amount equal to the lesser of (x) the required 2.09 Application and (y) 80% of the funds remaining in the Qualified Investments Account (or the applicable Qualified Investments Subaccount) in respect of the applicable Disposition of Covered Assets to the Collateral Account to be applied in accordance with Section 2.09(c) of the Credit Agreement, and (B) any remaining funds in the Qualified Investments Account (or the applicable Qualified Investments Subaccount) to the Company, or as the Company directs, to be used for general corporate purposes, or (ii) if such Mandatory Asset Reduction Event occurs concurrently with or during the pendency of an Event of Default, 100% of the funds remaining in the Qualified Investments Account (and in all applicable Qualified Investments Subaccounts) in respect of the applicable Disposition of Covered Assets to the Collateral Account to be applied (x) to the extent of the required 2.09 Application, in accordance with Section 2.09(c) of the Credit Agreement and (y) the balance, in accordance with Section 6.02 hereof.

     (g) If following the application of a Mandatory Asset Reduction Amount in accordance with Section 2.07(d) of the Credit Agreement and any prepayment of Loans or Cash Collateralization of outstanding Letters of Credit in

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connection therewith pursuant to Section 2.09(c) of the Credit Agreement, there are remaining funds in the Qualified Investments Account attributable to such Mandatory Asset Reduction Amount, the Collateral Agent shall direct the Depository Bank to transfer such remaining funds (i) if no Event of Default exists at the time, to the Company, or as the Company directs, to be used for general corporate purposes, or (ii) if an Event of Default exists at the time, to the Collateral Account to be applied in accordance with Section 6.02 hereof.

     (h) The Collateral Agent shall effectuate any transfer required pursuant to Section 4.03(f) or 4.03(g) by giving appropriate entitlement orders to the Depository Bank.

     Section 4.04. Payments in Trust. If, notwithstanding the instructions given or required to be given in accordance with this Article 4, any payments required by any Security Document to be remitted to the Collateral Agent are instead remitted to the Company or its Affiliates (it being the intent and understanding of the parties hereto that such payments are not to be made directly to the Company but directly to the Collateral Agent for deposit into, or credit to, the relevant Pledged Account for application in accordance with this Article 4), then, to the fullest extent permitted by Applicable Law, the Company or such other Person shall receive such payments into a constructive trust for the benefit of the Secured Parties and subject to the Secured Parties’ security interest, and shall (or shall use its best efforts to cause the Person receiving such payments to) promptly remit them to the Collateral Agent for deposit into, or credit to, the applicable Pledged Account designated by this Article 4.

     Section 4.05. Investment of Funds in Pledged Accounts. (a) The Collateral Agent will promptly direct the Depository Bank to (i) invest amounts on deposit in, or credited to, the Pledged Accounts, (ii) reinvest any interest paid on the amounts referred to in clause (i) above, and (iii) reinvest other proceeds of any such amounts that may mature or be sold, in each case, in Cash Equivalents which are deposited into, or credited to, such Pledged Account, in each case as the Company may select and instruct the Collateral Agent, unless, to the knowledge of the Collateral Agent, any Event of Default has occurred and is continuing, in which event the Collateral Agent shall direct the Depository Bank to invest such amounts in Cash Equivalents as the Collateral Agent may direct. If no Event of Default then exists, interest and proceeds resulting from an investment of funds in any Pledged Account in Cash Equivalents shall be, promptly upon request of the Company, transferred to the Company to be used for general corporate purposes. In addition, subject to any instructions from the Company (if not during the pendency of an Event of Default), the Collateral Agent shall have the right at any time to direct the Depository Bank to exchange such Cash Equivalents for similar Cash Equivalents of smaller or larger denominations.

     (b) Unless it has received instructions from the Company in accordance with this Section 4.05 as to the investment of such funds, the Collateral Agent

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may direct the Depository Bank to invest or reinvest any funds in any Pledged Account. All investments and reinvestments of funds in the Pledged Accounts shall be made in the name of the Depository Bank.

     (c) Whenever directed to make a transfer of funds from any of the Pledged Accounts in accordance with this Article 4, the Collateral Agent is hereby directed and authorized by the Company, the Borrowers and the Grantors (for themselves and their respective Subsidiaries) to direct the Depository Bank to liquidate (or cause to be liquidated) Cash Equivalents (in order of their respective maturities with the Cash Equivalents with the shortest maturities being liquidated first), to the extent that, after application of all other funds available for such purpose pursuant to this Article 4, the liquidation of any Cash Equivalent is necessary to make such transfer.

     (d) Neither the Collateral Agent nor the Depository Bank shall (in the absence of gross negligence or willful misconduct, as finally determined by a court of competent jurisdiction) have any liability with respect to any interest, cost or penalty on the liquidation of any Cash Equivalent pursuant to this Agreement, nor shall the Collateral Agent (in the absence of gross negligence or willful misconduct, as finally determined by a court of competent jurisdiction) have any liability with respect to Cash Equivalents (including purchases or conversions of foreign exchange) or moneys deposited into, or credited to, the Pledged Accounts (or any losses resulting therefrom) invested in accordance with this Agreement. Without limiting the generality of the foregoing, in the absence of gross negligence or willful misconduct, as finally determined by a court of competent jurisdiction, the Collateral Agent shall have no responsibility for any investment losses resulting from the investment, reinvestment or liquidation of all or a portion of funds in the Pledged Accounts, if the Collateral Agent has made such investment, reinvestment or liquidation, as applicable, in accordance with this Agreement.

     (e) All references in this Agreement to Pledged Accounts and to cash, moneys or funds therein or balances thereof, shall include the Cash Equivalents in which such cash, moneys, funds or balances are then invested and the proceeds thereof, and all financial assets and security entitlements carried in or credited to such Pledged Accounts.

     (f) (i) Neither the Collateral Agent nor any of its Affiliates assume any duty or liability for monitoring the rating or performance of any Cash Equivalent. Subject to Section 4.06, in the event an investment selection is not made by the Company in accordance with this Section 4.05, the funds in the Pledged Accounts shall not be required to be invested but may be invested at the discretion of the Collateral Agent, and the Collateral Agent shall not incur any liability for interest or income thereon. The Collateral Agent shall have no obligation to cause the investment or reinvestment of the funds in the Pledged Accounts on the day of deposit if all or a portion of such funds is deposited with the Collateral Agent

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after 11:00 a.m. (New York City time) on such day of deposit. Instructions to invest or reinvest that are received after 11:00 a.m. (New York City time) will be treated as if received on the following Business Day in New York. Requests or instructions received after 11:00 a.m. (New York City time) by the Collateral Agent to liquidate all or a portion of funds in any Pledged Account will be treated as if received on the following Business Day in New York.

     (ii) The Credit Parties acknowledge that non-deposit investment products (A) are not obligations of, nor guaranteed, by JPMCB or any of its Affiliates; (B) are not FDIC insured; and (C) are subject to investment risks, including the possible loss of principal amount invested.

     Section 4.06. Transfers from Accounts During the Continuance of an Event of Default. During the existence and continuance of an Event of Default, the Collateral Agent shall not be obligated to accept any instructions from the Company with respect to any transfer or withdrawal of funds on deposit in, or credited to, any Pledged Account and, in such circumstances, the Collateral Agent may direct the investment, transfer or withdrawal of funds in the Pledged Accounts without further consent by the Company.

     Section 4.07. Reports, Certification and Instructions. (a) The Collateral Agent shall maintain all such accounts, books and records as may be necessary to properly record all transactions carried out by it under this Agreement. The Collateral Agent shall permit the Company and its Affiliates and their authorized representatives to examine such accounts, books and records; provided that any such examination shall occur upon reasonable notice and during normal business hours.

     (b) The Collateral Agent shall deliver to the Company copies of the account statements for all Pledged Accounts (including all subaccounts) for each month. Such account statements shall indicate, with respect to each such account, deposits, credits and transfers, investments made and closing balances. The Collateral Agent shall provide any additional information or reports relating to the Pledged Accounts and the transactions therein reasonably requested from time to time by the Company or any Secured Party.

     (c) Each time the Company directs the Collateral Agent to make or cause to be made a transfer or withdrawal from a Pledged Account, it shall be deemed to represent and warrant for the benefit of the Collateral Agent and the other Secured Parties that such transfer or withdrawal is being made in an amount, and shall be applied solely for the purposes permitted by, and is and will otherwise be in accordance with, this Agreement and the Credit Agreement. Except to the extent any officer or officers of the Collateral Agent responsible for the administration of this Agreement has actual knowledge to the contrary, the Collateral Agent may conclusively rely on, and shall incur no liability in so relying on, any such direction.

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     (d) Notwithstanding any provision to the contrary contained in this Agreement, all notices, certifications, approvals, directions, instructions or other communication given to the Collateral Agent with respect to any payments, transfers, credits, deposits, withdrawals or investments with respect to, or otherwise relating to, any Pledged Account, in each case, by the Company or by any other Secured Party shall be given in writing, and the Collateral Agent shall not be required to take any action with respect to any payments, transfers, credits, deposits, withdrawals or investments unless it has received such written instructions specifying the date, amount and Pledged Account with respect to which such payment, transfer, credit, deposit, withdrawal or investment is to be made.

     Section 4.08. Depository Bank Undertakings. The Depository Bank hereby represents and warrants to, and agrees with the Company and the Collateral Agent as follows:

     (a) The Depository Bank (i) is a securities intermediary on the date hereof and (ii) so long as this Agreement remains in effect and such Depository Bank remains the Depository Bank hereunder, shall remain a securities intermediary, and shall act as such with respect to the Company, the Collateral Agent, the Pledged Accounts and all of the Account Collateral and any other property (including all financial assets and security entitlements maintained or carried in the Pledged Accounts) from time to time transferred to, credited to, deposited in, or maintained in the Pledged Accounts.

     (b) Each of the Pledged Accounts is, and shall remain, and the Depository Bank shall maintain each of the Pledged Accounts as, a securities account, with the Collateral Agent (and no other Person) as the entitlement holder and under the sole dominion and control of the Collateral Agent for the ratable benefit of the Collateral Agent and the other Secured Parties.

     (c) The Depository Bank (i) has identified (and will continue to identify) the Collateral Agent for the ratable benefit of the Secured Parties in its records as, and will treat the Collateral Agent as (A) the sole Person having a security entitlement against the Depository Bank with respect to the Pledged Accounts and the Account Collateral from time to time carried in the Pledged Accounts, (B) the sole entitlement holder against the Depository Bank with respect to each of the Pledged Accounts, (C) the sole Person having dominion and control over each of the Pledged Accounts and any and all assets, property and items from time to time carried in such Pledged Accounts (including cash) and (D) the sole Person entitled to exercise the rights with respect to the Pledged Accounts; and (ii) has credited and will continue to credit such assets, property and items to the Pledged Accounts in accordance with written instructions given pursuant to, and the other terms and conditions of, this Agreement.

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     (d) All of the property, including Account Collateral and cash, from time to time carried in or credited to the Pledged Accounts, shall constitute financial assets, and the Depository Bank shall treat all such property as financial assets under Article 8 of the UCC.

     (e) Notwithstanding any other provision in this Agreement to the contrary, the Depository Bank (i) shall comply with any and all entitlement orders and other directions originated by, and only by, the Collateral Agent in respect of the Pledged Accounts and the Account Collateral from time to time carried therein without any further consent or action by the Company or any other Person and (ii) shall not comply with the entitlement orders of any other Person.

     (f) The “securities intermediary’s jurisdiction” (within the meaning of Section 8-110(e) of the UCC) of the Depository Bank is and will continue to be the State of New York.

     (g) To be binding on the Depository Bank, all instructions by the Collateral Agent pursuant to this Agreement with respect to the Account Collateral carried in the Pledged Accounts must be given to the Depository Bank, and only pursuant to and subject to the terms and conditions of this Agreement.

     (h) Anything herein to the contrary notwithstanding, the Depository Bank will not be required to follow any instruction that would violate any Applicable Law, decree, regulation or order of any Governmental Authority (including any court or tribunal) or the terms of this Agreement.

     (i) The Depository Bank has not entered into and will not enter into any agreement with any other Person relating to the Pledged Accounts or any Pledged Financial Assets credited thereto pursuant to which it has agreed or will agree to comply with entitlement orders of such Person. The Depository Bank has not entered into any other agreement with the Company or any other Person purporting to limit or condition the duties of the Depository Bank to comply with entitlement orders originated by the Collateral Agent as set forth in Section 4.08(e).

     (j) The Depository Bank hereby permanently waives and releases any Lien, right of setoff or other right it may have against the Pledged Accounts and any Pledged Financial Assets or Pledged Security Entitlements carried in or credited to the Pledged Accounts and any credit balance or cash in the Pledged Accounts, and agrees that it will not assert any such Lien or other right in, to or against the Pledged Accounts or any Pledged Financial Asset or Pledged Security Entitlement carried therein or credited thereto, or any credit balance or cash in the Pledged Accounts.

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     (k) The Depository Bank will send copies of all statements and confirmations for and in respect of the Pledged Accounts simultaneously to the Company and the Collateral Agent.

     (l) All securities or other property underlying any financial assets consisting of Account Collateral deposited in or credited to a Pledged Account shall be registered in the name of the Depository Bank, endorsed to the Depository Bank or in blank or credited to another securities account or securities accounts maintained in the name of the Depository Bank, and in no case will any financial asset consisting of Account Collateral deposited in or credited to a Pledged Account be registered in the name of the Company, payable to the order of the Company or specially endorsed to the Company, except to the extent the foregoing have been specially endorsed by the Company to the Depository Bank or in blank.

     (m) If any Person (other than the Collateral Agent) asserts to the Depository Bank any Lien, encumbrance or adverse claim (including any writ, garnishment, judgment, warrant of attachment, execution or similar process) against any Account Collateral, the Depository Bank will as promptly as practicable thereafter notify the Company and the Collateral Agent thereof.

     Section 4.09. Force Majeure. Neither the Collateral Agent nor the Depository Bank shall incur any liability for not performing any act or fulfilling any obligation hereunder by reason of any occurrence beyond its control (including any provision of any present or future law or regulation or any act of any Governmental Authority, any act of God, war or terrorism, or the unavailability of the Federal Reserve Bank wire services or any electronic communication facility).

     Section 4.10. Clearing Agency. The Account Collateral in the Pledged Accounts may be held by the Collateral Agent directly or through any clearing agency or depository including the Federal Reserve/Treasury Book-Entry System for United States and federal agency securities, and the Depository Trust Company (collectively, the “Clearing Agency”). The Collateral Agent shall not have any responsibility or liability for the actions or omissions to act on the part of any Clearing Agency. The Collateral Agent is authorized, for any Collateral at any time held hereunder, to register the Collateral in the name of one or more of its nominee(s) or the nominee(s) of any Clearing Agency in which the Collateral Agent has a participant account, and such nominee(s) may sign the name of any Credit Party and guarantee such signature in order to transfer securities or certify ownership thereof to tax or other Governmental Authorities.

     Section 4.11. Return of Funds to the Company. Upon any request by the Company following the release of the Transaction Liens in accordance with Section 5.07(b), the Collateral Agent shall direct the Depository Bank to, and the Depository Bank shall promptly pay, transfer and deliver to or to the order of the

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Company all moneys, investments, and other property held in, or credited to, the Pledged Accounts, in each case, in accordance with the instructions of the Company and at the Company’s expense.

ARTICLE 5
Security Interests

     Section 5.01. Grant of Security Interests. (a) Each Subsidiary Grantor hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in such Subsidiary Grantor’s right, title and interest in and to the following, in each case, as to each type of property described below, whether now owned or hereafter acquired by such Subsidiary Grantor, wherever located, and whether now or hereafter existing or arising (collectively, the “Security Collateral”):

     (i) the Initial Pledged Equity and the certificates, if any, representing the Initial Pledged Equity, and all dividends, distributions, return of capital, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of, in exchange for, or in conversion of, any or all of the Initial Pledged Equity and all subscription warrants, rights or options issued thereon or with respect thereto;

     (ii) all additional shares of stock and other Equity Interests of or in any Pledged Company from time to time acquired by such Subsidiary Grantor in any manner (such shares and other Equity Interests, together with the Initial Pledged Equity, being the “Pledged Equity”), and the certificates, if any, representing such additional shares or other Equity Interests, and all dividends, distributions, return of capital, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of such Pledged Equity and all subscription warrants, rights or options issued thereon or with respect thereto;

     (iii) all books and records of such Grantor pertaining to the Security Collateral;

     (iv) all supporting obligations, general intangibles and contract rights (including rights under limited liability company agreements, limited partnership agreements and any other organizational or constituent documents pursuant to which Pledged Equity has been issued or which sets out rights with respect thereto), warranties, indemnities or guaranties, in each case to the extent relating to, or payable in respect of, interests in the Security Collateral, and any tort claims (including all commercial tort claims) arising in connection with interests in the Security Collateral; and

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     (v) all proceeds of the foregoing Security Collateral.

     (b) Each Subsidiary Grantor hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in such Subsidiary Grantor’s right, title and interest in and to the following (but excluding Excluded Subsidiary Grantor Assets), in each case, as to each type of property described below, whether now owned or hereafter acquired by such Subsidiary Grantor, wherever located, and whether now or hereafter existing or arising (all such property in which a security interest is granted under this Section 5.01(b) being, collectively, the “Subsidiary Grantor Payment Collateral”):

     (i) all accounts and payment intangibles owing to such Subsidiary Grantor by (A) any Pipeline Company Borrower or (B) any other Grantor;

     (ii) all instruments owing to such Subsidiary Grantor by (A) any Pipeline Company Borrower or (B) any other Grantor;

     (iii) all chattel paper in respect of obligations payable to such Subsidiary Grantor with respect to which the account debtor is (A) any Pipeline Company Borrower or (B) any other Grantor; and

     (iv) all proceeds of the foregoing Subsidiary Grantor Payment Collateral.

Notwithstanding the foregoing, the Subsidiary Grantor Payment Collateral shall not include, and the Liens created under this Section 5.01(b) shall not encumber, (A) any (1) accounts owing to the Exempted Guarantor by the Company, (2) payment intangibles owing to the Exempted Guarantor by the Company, (3) instruments owing to the Exempted Guarantor by the Company or (4) chattel paper in respect of obligations payable to the Exempted Guarantor with respect to which the account debtor is the Company, or (B) any Excluded Payment Property of any Grantor (all of the property described in clause (A) and (B) of this sentence being, collectively, the “Excluded Subsidiary Grantor Assets”).

     (c) The Company hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in the Company’s right, title and interest in and to the following (but excluding Excluded Payment Property of the Company), in each case, as to each type of property described below, whether now owned or hereafter acquired by the Company, wherever located, and whether now or hereafter existing or arising (all such property in which a security interest is granted under this Section 5.01(c) being, collectively, the “Company Payment Collateral”, and together with the Subsidiary Grantor Payment Collateral, the “Payment Collateral”):

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     (i) all accounts or payment intangibles owing to the Company by (A) any Pipeline Company Borrower or (B) any Grantor (other than the Exempted Guarantor);

     (ii) all instruments owing to the Company by (A) any Pipeline Company Borrower or (B) any Grantor (other than the Exempted Guarantor);

     (iii) all chattel paper in respect of obligations payable to the Company with respect to which the account debtor is (A) any Pipeline Company Borrower or (B) any Grantor (other than the Exempted Guarantor); and

     (iv) all proceeds of the foregoing Company Payment Collateral.

Notwithstanding the foregoing, the Company Payment Collateral shall not include, and the Liens created under this Section 5.01(c) shall not encumber, any Excluded Payment Property of the Company.

     (d) Each Grantor hereby grants to the Collateral Agent, for the ratable benefit of the Secured Parties, a security interest in such Grantor’s right, title and interest in and to the following, in each case, as to each type of property described below, whether now owned or hereafter acquired by such Grantor, wherever located, and whether now owned or hereafter existing or arising (collectively, the “Account Collateral”):

     (i) the Pledged Accounts, all Pledged Financial Assets, all Pledged Security Entitlements and all property, funds, interest, dividends, distributions, cash, instruments and other property from time to time carried in or credited to any Pledged Account or received, receivable or otherwise distributed in respect of or in exchange for any or all of the foregoing, and all certificates and instruments, if any, from time to time representing or evidencing the Pledged Accounts;

     (ii) all promissory notes, certificates of deposit, deposit accounts, checks and other instruments delivered (or required to be delivered) to or otherwise possessed by the Collateral Agent for or on behalf of such Grantor in connection with the Account Collateral, including those received in substitution for or in addition to any or all of the Account Collateral;

     (iii) all interest, dividends, distributions, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of the Account Collateral;

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     (iv) all books and records of such Grantor pertaining to any of the Account Collateral;

     (v) all supporting obligations, general intangibles, contract rights, warranties, indemnities and guaranties, in each case to the extent relating to, or payable in respect of, the Account Collateral; and

     (vi) all proceeds of the foregoing Account Collateral.

     Section 5.02. Security for Obligations. (a) In the case of each Grantor, the security interests granted by such Grantor pursuant to Sections 5.01(a) through (d) secure the payment and performance of all such Grantor’s Secured Obligations, whether now existing or hereafter arising.

     (b) Without limiting the generality of subsection (a) of this Section 5.02, as to each Grantor, the security interests granted by such Grantor pursuant to Sections 5.01(a) through (d) secure the payment of all amounts that constitute part of such Grantor’s Secured Obligations and would be owed by such Grantor but for the fact they are unenforceable or not allowable due to the existence of an Insolvency Proceeding involving such Grantor.

     Section 5.03. Delivery and Control of Collateral. (a) All certificates or instruments representing or evidencing Security Collateral shall be delivered to and held by or on behalf of the Collateral Agent pursuant hereto and shall be in suitable form for transfer by delivery, or shall be accompanied by duly indorsed instruments of transfer or assignment in blank, all in form and substance reasonably satisfactory to the Collateral Agent, but excluding checks, certificates of title and other similar instruments. If an Event of Default has occurred and is continuing, the Collateral Agent shall have the right, in its discretion and without notice to any Credit Party, to transfer to or to register in the name of the Collateral Agent or any of its nominees any or all of the Security Collateral, subject only to the revocable rights specified in Section 5.08. In addition, the Collateral Agent shall have the right at any time to exchange certificates or instruments representing or evidencing Security Collateral for certificates or instruments of smaller or larger denominations.

     (b) With respect to any Security Collateral in which any Grantor has any right, title or interest and that constitutes an uncertificated security, such Grantor will cause the issuer thereof to agree in an authenticated record with such Grantor and the Collateral Agent that such issuer will comply with instructions with respect to such Security Collateral originated by the Collateral Agent without further consent of such Grantor, such authenticated record to be in form and substance satisfactory to, and to be delivered to, the Collateral Agent. With respect to any Security Collateral in which any Grantor has any right, title or interest and that is not an uncertificated security, upon the request of the

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Collateral Agent, such Grantor will notify each such issuer of Pledged Equity that such Pledged Equity is subject to the security interest granted hereunder.

     (c) Each Grantor shall deliver to the Collateral Agent all Payment Collateral pledged by it that constitutes instruments or tangible chattel paper, accompanied by duly indorsed instruments of transfer or assignment in blank, which instruments of transfer or assignment shall be in form reasonably satisfactory to the Collateral Agent.

     Section 5.04. Further Assurances; Etc.. (a) Each Grantor agrees that from time to time, at the expense of such Grantor, such Grantor will promptly do, execute, acknowledge, deliver, record, re-record, file, re-file, register and re-register any and all such further acts, pledge agreements, collateral assignments, account control agreements, financing statements and continuations thereof, termination statements, notices of assignment, transfers, certificates, assurances and other instruments as the Collateral Agent or the Depository Bank may reasonably require from time to time in order to (i) carry out more effectively the purposes of the Security Documents with respect to the Collateral, (ii) to the fullest extent permitted by Applicable Law, subject its right, title and interest in and to the Collateral to the Transaction Liens, (iii) perfect and maintain the validity and effectiveness of the Security Documents and the validity, effectiveness and priority of the Transaction Liens and (iv) assure, grant, collaterally assign, transfer, preserve, protect and confirm more effectively unto the Secured Parties the rights granted or now or hereafter stated to be granted to the Secured Parties in respect of the Collateral under any Security Document or under any other instrument executed in connection with any Security Document to which it is a party. Without limiting the generality of the foregoing, each Grantor will promptly with respect to Collateral of such Grantor: (A) execute or authenticate and file such financing or continuation statements, or amendments thereto, and such other instruments or notices, as may be necessary or desirable, or as the Collateral Agent may reasonably request, in order to perfect and preserve the Transaction Liens; (B) deliver and pledge to the Collateral Agent for benefit of the Secured Parties certificates representing Security Collateral that constitutes certificated securities, accompanied by undated stock powers indorsed in blank, and deliver and pledge to the Collateral Agent for the benefit of the Secured Parties all tangible chattel paper and all instruments constituting Collateral, together with duly indorsed instruments of transfer or assignment in blank; (C) take all action necessary to ensure that the Collateral Agent has control of Collateral, if any, consisting of deposit accounts, as provided in Section 9-104 of the UCC, control of the Account Collateral as provided in Sections 8-106 and 9-106 of the UCC, and control of Payment Collateral consisting of electronic chattel paper as provided in Section 9-105 of the UCC; and (D) deliver to the Collateral Agent evidence that all other action that the Collateral Agent may reasonably request as necessary or desirable to perfect and preserve Transaction Liens has been taken.

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     (b) Each Grantor hereby authorizes the Collateral Agent to file one or more financing or continuation statements, and amendments thereto, including one or more financing statements indicating that such financing statements cover all right, title and interest of such Grantor in and to the Collateral, in each case without the signature of such Grantor. The Collateral Agent shall provide a copy of each such financing statement to each Grantor. A photocopy or other reproduction of this Agreement or any financing statement covering the Collateral or any part thereof shall be sufficient as a financing statement where permitted by law. Each Grantor ratifies its authorization for the Collateral Agent to have filed such financing statements, continuation statements or amendments filed prior to the date hereof.

     Section 5.05. Grantors Remain Liable. Anything herein to the contrary notwithstanding, (a) each Grantor shall remain liable under any contracts and agreements included in such Grantor’s Collateral (including, with respect to Security Collateral, any obligations under limited liability company agreements, limited partnership agreements and any other organizational or constituent documents pursuant to which Pledged Equity has been issued or which sets out obligations with respect to Security Collateral) to the extent set forth therein to perform all of its duties and obligations thereunder to the same extent as if this Agreement had not been executed, (b) the exercise by the Collateral Agent of any of the rights hereunder shall not release any Grantor from any of its duties or obligations under the contracts and agreements included in the Collateral and (c) no Secured Party shall have any obligation or liability under the contracts and agreements included in the Collateral by reason of this Agreement or any other Security Document, nor shall any Secured Party be obligated to perform any of the obligations or duties of any Grantor thereunder or to take any action to collect or enforce any claim for payment assigned hereunder.

     Section 5.06. Additional Equity Interests. (a) Pledged Equity. Each Grantor agrees that (i) it will cause each Pledged Company the Pledged Equity in which has been pledged by such Grantor hereunder, not to issue any Equity Interests or other securities in addition to or in substitution for the Pledged Equity issued by such Pledged Company, except to such Grantor, (ii) it will pledge hereunder, immediately upon such Grantor’s acquisition (directly or indirectly) thereof, any and all additional Equity Interests issued by such Pledged Company, and (iii) it will cause all such Equity Interests issued by such Pledged Company to be certificated securities under Article 8 of the UCC and under Article 8 or Chapter 8 of the Uniform Commercial Code as in effect in the jurisdiction of organization of such Pledged Company; provided, however, that this Section 5.06 shall not limit any Grantor’s rights under Section 5.07(a)(ii).

     (b) Ownership of Equity Interests in Grantors. The Company agrees and covenants that it will at all times own, directly or indirectly, 100% of the outstanding Equity Interests (including all voting, economic and other rights associated therewith) in each Grantor, except for the rights of the Collateral Agent

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hereunder with respect to the Equity Interests in any Grantor that is a Pledged Company.

     (c) Ownership of Equity Interests in Pledged Companies. Each Grantor (including any successor thereto pursuant to a merger or consolidation permitted under Section 6.05 of the Credit Agreement) agrees and covenants that (i) it will at all times remain a registered organization, as defined in Section 9-102(70) of the UCC, and (ii) with respect to each Pledged Company in which such Grantor has pledged Equity Interests hereunder, such Grantor will at all times own directly 100% of the outstanding Equity Interests issued by such Pledged Company (including voting, economic and other rights associated therewith), except to the extent permitted under Section 6.04(a)(iv) of the Credit Agreement and except for the rights of the Collateral Agent hereunder.

     Section 5.07. Release of Collateral. (a) Partial Release of Collateral.

     (i) Payments out of Pledged Accounts. Upon any payment of amounts out of any Pledged Account (and not deposited into, or transferred to, another Pledged Account) to (A) the Administrative Agent, the Collateral Agent or the Depository Bank in respect of amounts due and payable hereunder to such Persons or other Secured Parties, (B) any Secured Party or (C) the Company or any Restricted Subsidiary (or any other Person designated in writing by the Company to the Collateral Agent to receive such payment), in each case in accordance with the Security Documents, the Transaction Liens on such amount shall be automatically released without further action or consent by the Collateral Agent or any other Person (including any Secured Party).

     (ii) Release of Lien on Collateral. Upon the Disposition of any Collateral in a transaction permitted under the Credit Agreement and the other Loan Documents, the Transaction Liens on such Collateral shall be automatically released without further action or consent by the Collateral Agent or any other Person (including any other Secured Party).

     (b) Full Release of Collateral. On the earlier of (A) the Final Payment Date or (B) the date on which the requisite percentage of the Lenders have approved the release of the Transaction Liens in accordance with Section 10.02 of the Credit Agreement, the Transaction Liens shall be fully and automatically released without further action by the Collateral Agent or any other Person (including any other Secured Party), and all rights to the Collateral shall revert to the applicable Grantor.

     (c) Delivery of Releases and Return of Collateral. Upon the release of any Transaction Lien pursuant to this Section 5.07, the Collateral Agent will, at the applicable Grantor’s expense, (i) execute and deliver to such Grantor such release or releases (including Uniform Commercial Code partial release or

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termination statements) as such Grantor shall reasonably request to evidence such release, and (ii) deliver to the applicable Grantors or their designees designated in writing to the Collateral Agent such Collateral, including any Assets in the Pledged Accounts and any certificates or instruments representing or evidencing any such Collateral that is Security Collateral.

     Section 5.08. Voting Rights, Dividends, Payments, Etc. (a) So long as no Event of Default shall have occurred and be continuing:

     (i) each Grantor shall be entitled to exercise any and all voting and other consensual rights pertaining to the Security Collateral (including rights relating to conversion or exchange thereof) of such Grantor or any part thereof at any time and for any purpose; provided that such Grantor will not exercise or refrain from exercising any such right if such action would violate this Agreement;

     (ii) except as provided in Section 5.08(b), each Grantor shall be entitled to receive and retain any and all cash dividends, interest and other cash distributions paid in respect of the Security Collateral of such Grantor;

     (iii) each Grantor shall be entitled to receive and retain all payments made on or in respect of Payment Collateral pledged by such Grantor; and

     (iv) the Collateral Agent will (A) execute and deliver (or cause to be executed and delivered) to each Grantor all such proxies and other instruments as such Grantor may reasonably request for the purpose of enabling such Grantor to exercise the voting and other rights that it is entitled to exercise pursuant to paragraph (i) above (including, in the case of a conversion or exchange of Pledged Equity, the Collateral Agent’s delivering to the Pledged Company, as applicable, on behalf of the applicable Grantor, the certificate(s) or instrument(s) representing or evidencing any such Collateral for the purpose of effecting the exchange of such certificate(s) or instrument(s) for new certificate(s) or instrument(s)) and to receive the dividends, interest or other distributions that it is authorized to receive and retain pursuant to paragraph (ii) above, and (B) with respect to Payment Collateral, provide such instructions to account debtors and Persons obligated to make payments on instruments as will enable each Grantor to receive all payments it is authorized to receive and retain pursuant to paragraph (iii) above. In the absence of instructions to vote or exercise other rights, the Collateral Agent shall not be obligated and shall incur no liability for its failure to take any action in respect of such rights.

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     (b) The Collateral Agent shall be entitled to receive (whether or not an Event of Default has occurred and is continuing), (i) all non-cash dividends and distributions (including distributions upon conversion or exchange of Security Collateral) paid in respect of Security Collateral, which shall be held by the Collateral Agent as Security Collateral, and (ii) all cash dividends, interest and other cash distributions in respect of Security Collateral distributed in exchange for, in redemption of, or in connection with a partial or total liquidation or dissolution or with a reduction of capital, capital surplus or paid-in-surplus, which distributions described in this clause (ii) shall be deposited in the Collateral Account and held and administered as Account Collateral, provided, however, that a Credit Related Party that receives a dividend from a FERC-Regulated Restricted Subsidiary shall not be required to deliver such funds to the Collateral Agent so long as (x) such funds are not proceeds of a Mandatory Asset Reduction Event and (y) such funds are otherwise transferred to the Company. Each issuer of Pledged Equity that is a party to this Agreement agrees to pay and deliver all dividends, distributions and interest described in this Section 5.08(b) on such Pledged Equity directly to the Collateral Agent. With respect to any Pledged Equity issued in conversion or exchange of Pledged Equity issued by an issuer that is not a Pledged Company, the Grantor that has pledged such Pledged Equity shall instruct the issuer to deliver directly to the Collateral Agent the Pledged Equity so issued in the exchange or conversion. Any and all dividends, distributions and interest described in this Section 5.08(b) that are received by a Grantor contrary to the provisions of this Section 5.08(b), shall be received in trust for the benefit of the Collateral Agent, shall be segregated from the other property or funds of such Grantor, and shall promptly be delivered or paid over to the Collateral Agent and held and administered as above provided in this Section 5.08(b).

     (c) Upon the occurrence and during the continuance of any Event of Default:

     (i) all rights of each Grantor to exercise or refrain from exercising the voting and other consensual rights that it would otherwise be entitled to exercise pursuant to Section 5.08(a)(i) shall, upon delivery by the Collateral Agent to such Grantor of a written notice of such Event of Default, cease, and all such rights shall thereupon become vested in the Collateral Agent, which shall thereupon have the sole right to exercise or refrain from exercising such voting and other consensual rights;

     (ii) all rights of each Grantor to receive the dividends, interest and other distributions that it would otherwise be authorized to receive and retain pursuant to Section 5.08(a)(ii) shall, upon delivery by the Collateral Agent to such Grantor of a written notice of such Event of Default, cease, and all such rights shall thereupon become vested in the Collateral Agent, and any and all such cash dividends, interest and other cash distributions received by such Grantor shall be promptly delivered to the Collateral

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Agent who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered in accordance with Section 4.02(b)(iii). With respect to any issuer of Pledged Equity that is a party to this Agreement, upon delivery by the Collateral Agent to such issuer of a written notice of such Event of Default, such issuer shall thereafter pay and deliver all dividends, distributions and interest described in this Section 5.08(c)(ii) directly to the Collateral Agent, until such issuer has received written notice from the Collateral Agent that such Event of Default no longer exists. Each Grantor that has granted a security interest in Pledged Equity under this Agreement in an issuer that is not a party to this Agreement, agrees to cause such issuer to pay and deliver all dividends, distributions and interest described in this Section 5.08(c)(ii) directly to the Collateral Agent. Any such dividends, interest and distributions received by a Grantor contrary to the provisions of this Section 5.08(c)(ii) shall be received in trust for the benefit of the Collateral Agent, shall be segregated from the other funds of such Grantor and shall be promptly paid over to the Collateral Agent who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered as above provided in this Section 5.08(c)(ii); and

     (iii) all rights of each Grantor to receive the payments on Payment Collateral that it would otherwise be authorized to receive and retain pursuant to Section 5.08(a)(iii) shall, upon delivery by the Collateral Agent to the Grantors and the Pipeline Company Borrowers of a written notice of such Event of Default, cease and thereafter all such payments shall be made by the Grantor or the Pipeline Company Borrower, as applicable, that is the account debtor or Person obligated to make payment on such Payment Collateral, directly to the Collateral Agent, who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered in accordance with Section 4.02(b)(iii). Any such payments received by a Grantor contrary to the provisions of this Section 5.08(c)(iii) shall be received in trust for the benefit of the Collateral Agent, shall be segregated from the other funds of such Grantor and shall be promptly paid over by such Grantor to the Collateral Agent who shall cause the Depository Bank to deposit same in a subaccount of the Cash Collateral Account to be administered in accordance with this Section 5.08(c)(iii).

     Section 5.09. The Collateral Agent Appointed Attorney-in-Fact. Each Grantor hereby irrevocably appoints the Collateral Agent such Grantor’s attorney-in-fact, with full authority in the place and stead of such Grantor and in the name of such Grantor or otherwise, from time to time, in the Collateral Agent’s discretion, to take any action and to execute any instrument that the Collateral Agent may deem necessary or advisable to accomplish the purposes of this

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Agreement and any other Security Document with respect to the Collateral and the Collateral Agent’s rights and remedies with respect thereto, including:

     (a) to ask for, demand, collect, sue for, recover, compromise, receive and give acquittance and receipts for moneys due and to become due under or in respect of any of the Collateral;

     (b) to receive, indorse and collect any drafts or other instruments, documents and chattel paper, in connection with clause (a) above; and

     (c) to file any claims or take any action or institute any proceedings that the Collateral Agent may deem necessary or desirable for the collection of any of the Collateral or otherwise to enforce the rights of the Collateral Agent and any other Secured Party with respect to any of the Collateral;

provided that the Collateral Agent shall not exercise the power and authority granted to it pursuant to this Section 5.09 except during such period as an Event of Default has occurred and is continuing.

     Section 5.10. Netting of Accounts. Notwithstanding any other provision of this Agreement or the Credit Agreement, so long as no Event of Default has occurred and in continuing, any Credit Related Party may reduce (through the exercise of set-off or similar rights) the principal amount of any accounts, payment intangibles, instruments or chattel paper owed by it to another Credit Related Party by the amount of any accounts, payment intangibles, instruments or chattel paper owed to it or any of its Subsidiaries by such other Credit Related Party or any Subsidiaries of such other Credit Related Party.

ARTICLE 6
Remedies and Enforcement

     Section 6.01. Remedies and Enforcement. (a) At such time as any Event of Default has occurred and is continuing, the Collateral Agent shall have the right to take such actions as are necessary or appropriate to enforce, implement and administer the provisions hereof or of any other Security Document that are applicable to any period during which an Event of Default has occurred and is continuing, and without limiting the foregoing, the Collateral Agent shall have and may exercise, enforce, implement and administer all rights, privileges, powers, benefits and remedies granted to or arising in favor of the Collateral Agent under such provisions with respect to any such Event of Default, including in each case referenced above the provisions of Section 4.02(b)(iii), 4.03(f), 4.05( ), 4.06, 5.03(a), 5.08, and 5.09, with respect to any Net Cash Proceeds constituting Mandatory Asset Reduction Amounts, the application or non-application of funds in Pledged Accounts, deposits or transfers of funds into or from Pledged Accounts or subaccounts thereof, delivery of funds from Pledged

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Accounts to the Collateral Agent, the right to direct investments, voting rights with respect to Security Collateral and powers of attorney.

     (b) At such time as an Event of Default has occurred and is continuing, the Collateral Agent shall have and in its discretion may exercise any or all of the following rights and remedies:

     (i) Enforcement Actions. The Collateral Agent may take any Enforcement Action or Enforcement Actions (at such times, places and by such methods, as the Collateral Agent shall determine, including any actions incidental to carrying out any such Enforcement Action) in order to enforce the Security Documents and to realize upon the Collateral or, in the case of any Insolvency Proceeding against the Company or any of its Subsidiaries, seeking to enforce the claims and/or Transaction Liens, including claims under the Security Documents.

     (ii) Sale; Incidents of Sale. The Grantors agree that, to the extent notice of sale shall be required by Applicable Law with respect to the Disposition of any Collateral, at least ten days’ notice to the Company of the time and place of any public Disposition or the time after which any private Disposition is to be made shall constitute reasonable notification. The Collateral Agent shall not be obligated to make any Disposition of Collateral regardless of notice of Disposition having been given. The Collateral Agent may adjourn any public or private Disposition from time to time by announcement at the time and place fixed therefor, and such Disposition may, without further notice, be made at the time and place to which it was so adjourned. With respect to any Disposition of any of the Collateral made or caused to be made by the Collateral Agent, whether made under the power of Disposition hereby given or pursuant to judicial proceedings, to the extent permitted by Applicable Law:

     (A) Any Secured Party, the Company, and any of the Company’s Affiliates (including any Grantor) may bid for, and purchase, the Collateral offered for sale, and, upon compliance with the terms of sale and Applicable Law, may hold and Dispose of such property; and

     (B) Pursuant to the power of attorney granted under Section 5.09(a), the Collateral Agent may, but shall not be obligated to, make all necessary deeds, bills of sale and instruments of assignment and transfer covering the Collateral Disposed of, and for that purpose the Collateral Agent may execute all necessary deeds, bills of sale and instruments of assignment and transfer, and may substitute one or more Persons with like power.

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     (iii) Collateral Agent May File Proofs of Claim. In case of the pendency of any Insolvency Proceeding relative to the Company or any of its Subsidiaries or the Collateral, the Collateral Agent (irrespective of whether any of the outstanding Secured Obligations shall then be due and payable) shall be entitled and empowered (but not obligated), by intervention in such proceeding or otherwise, (A) to file and prove a claim for the whole amount of the Secured Obligations owing and unpaid in order to protect the rights of the Secured Parties under the Security Documents and with respect to the Collateral, and to file such other papers or documents as may be necessary or advisable in order to have the claims of the Collateral Agent (including any claim for the reasonable compensation, disbursements and advances of the Collateral Agent in its individual or trust capacity and its agents and counsel) and of any other Secured Parties in respect of the Security Documents and the Collateral allowed in such judicial proceeding and (B) to collect and receive any moneys or other property payable or deliverable on any such claims and to distribute the same; and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Secured Party to make payments with respect to such claims to the Collateral Agent.

     (iv) Collateral Agent May Enforce Claims. All rights of action and claims under this Agreement and the other Security Documents may be prosecuted and enforced by the Collateral Agent; provided that the Collateral Agent is also hereby appointed as agent for the other Secured Parties for the purposes of protecting their interests in and to any portion of the Collateral and under the Security Documents, and the Collateral Agent shall take such action solely as agent for the Secured Parties.

     Section 6.02. Application of Proceeds. If an Event of Default shall have occurred and be continuing and the Collateral Agent applies (i) any cash held in the Pledged Accounts or (ii) the proceeds of any Disposition of all or any part of the Collateral, such cash and/or proceeds shall be applied to the Secured Obligations in the following order of priorities:

     first, to pay the expenses of such Disposition, including reasonable compensation to agents of and counsel for the Collateral Agent, and all expenses, liabilities and advances incurred or made by the Collateral Agent in connection with the Security Documents, and any other amounts then due and payable to the Collateral Agent in its capacity as such pursuant to Section 9.01 hereof or Section 10.03 of the Credit Agreement;

     second, to pay the unpaid principal of all Borrowings and all unreimbursed LC Disbursements and to Cash Collateralize all outstanding Letters of Credit, all ratably until the principal of all Borrowings and all

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unreimbursed LC Disbursements shall have been paid in full and all Letters of Credit shall have been Cash Collateralized;

     third, to pay all other amounts owed under the Credit Agreement and the other Loan Documents ratably, until all such other amounts shall have been paid in full;

     fourth, to pay all other Secured Obligations ratably, until payment in full of all such other Secured Obligations shall have been made; and

     finally, to pay to the relevant Grantor, or as a court of competent jurisdiction may direct, any surplus then remaining from the proceeds of the Collateral owned by it;

provided that Collateral owned by a Subsidiary Grantor and any proceeds thereof shall be applied pursuant to the foregoing clauses first, second, third and fourth only to the extent permitted by the limitation in Section 2.01(b) of the Subsidiary Guarantee Agreement. The Collateral Agent may make such distributions hereunder in cash or in kind or, on a ratable basis, in any combination thereof.

     Section 6.03. Other Remedies of Secured Parties. Except as the same relates to the Collateral or as otherwise expressly prohibited by this Agreement or any other Security Document, each Secured Party may exercise any right or power, enforce any remedy, give any direction, consent or waiver or make any determination, under or in respect of any provision of any Financing Document to which it is a party. Notwithstanding the foregoing, no Secured Party other than the Collateral Agent shall have the right to take any Enforcement Action with respect to the Collateral or the Subsidiary Guarantee Agreement or seek to exercise and enforce the Transaction Liens, and all such Enforcement Actions shall be effected solely through the Collateral Agent. No reference in this Agreement to the Collateral Agent’s making a demand for payment under the Subsidiary Guarantee Agreement shall be construed to mean that such a demand is required in order to cause any obligation under the Subsidiary Guarantee Agreement to become due and payable, it being understood that obligations under the Subsidiary Guarantee Agreement shall become due and payable at such times as they become due and payable under the terms of the Subsidiary Guarantee Agreement.

ARTICLE 7
Depository Bank

     Section 7.01. Depository Bank. The provisions of Article 9 of the Credit Agreement shall inure to the benefit of the Depository Bank to the same extent as if it were named as an Agent therein.

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ARTICLE 8
[reserved]

ARTICLE 9
Miscellaneous

     Section 9.01. Indemnity and Expenses. (a) Each Credit Party agrees to indemnify (without duplication), defend and save and hold harmless each of the Collateral Agent, the Depository Bank and the Secured Parties and each of their Affiliates and their respective officers, directors, employees, agents and advisors (each, an “Indemnified Party”) from and against, and shall pay, any and all claims, damages, losses, liabilities and expenses (including reasonable fees and expenses of counsel) that may be incurred by or asserted or awarded against any Indemnified Party, in each case arising out of or in connection with (i) this Agreement or the other Security Documents, or (ii) as a result of the execution or delivery of this Agreement or the other Security Documents or the performance by the Credit Parties hereto and thereto of their respective obligations hereunder and thereunder, except in each case of clause (i) and (ii), as to any particular Indemnified Party, to the extent such claim, damage, loss, liability or expense is found in a final, nonappealable judgment by a court of competent jurisdiction to have resulted from, or to be attributable to, the gross negligence or willful misconduct of such Indemnified Party or its employees or agents. The indemnification provisions of this Section 9.01(a) are not intended to constitute a guaranty of payment of any principal, interest, facility or commitment fees, rental or other lease payments, or analogous amounts, under any Secured Obligations; provided that nothing in this Section 9.01(a) shall limit the liability of any Credit Party for the payment of any Secured Obligation, to the extent such liability arises under any other Financing Document, including any liability arising under this Agreement.

     (b) Each Credit Party will pay to the Collateral Agent the amount of any and all reasonable out-of-pocket expenses, including the reasonable fees and expenses of its counsel and of any experts and agents, that the Collateral Agent may incur in connection with (i) the administration of this Agreement and the other Security Documents, (ii) the custody, preservation, or the sale of, collection from or other realization upon, any of the Collateral of such Credit Party, (iii) the exercise or enforcement of any of the rights of the Collateral Agent or any other Secured Party hereunder, or (iv) the failure by such Credit Party to perform or observe any of the provisions hereof required to be performed or observed by it.

     (c) The indemnities provided by the Credit Parties pursuant to this Agreement shall survive the expiration, cancellation, termination or modification of this Agreement or the other Security Documents, the resignation or removal of

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the Collateral Agent, Depository Bank or Secured Parties and the provision of any subsequent or additional indemnity by any Person.

     (d) All amounts due under this Section 9.01 shall be payable not later than 30 days after the delivery of written demand to the Company therefor.

     Section 9.02. Amendments; Waivers, Etc. No amendment, modification or waiver of any provision of this Agreement or any other Security Document, and no consent with respect to any departure by the Collateral Agent, any other Secured Party or any Credit Party herefrom or therefrom, shall be effective unless the same shall be in writing and signed by the Credit Parties and the Collateral Agent in accordance with the Credit Agreement. Any such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given.

     Section 9.03. Security Interest Absolute and Waivers. (a) The obligations of each Credit Party under or in respect of this Agreement or any other Security Document to which such Credit Party is a party are independent of the Secured Obligations or any other obligations of any other Credit Party under or in respect of the Financing Documents, and a separate action or actions may be brought and prosecuted by the Collateral Agent against each Credit Party to enforce this Agreement or any other Security Document to which such Credit Party is a party, irrespective of whether any action is brought against the Company or any other Credit Party or whether the Company or any other Credit Party is joined in any such action or actions. All rights of the Collateral Agent and the other Secured Parties and the Liens granted by the Grantors hereunder, and all obligations of each Credit Party hereunder, shall be unaffected by, and each Credit Party hereby irrevocably waives (to the maximum extent permitted by applicable law) any defenses to its obligations under the Security Documents that it may now have or may hereafter acquire, which defenses in any way relate to, any or all of the following:

     (i) any lack of validity or enforceability of any Financing Document or any other agreement or instrument relating thereto;

     (ii) any change in the time, manner or place of payment of, or in any other term of, all or any of the Secured Obligations or any other obligations of any Credit Party under or in respect of the Financing Documents or any other amendment or waiver of or any consent to any departure from any Financing Document, including any increase in the Secured Obligations resulting from the extension of additional credit to any Credit Party or any of its Subsidiaries or otherwise;

     (iii) any Condemnation, exchange, release or non-perfection of any Collateral or any other collateral, or any release, amendment or waiver

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of, or consent to, or departure from any Guaranty of all or any of the Secured Obligations;

     (iv) any manner of application of any Collateral or any other collateral, or proceeds thereof, to all or any of the Secured Obligations, or any manner of sale or other disposition of any Collateral or any other collateral for all or any of the Secured Obligations or any other obligations of any Credit Party under or in respect of the Financing Documents or any other assets of any Credit Party or any of its Subsidiaries;

     (v) any change, restructuring or termination of the corporate structure or existence of any Credit Party or any of its Subsidiaries;

     (vi) any failure of any Secured Party to disclose to any Credit Party any information relating to the business, condition (financial or otherwise), operations, performance, assets, nature of assets, liabilities or prospects of any other Credit Party now or hereafter known to such Secured Party (each Credit Party waiving any duty on the part of the Secured Parties to disclose such information);

     (vii) the failure of any other Person to execute or deliver this Agreement or any other Security Document, guaranty or agreement or the release or reduction of liability of any Credit Party or other grantor or surety with respect to the Secured Obligations; or

     (viii) any other circumstance (including any statute of limitations) or any existence of or reliance on any representation by any Secured Party that might otherwise constitute a defense available to, or a discharge of, such Credit Party or any other Credit Party or third party grantor of a secured interest, but specifically excluding any defense or discharge arising as a result of performance or indefeasible payment.

     (b) This Agreement shall continue to be effective or be reinstated, as the case may be, if at any time any payment of any of the Secured Obligations is rescinded or must otherwise be returned by any Secured Party or by any other Person upon the insolvency, bankruptcy or reorganization of any Credit Party or otherwise, all as though such payment had not been made.

     (c) Each Credit Party hereby unconditionally and irrevocably waives promptness, diligence, notice of acceptance, presentment, demand for performance, notice of nonperformance, default, notice of intent to accelerate, acceleration, protest or dishonor and any other notice with respect to any of the Secured Obligations and this Agreement or any other Security Document to which such Credit Party is a party and any requirement that any Secured Party protect, secure, perfect or insure any Lien or any property subject thereto or

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exhaust any right or take any action against any Credit Party or any other Person or any Collateral.

     (d) Each Credit Party hereby unconditionally and irrevocably waives any right to revoke this Agreement or any other Security Document to which such Credit Party is a party and acknowledges that this Agreement or any other Security Document to which such Credit Party is a party is continuing in nature and applies to all Secured Obligations, whether existing now or in the future.

     (e) Each Credit Party hereby unconditionally and irrevocably waives (i) any defense arising by reason of any claim or defense based upon an election of remedies by the Collateral Agent that in any manner impairs, reduces, releases or otherwise adversely affects the subrogation, reimbursement, exoneration, contribution or indemnification rights of such Credit Party or other rights of such Credit Party to proceed against any other Credit Party, any other guarantor or any other Person or any Collateral and (ii) any defense based on any right of set-off or counterclaim against or in respect of the obligations of such Credit Party hereunder.

     (f) Each Credit Party and each of the Secured Parties confirms that it is the intention of all such Persons that this Agreement, the other Security Documents and the obligations of each Credit Party hereunder or thereunder do not constitute a fraudulent transfer or fraudulent conveyance for purposes of the Bankruptcy Code, the Uniform Fraudulent Conveyance Act, the Uniform Fraudulent Transfer Act or any similar foreign, federal or state law to the extent applicable to this Agreement, any other Security Document and the obligations of each Credit Party hereunder or thereunder or in connection with any Insolvency Proceeding in respect of any Credit Party. To effectuate the foregoing intention, the Collateral Agent, the other Secured Parties and the Subsidiary Grantors hereby irrevocably agree that the obligations of each Subsidiary Grantor under this Agreement and the other Security Documents at any time shall not exceed the maximum amount as will result in the obligations of such Subsidiary Grantor under this Agreement and the other Security Documents not constituting a fraudulent transfer or fraudulent conveyance (after giving effect to Section 2.02 of the Subsidiary Guarantee Agreement).

     (g) Each Credit Party acknowledges that it will receive substantial direct and indirect benefits from the financing arrangements contemplated by the Security Documents and that the waivers set forth in this Section 9.03 are knowingly made in contemplation of such benefits.

     Section 9.04. Notices; Etc. (a) Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to paragraph (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

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     (i) if to the Company, any Pipeline Borrower or the Collateral Agent, to it at its address specified in or pursuant to Section 10.01 of the Credit Agreement;

     (ii) if to any Grantor, to it c/o the Company at the address specified in or pursuant to clause (i) above;

     (iii) if to the Depository Bank, to it at JPMorgan Chase Bank, N.A., Institutional Trust Services, 4 New York Plaza, 21st Floor, New York, New York 10004, Attention of Linda Ramos-McCollum (Telecopy No. (212) 623-6168.

     (b) Notices and other communications among the Secured Parties, the Collateral Agent and/or the Depository Bank hereunder may be delivered or furnished by electronic communications. The Administrative Agent or a Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

     (c) Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given and effective, if sent by mail or courier on the date of delivery thereof to the address specified herein for such notice, or if by telecopier when the answerback is received or if by other means, on the date of receipt; provided that a notice given by telecopier or electronic communication in accordance with this Section 9.04 but received on any day other than a Business Day or after business hours in the place of receipt, will be deemed to be received on the next Business Day in that place.

     Section 9.05. Continuing Security Interest; Assignments. This Agreement and each other Security Document shall create a continuing security interest in the Collateral and shall (a) remain in full force and effect until terminated in accordance with its terms, (b) be binding upon each Credit Party, its successors and assigns and (c) inure, together with the rights and remedies of the Collateral Agent hereunder, to the benefit of the Secured Parties and their respective successors, transferees and assigns. Without limiting the generality of the foregoing clause (c), each Secured Party may assign, sell or otherwise transfer all or any portion of its rights and obligations in respect of any Secured Obligations held by it to any other Person, and such other Person shall thereupon become vested with all the benefits in respect thereof granted to such Secured Party herein or otherwise, in each case subject to the Financing Documents.

     Section 9.06. [Reserved].

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     Section 9.07. Execution in Counterparts. This Agreement may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by telecopier shall be effective as delivery of an original executed counterpart of this Agreement.

     Section 9.08. Severability. If any provision of this Agreement shall be invalid, illegal or unenforceable, then to the extent permitted by law, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

     Section 9.09. Integration. This Agreement and the other Financing Documents represent the agreement of the parties hereto with respect to the subject matter hereof, and there are no promises, undertakings, representations or warranties by any party relative to subject matter hereof not expressly set forth or referred to herein or in the other Financing Documents.

     Section 9.10. No Partnership. Nothing contained in this Agreement and no action by any Secured Party is intended to constitute or shall be deemed to constitute the Secured Parties (or any of them) a partnership, association, joint venture or other entity.

     Section 9.11. No Reliance. No Secured Party has relied on any representation or warranty of any other Secured Party with respect to this Agreement and the transactions contemplated hereunder unless such representation or warranty has been set forth expressly in this Agreement.

     Section 9.12. Release. On the date hereof, without further action by any party to this Agreement or the Existing Security Agreement, each of the Released Parties shall cease to be a Subsidiary Grantor under the Existing Security Agreement, and shall not be deemed a Subsidiary Grantor under this Agreement.

     Section 9.13. No Impairment. Nothing in this Agreement is intended or shall be construed to impair, diminish or otherwise adversely affect any other rights the Secured Parties may have or may obtain against the Company, any other Credit Party or any other Person.

     Section 9.14. Equitable Remedies. Each party to this Agreement acknowledges that the breach by it of any of the provisions of this Agreement is likely to cause irreparable damage to the other party. Therefore, the relief to which any party shall be entitled in the event of any such breach or threatened breach shall include, but not be limited to, a mandatory injunction for specific performance, injunctive or other judicial relief to prevent a violation of any of the provisions of this Agreement, damages and any other relief to which it may be entitled at law or in equity.

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     Section 9.15. Remedies. (a) Other than as stated expressly herein, no remedy herein conferred upon the Collateral Agent or any other Secured Party is intended to be exclusive of any other remedy and each and every such remedy shall be cumulative and shall be in addition to every other remedy given under this Agreement or the other Financing Documents, or now or hereafter existing at law or in equity or by statute or otherwise.

     (b) As between the Credit Parties and each Secured Party, it is agreed that the amounts payable by the Company at any time in respect of the Secured Obligations shall be a separate and independent debt and each Secured Party shall be entitled, subject to Section 6.03, to protect and enforce its rights arising out of the Financing Documents to which it is a party and its right, pursuant to the terms of any Financing Document to which it is a party, to cancel or suspend its commitments thereunder and to accelerate the maturity of any of the Secured Obligations, in each case in accordance with the applicable Financing Documents, and, except as aforesaid, it shall not be necessary for any other Secured Party to consent to, or be joined as an additional party in, any proceedings for such purposes.

     (c) In case the Collateral Agent shall have proceeded to enforce any right, remedy or power under this Agreement or any other Security Document and the proceeding for the enforcement thereof shall have been discontinued or abandoned for any reason or shall have been determined adversely to the Collateral Agent, then and in every such case the Credit Parties and the Secured Parties shall, subject to any effect of or determination in such proceeding, severally and respectively be restored to their former positions and rights under this Agreement or any other Security Document and thereafter all rights, remedies and powers of the Secured Parties shall continue as though no such proceeding had been taken.

     Section 9.16. Limitations. (a) The obligations, liabilities or responsibilities of any party hereunder shall be limited to those obligations, liabilities or responsibilities expressly set forth and attributed to such party pursuant to this Agreement or otherwise applicable under Applicable Law.

     (b) In no event shall any Secured Party be liable for, and each of the Credit Parties hereby agrees not to assert any claim against any Secured Party, on any theory of liability, for consequential, incidental, indirect, punitive or special damages arising out of or otherwise relating to this Agreement, the other Financing Documents, any of the transactions contemplated herein or therein, or the actual or proposed use of the proceeds of any Loan, Letter of Credit or Secured Hedging Agreement.

     Section 9.17. Survival. Notwithstanding anything in this Agreement to the contrary, Sections 9.01, 9.17, 9.19, 9.20 and 9.21 shall survive any

41

termination of this Agreement. In addition, each representation and warranty made or deemed to be made hereunder shall survive the Effective Date.

     Section 9.18. [Reserved].

     Section 9.19. Jurisdiction, Etc. (a) Each of the parties hereby irrevocably and unconditionally submits, for itself and its property, to the nonexclusive jurisdiction of the Supreme Court of the State of New York, sitting in New York County, and of the United States District Court for the Southern District of New York, and any appellate court from any thereof, in any action or proceeding by the Collateral Agent or any Secured Party arising out of or relating to this Agreement or any of the other Security Documents to which it is a party or under which it is a beneficiary, or for recognition or enforcement of any judgment obtained in any such action or proceeding, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State court or, to the fullest extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that any Secured Party may otherwise have to bring any action or proceeding relating to this Agreement, the Security Documents or any of the other Financing Documents in the courts of any jurisdiction.

     (b) Each of the parties irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection that it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or any of the other Security Documents to which it is a party in any court referred to in paragraph (a) of this Section. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

     (c) Each party to this Agreement irrevocably consents to service of process in any action or proceeding referred to in this Section 9.19 by the mailing thereof by certified mail, return receipt requested, addressed as provided in Section 9.04( ), with a copy thereof to the “General Counsel” of such Person at such same address. Nothing in this Agreement will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

     Section 9.20. GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

     Section 9.21. Waiver of Jury Trial. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE

42

LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (a) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, AND (b) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

43

     IN WITNESS WHEREOF, each party hereto has caused this Agreement to be duly executed and delivered by its officer thereunto duly authorized as of the date first above written.

THE COMPANY	EL PASO CORPORATION
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer
PIPELINE COMPANY BORROWERS:	EL PASO NATURAL GAS COMPANY
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer
	TENNESSEE GAS PIPELINE COMPANY
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer
SUBSIDIARY GRANTORS:	EL PASO EPNG INVESTMENTS, L.L.C.
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer
	EL PASO TENNESSEE PIPELINE CO.
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer

EL PASO TGPC INVESTMENTS, L.L.C.
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer

RELEASED PARTIES:	EL PASO CNG COMPANY, L.L.C.
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer
	EL PASO NORIC INVESTMENTS III, L.L.C.
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer
	EPPP CIG GP HOLDINGS, L.L.C.
	By:	/s/ John J. Hopper
		Name:	John J. Hopper
		Title:	Vice President and Treasurer

COLLATERAL AGENT:	JPMORGAN CHASE BANK, N.A., as Collateral Agent
	By:	/s/ Robert Traband
		Name:	Robert Traband
		Title:	Executive Director
DEPOSITORY BANK:	JPMORGAN CHASE BANK, N.A., as Depository Bank
	By:	/s/ Robert Traband
		Name:	Robert Traband
		Title:	Executive Director

SCHEDULE I

SUBSIDIARY GRANTORS

El Paso EPNG Investments, L.L.C.
El Paso Tennessee Pipeline Co.
El Paso TGPC Investments, L.L.C.

Schedule II
1

SCHEDULE II

INITIAL PLEDGED EQUITY

Percentage

Jurisdiction

of

of

Outstanding

Organization

Class of

Number

Equity

Name of

of

Equity

Certificate

of

Interests of

Grantor

Name of Issuer

Issuer

Interest

Par Value

No.

Shares

Issuer

El Paso EPNG Investments, L.L.C.

El Paso Natural Gas Company

Delaware

Common Stock

1.00

2

1,000

100

%

El Paso Tennessee Pipeline Co.

El Paso TGPC Investments, L.L.C.

Delaware

Membership Interests

n/a

1

n/a

100

%

El Paso TGPC Investments, L.L.C.

Tennessee Gas Pipeline Company

Delaware

Common Stock

5.00

4

208

100

%

Schedule II
1

SCHEDULE III

NAME, LOCATION, CHIEF EXECUTIVE OFFICE, TYPE OF ORGANIZATION, JURISDICTION OF ORGANIZATION,
AND ORGANIZATIONAL IDENTIFICATION NUMBER

			Type of	Jurisdiction of	Organizational
Company Name	Location	Chief Executive Office	Organization	Organization	I.D. No.
El Paso Corporation	Delaware	El Paso Building	Corporation	Delaware		2884676
		1001 Louisiana St.
		Houston, Texas 77002
El Paso EPNG Investments, L.L.C.	Delaware	El Paso Building	Limited Liability	Delaware		3640051
		1001 Louisiana St.	Company
		Houston, Texas 77002
El Paso Tennessee Pipeline Co.	Delaware	El Paso Building	Corporation	Delaware		2140052
		1001 Louisiana St.
		Houston, Texas 77002
El Paso TGPC Investments, L.L.C.	Delaware	El Paso Building	Limited Liability	Delaware		3640033
		1001 Louisiana St.	Company
		Houston, Texas 77002

Schedule III
1

SCHEDULE IV

CHANGES
Scope: Within Last 5 Years Prior to Effective Date

					Changes in
			Changes in		the
	Changes in the	Changes	the Chief	Changes in the	Jurisdiction	Changes in the
	Company	in	Executive	Type of	of	Organizational
Company	Name	Location	Office	Organization	Organization	I.D. No.
El Paso Corporation	None	None	None	None	None	None
El Paso EPNG Investments, L.L.C.	None	None	None	None	None	None
El Paso Tennessee Pipeline Co.	None	None	None	None	None	None
El Paso TGPC Investments, L.L.C.	None	None	None	None	None	None

Schedule IV
1

SCHEDULE V

SECURED HEDGING AGREEMENTS

1. None.

Schedule V
1

EXHIBIT A

FORM OF OFFICER’S CERTIFICATE FOR QUALIFIED INVESTMENTS

     The undersigned hereby certifies that [he/she] is the duly appointed [President, Vice-President, Treasurer, or Chief Financial Officer] of El Paso Corporation, a Delaware corporation (the “Company”), and that, as such, [he/she] is authorized to execute and deliver this certificate of the Company pursuant to Section 4.03(e) of that certain Third Amended and Restated Security Agreement, dated as of November 16, 2007 among the Company, the Pipeline Company Borrowers, the Subsidiary Grantors and JPMorgan Chase Bank N.A. (“JPMCB”), in its capacity as Collateral Agent for the Secured Parties and Depository Bank (as amended, supplemented or otherwise modified from time to time, the “Security Agreement).

     The undersigned hereby directs, on behalf of the Company, that $                     (the “Transfer Amount”) be withdrawn from [the Qualified Investments Account] [identify applicable Qualified Investments Subaccount] and transferred to [                    ] (the “Restricted Subsidiary”) pursuant to Section 4.03(e) of the Security Agreement.

     The undersigned further certifies, on behalf of the Company, that (i) the Transfer Amount resulted from a Disposition of Covered Assets of the Restricted Subsidiary; [(ii) if the Restricted Subsidiary is a FERC-Related Restricted Subsidiary; all funds retained by the Restricted Subsidiary pursuant to Section 4.03(a) of the Security Agreement from the Net Cash Proceeds of all of such Restricted Subsidiary’s Dispositions of Covered Assets prior to the date hereof have been, or (by making the Qualified Investment(s) described in clause (iii) below) will be, used to make Qualified Investments;] and (iii) the Restricted Subsidiary will invest the Transfer Amount as follows, which investment constitutes one or more Qualified Investments: [Describe Qualified Investments to be made with the Transfer Amount].

     Each capitalized term used but not defined herein shall have the meaning ascribed thereto in the Security Agreement.

     This certificate shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York.

     IN WITNESS WHEREOF, I have set my hand on this certificate this ___day of                     , ___.

EL PASO CORPORATION

By:

Name:

Title:

Exhibit A
1

SCHEDULE VI

MATERIAL AGREEMENTS OF EL PASO CORPORATION

     a. Indenture, dated as of July 21, 2003, between El Paso Natural Gas Company and Wilmington Trust Company, as Trustee.

     (i) First Supplemental Indenture, dated as of April 4, 2007.

     b. Indenture, dated as of May 10, 1999, between El Paso Corporation (f/k/a El Paso Energy Corporation) and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by HSBC Bank USA).

     (i) First Supplemental Indenture dated as of May 10, 1999 ($500 Million 6.75% Senior Notes due May 15, 2009).

     (ii) Sixth Supplemental Indenture dated as of May 14, 2001 ($500 Million 7% Notes due May 15, 2011).

     (iii) Seventh Supplemental Indenture dated as of June 10, 2002 ($600 Million 7.875% Notes due June 15, 2012 (Private Placement)).

     (iv) Eighth Supplemental Indenture dated as of June 26, 2002 (up to $575 Million 6.14% Senior Notes due 8/16/07).

     (v) Ninth Supplemental Indenture dated as of July 1, 2005 (Remarked $272,102,350 of 6.14% Senior Note due August 16, 2007 issued pursuant to the Eight Supplemental Indenture dated June 26, 2002 (held as collateral for the Purchase Contract portion of the Equity Security Units) for $272,102,000 of 7.625% Senior Notes due August 16, 2007).

     (vi) Tenth Supplemental Indenture dated as of December 28, 2005 (10.75% Senior Notes due 2010, 9.625% Senior Notes due 2012, 7.75% Senior Notes due 2032, 7.42% due 2037, 6.95% Senior Notes due 2028, 6.375% Senior Notes due 2009, 7.75% Senior Notes due 2010, 6.50% Senior Notes due 2008, 7.625% Senior Notes due 2008, 6.50% Senior Notes due 2006, 6.70% Senior Notes due 2027, 7.50% Senior Notes due 2007).

     (vii) Eleventh Supplemental Indenture dated as of August 31, 2006 (for the issuance of up to $150,000,000 of 7.75% Medium Term Notes due 2032 or 2035, as applicable, to be exchanged for 7.75% Senior Notes due 2032 or 7.75% Senior Debentures due October 15, 2035).

     (viii) $300 Million 8.05% Global Medium Term Notes (Senior Fixed Rate Notes), due October 15, 2030, as described in the Pricing Supplement No. 1 dated

Exhibit A
1

October 5, 2000 to Supplemental Prospectus dated December 14, 1999 and Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (ix) $300 Million 7.375% Global Medium Term Notes (Senior Fixed Rate Notes), due December 15, 2012, as described in the Pricing Supplement No. 2 dated December 6, 2000 to Supplemental Prospectus dated December 14, 1999 and Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (x) $300 Million 6.95% Global Medium Term Notes (Senior Fixed Rate Notes), due December 15, 2007, as described in the Pricing Supplement No. 3 dated December 14, 2000, to Supplemental Prospectus dated December 13, 2000, to Base Prospectus dated December 3, 1999, Registration No. 333-86049.

     (xi) $700 Million 7.8% Global Medium Term Notes (Senior Fixed Rate Notes), due August 1, 2031, as described in the Pricing Supplement No. 01 dated July 25, 2001, to Supplemental Prospectus dated July 24, 2001, to Base Prospectus dated May 4, 2001, Registration No. 333-59704.

     (xii) $1,100 Million 7.75% Global Medium Term Notes (Senior Fixed Rate Notes), due January 15, 2032, as described in the Pricing Supplement No. 01 dated January 9, 2002 to Prospectus Supplement dated January 7, 2002, to Base Prospectus dated May 4, 2001.

     (xiii) Twelfth Supplemental Indenture dated as of June 18, 2007 ($375,000,000 6.875% Senior Notes due 2014, $900,000,000 7.000% Senior Notes due 2017).

     c. Indenture dated as of March 1, 1998 between El Paso Natural Gas Company (by assignment now El Paso Corporation) and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Law Debenture Trust Company).

     (i) First Supplemental Indenture dated as of March 17, 1998 ($334.75 Million 4.75% Convertible Subordinated Debentures due March 17, 2028, El Paso Energy Capital Trust I).

     (ii) Second Supplemental Indenture dated August 1, 1998 (the Holding Company formation transaction which authorized the merger of El Paso Natural Gas Company with El Paso Merger Company, with El Paso Natural Gas Company as the surviving corporation, and then El Paso Natural Gas Company stock was converted to into El Paso Energy Corporation (now El Paso Corporation) common stock and the debt was assumed by El Paso Corporation).

     (iii) Amended and Restated Declaration of Trust of El Paso Energy Capital Trust I, dated as of March 16, 1998, among El Paso Natural Gas Company, Chase Manhattan Bank, Chase Manhattan Bank Delaware and Administrative Trustees.

Schedule IV
2

     d. Indenture, dated as of November 13, 1996, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank).

     (i) First Supplemental Indenture dated as of June 10, 2002 ($300 Million 8.375% Notes due June 15, 2032).

     (ii) Second Supplemental Indenture dated as of April 4, 2007 ($355 Million 5.95% Notes due April 15, 2017).

     e. Indenture, dated as of January 1, 1992, between El Paso Natural Gas Company and Wilmington Trust Company (as successor to Citibank, N.A.).

     f. Indenture, dated as of June 1, 1986, between Sonat Inc. (by merger now El Paso Corporation) and Manufacturers Hanover Trust Company (by merger now JPMorgan Chase Bank and subsequently replaced by HSBC BANK USA).

     (i) First Supplemental Indenture dated as of June 1, 1995 (Various amendments).

     (ii) Second Supplemental Indenture dated as of October 25, 1999 (assumption of Sonat obligations under Indenture dated June 1, 1986).

     (iii) $100 Million 6.75% Notes due October 1, 2007, as described in the Prospectus Supplement dated September 25, 1997 to Prospectus dated July 27, 1993.

     (iv) $100 Million 6.625% Notes due February 1, 2008, as described in the Prospectus Supplement dated January 27, 1998 to Prospectus dated July 27, 1993.

     (v) $100 Million 7% Notes due February 1, 2018, as described in the Prospectus Supplement dated January 29, 1998 to Prospectus dated July 27, 1993.

     (vi) $600 Million 7.625% Notes due July 15, 2011, as described in the Prospectus Supplement dated July 7, 1999 to Prospectus dated September 9, 1998.

     g. Indenture, dated as of March 30, 1992, between Valero Energy Corporation (by merger PG&E Gas Transmission, Texas Corporation, then El Paso Gas Transmission Company (“GTT”) and now El Paso Corporation) and Bankers Trust Company (by merger now Deutsche Bank Trust Company Americas).

     (i) First Supplemental Indenture dated as of March 13, 1995 (authorized the issuance of $284 Million in Medium-Term Notes, various interest rates and maturities, 9 months to 30 years).

Schedule IV
3

     (ii) Second Supplemental Indenture dated as of March 11, 2002 (conform Indenture dated March 30, 1992 to El Paso Corporation May 10, 1999 Indenture).

     (iii) Third Supplemental Indenture dated as of April 5, 2002 (merged GTT into El Paso Corporation).

     h. Indenture, dated as of October 1, 1990 between El Paso CGP Company, L.L.C. (f/k/a El Paso CGP Company and The Coastal Corporation) and The Bank of New York Trust Company, N.A. (f/k/a The Bank of New York) ($150 Million 10.75% Senior Debentures due October 1, 2010).

     (i) First Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso CGP Company, L.L.C. October 1, 1990 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (ii) Second Supplemental Indenture, dated as of December 31, 2005 among El Paso CGP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso CGP Company, L.L.C., assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso CGP Company, L.L.C.).

     i. Indenture, dated as of May 15, 1992 between El Paso CGP Company, L.L.C. (f/k/a El Paso CGP Company and The Coastal Corporation) and Bank of Montreal Trust Company (subsequently replaced by The Bank of New York Trust Company, N.A.).

     (i) First Supplemental Indenture, dated as of May 20, 1992 ($150 Million 9.625% Senior Debentures due May 15, 2012).

     (ii) Second Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso COP Company, L.L.C. May 15, 1992 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (iii) Third Supplemental Indenture, dated as of December 31, 2005 among El Paso COP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso COP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso COP Company, L.L.C.).

     j. Indenture, dated as of September 15, 1992 between El Paso COP Company, L.L.C. (f/k/a El Paso COP Company and The Coastal Corporation) and NationsBank, N.A. (subsequently replaced by The Bank of New York Trust Company, RA.).

     (i) Second Supplemental Indenture dated as of October 19, 1995 ($150 Million 7.75% Senior Debentures due October 15, 2035).

Schedule IV
4

     (ii) Third Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso COP Company, L.L.C. September 15, 1992 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (iii) Fourth Supplemental Indenture, dated as of December 31, 2005 among El Paso COP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso COP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso COP Company, L.L.C.).

     k. Indenture, dated as of February 24, 1997 between El Paso COP Company, L.L.C. (f/k/a El Paso COP Company and The Coastal Corporation) and Harris Trust and Savings Bank (subsequently replaced by The Bank of New York Trust Company, N.A.).

     (i) First Supplemental Indenture dated as of February 24, 1997 ($200 Million 6.70% Senior Debentures due February 15, 2027, put date February 15, 2007).

     (ii) Second Supplemental Indenture dated as of February 24, 1997 ($200 Million 7.42% Senior Debentures due February 15, 2037).

     (iii) Third Supplemental Indenture dated as of June 5, 1998 ($200 Million 6.5% Senior Debentures due June 1, 2008).

     (iv) Fourth Supplemental Indenture dated as of June 5, 1998 ($200 Million 6.95% Senior Debentures due June 1, 2028).

     (v) Fifth Supplemental Indenture dated as of February 10, 1999 ($200 Million 6.375% Senior Debentures due February 1, 2009).

     (vi) Eighth Supplemental Indenture dated as of June 16, 2000 ($400 Million 7.75% Notes due June 15, 2010).

     (vii) Eleventh Supplemental Indenture dated as of September 6, 2000 ($215 Million 7.625% Notes due 9/1/08).

     (viii) Twelfth Supplemental Indenture, dated as of December 27, 2005 (various amendments required to conform El Paso CGP Company, L.L.C. February 24, 1997 Indenture to El Paso Corporation May 10, 1999 Indenture).

     (ix) Thirteenth Supplemental Indenture, dated as of December 31, 2005 among El Paso CGP Company, L.L.C., El Paso Corporation and The Bank of New York Trust Company, N.A. (substantially all of El Paso CGP Company, L.L.C. assets were transferred to El Paso Corporation and El Paso Corporation assumed the debt of El Paso CGP Company, L.L.C.).

Schedule IV
5

     l. Indenture, dated as of March 4, 1997, between Tennessee Gas Pipeline Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank).

     (i) First Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.5% Debentures due April 1, 2017).

     (ii) Second Supplemental Indenture dated as of March 13, 1997 ($300 Million 7% Debentures due March 15, 2027).

     (iii) Third Supplemental Indenture dated as of March 13, 1997 ($300 Million 7.625% Debentures due April 1, 2037).

     (iv) Fourth Supplemental Indenture dated as of October 9, 1998 ($400 Million 7% Debentures due October 15, 2028).

     (v) Fifth Supplemental Indenture dated June 10, 2002 ($240 Million 8.375% Senior Notes due June 15, 2032).

     m. Indenture, dated as of March 15, 1988, between Tenneco, Inc. (now El Paso Tennessee Pipeline Co.) and The Chase Manhattan Bank (now by merger JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company).

     (i) Second Supplemental Indenture dated as of March 30, 1988 ($250 Million 10% Debentures due March 15, 2008, outstanding balance $26.4 Million).

     (ii) Tenth Supplemental Indenture dated as of November 15, 1992 ($150 Million 9% Debentures due November 15, 2012, outstanding principal $1.1 Million).

     (iii) Twelfth Supplemental Indenture dated as of December 15, 1995 ($300 Million 7.25% Debentures due December 15, 2025, outstanding principal $23.2 Million).

     (iv) Thirteenth Supplemental Indenture dated as of December 10, 1996.

     n. Indenture, dated as of December 15, 1981, between Tenneco Inc. (now Tennessee Gas Pipeline Company) and The Chase Manhattan Bank (by merger now JPMorgan Chase Bank and subsequently replaced by Wilmington Trust Company) ($400 Million 6% Debentures due December 15, 2011, current balance $85.8 Million).

     (i) First Supplemental Indenture dated as of December 10, 1996.

     (ii) Second Supplemental Indenture dated as of December 10, 1996.

Schedule IV
6

     o. Fiscal Agency Agreement dated May 6, 2002 among El Paso Corporation, Citibank, N.A. and Societe Generale Bank and Trust, 6 S.A. relating to €500 Million 7.125% Euro Notes due May 6, 2009.

     p. Credit Agreement dated as of June 20, 2007, among El Paso Corporation, the Lenders party thereto, Citicorp USA, Inc., as Administrative Agent and as Issuing Agent, and the Bank of New York as Paying Agent.

     (i) The Reimbursement Agreement dated as of June 20, 2007, between El Paso Corporation and Citibank, N. A.

     (ii) Credit Agreement First Amendment dated as of August 28, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (iii) Credit Agreement Second Amendment dated as of September 6, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (iv) Credit Agreement Third Amendment dated as of September 17 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (v) Credit Agreement Fourth Amendment dated as of September 20, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (vi) Credit Agreement Fifth Amendment dated as of September 28, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (vii) Credit Agreement Sixth Amendment dated as of October 3, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (viii) Credit Agreement Seventh Amendment dated as of October 11, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     (ix) Credit Agreement Eighth Amendment dated as of October 18, 2007, among El Paso Corporation, Citicorp USA, Inc. and The Bank of New York.

     q. Other Credit and Facility Agreements

     (i) Discretionary Facility Agreement dated as of February 21, 2003, between El Paso Corporation and Compass Bank.

     (ii) Credit Agreement dated July 19, 2006 among El Paso Corporation and Deutsche Bank AG New York Branch as Initial Lender and Issuing Bank and Deutsche Bank AG New York Branch as Administrative Agent and Collateral Agent.

Schedule IV
7

     (iii) First Tier Receivables Sale Agreement dated August 31, 2006, between Tennessee Gas Pipeline Company and TGP Finance Company, L.L.C.

     (iv) Second Tier Receivables Sale Agreement dated August 31, 2006, between TGP Finance Company, L.L.C. and TGP Funding Company, L.L.C.

     (v) Receivables Purchase Agreement dated August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, Starbird Funding Corporation, the other investors from time to time parties thereto, BNP Paribas, New York Branch, and the other Managing Agents from time to time parties thereto.

(a) Amendment No 1, dated as of December 1, 2006, to the Receivables Purchase Agreement dated as of August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, Starbird Funding Corporation and the other funding entities from time to time party thereto, BNP Paribas, New York Branch, and the other financial institutions from time to time party thereto.

     (vi) Facility Agreement dated as of January 4, 2007, between El Paso Corporation and Morgan Stanley Capital Services Inc.

     r. Letters of Credit with a Face Amount Exceeding $50,000,000

     (i) Application and Agreement for irrevocable Standby Letter of Credit, dated as of December 15, 2004, by El Paso Corporation to JPMorgan Chase Bank, N.A., in favor of Midland Cogeneration Venture Limited Partnership for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $110 Million 100 Thousand.

     (ii) Application for Irrevocable Standby Letter of Credit, dated as of July 29, 2006 by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Midland Cogeneration Venture Limited Partnership for the account of El Paso Merchant Energy, L.P. for the aggregate amount not exceeding $74 Million.

     (iii) Application for Irrevocable Standby Letter of Credit, dated as of September 1, 2005, by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Williams Power Company for the account of El Paso Merchant Energy, L.P. for the aggregate amount not exceeding $219 Million 900 Thousand.

     (iv) Application for Standby Letter of Credit, dated as of November 10, 2006, by El Paso Corporation to BNP Paribas in favor of Southeast Supply Header, LLC for the account of Southern Natural Gas Company in the amount of $60 Million.

     (v) Application for Standby Letter of credit, dated as of July 19, 2006, by El Paso Corporation to Deutsche Bank AG, New York Branch, in favor of Morgan Stanley

Schedule IV
8

Capital Group Inc. for the account of El Paso Marketing, L.P. in the amount of $184 Million.

     (vi) Application for Irrevocable Standby Application for Irrevocable Standby Letter of Credit, dated as of February 6, 2007, by El Paso Corporation to Fortis Bank S.A./N.V., in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $162 Million 100 Thousand.

     (vii) Application for Irrevocable Standby Letter of Credit, dated as of September 24, 2003, by El Paso Corporation to JPMorgan Chase Bank, N.A., in favor of Morgan Stanley Capital Group Inc. for the account of El Paso Marketing, L.P. for the aggregate amount not exceeding $85 Million 750 Thousand.

     s. ISDA Master Agreements

     (i) 1992 ISDA Master Agreement dated October 24, 2001, between El Paso Corporation and Credit Suisse First Boston International.

     (ii) 1992 ISDA Master Agreement dated March 5, 2001, between El Paso Corporation and Westdeutsche Landesbank Girozentrale.

     (iii) 2002 ISDA Master Agreement dated August 29, 2003 between El Paso Corporation and Citibank, N.A.

     (iv) 2002 ISDA Master Agreement dated June 24, 2004, between El Paso Corporation and Deutsche Bank A.G.

     (v) 2002 ISDA Master Agreement dated November 22, 2004, between El Paso Corporation and Citigroup Financial Products Inc.

     t. Various Guaranties and Other Documents

     (i) Guaranty Agreements dated as of July 12, 2005 and December 13, 2006, by El Paso Corporation in favor of Mt. Franklin Insurance Ltd.

     (ii) Guaranty Agreement dated as of February 15, 2006, by El Paso Corporation in favor of Coastal Offshore Insurance Ltd.

     (iii) Guaranty Agreement dated as of April 25, 2006 by El Paso Corporation in favor of Petroleo Brasileiro S.A. – Petrobas.

     (iv) Terms of 4.99% Convertible Perpetual Preferred Stock, pursuant to the Offering Memorandum dated as of April 11, 2005 by El Paso Corporation.

Schedule IV
9

EX-12

Exhibit 12

EL PASO CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(DOLLARS IN MILLIONS)

	For the years ended December 31,
	2009			2008			2007			2006			2005
Earnings
Income (loss) before income taxes from continuing operations	$	(873	)	$	(1,034	)	$	664		$	523		$	(826	)
Income from equity investees		(67	)		(48	)		(101	)		(145	)		(281	)
Income (loss) before income taxes from continuing operations before adjustment for income from equity investees		(940	)		(1,082	)		563			378			(1,107	)
Fixed charges		1,074			972			1,074			1,354			1,441
Distributed income of equity investees		88			180			189			139			209
Capitalized interest		(48	)		(45	)		(51	)		(45	)		(45	)
Preferred returns on consolidated subsidiaries		(5	)		—			(6	)		(1	)		(11	)
Total earnings available for fixed charges	$	169		$	25		$	1,769		$	1,825		$	487
Fixed charges
Interest and debt expense	$	1,056		$	959		$	1,055		$	1,340		$	1,413
Interest component of rent		13			13			13			13			17
Preferred returns on consolidated subsidiaries		5			0			6			1			11
Total fixed charges	$	1,074		$	972		$	1,074		$	1,354		$	1,441
Ratio of earnings to fixed charges(1)		—			—			1.65			1.35			—
Fixed charges
Interest and debt expense	$	1,056		$	959		$	1,055		$	1,340		$	1,413
Interest component of rent		13			13			13			13			17
Preferred returns on consolidated subsidiaries		5			—			6			1			11
Preferred stock dividend of parent		37			37			56			36			27
Total fixed charges and preferred stock dividend	$	1,111		$	1,009		$	1,130		$	1,390		$	1,468
Ratio of earnings to combined fixed charges and preferred stock dividends(2)		—			—			1.57			1.31			—

(1)	Earnings for the years ended December 31, 2009, 2008 and 2005 were inadequate to cover fixed charges by $905 million, $947 million, and $954 million, respectively.
(2)	Earnings for the years ended December 31, 2009, 2008 and 2005 were inadequate to cover fixed charges and preferred stock dividends by $942 million, $984 million, and $981 million, respectively.

For purposes of computing these ratios, earnings means income (loss) before income taxes from continuing operations before:

— income or loss from equity investees, adjusted to reflect actual distributions from equity investments; and

— fixed charges;

less:

— capitalized interest

Fixed charges means the sum of the following:

— interest costs, not including interest on tax liabilities which is included in income tax expense our income statement

— amortization of debt costs

— that portion of rental expense which we believe represents an interest factor; and

— preferred stock dividends and preferred returns on consolidated subsidiaries.

EX-21

Exhibit 21.1

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Agua del Cajon (Cayman) Company	Cayman Islands	El Paso Neuquen Holding Company	Owner of Ordinary Stock		50.0000
		EPED B Company	Owner of Preferred Stock		50.0000
Alpheus Communications, L.P.	Delaware	Zipline, L.L.C.	Unaffiliated Parties — GP Owner		0.5100
		Genesis Park, L.P.	Unaffiliated Parties — LP Owner		7.0100
		Directors/Officers/Other Individuals	Unaffiliated Parties — LP Owner		19.2200
		El Paso Global Networks Company	Limited Partner		34.5400
		Genesis Park Telecom Partners, L.P.	Unaffiliated Parties — LP Owner		38.7200
ANR Advance Holdings, Inc.	Delaware	El Paso Midwest Company	Stockholder		50.0000
		Unaffiliated Parties	Unaffiliated Parties		50.0000
ANR Development Company, L.L.C.	Delaware	El Paso CGP Company, L.L.C.	Member		100.0000
ANR Real Estate Corporation	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
Aquamarine Power Holdings, L.L.C.	Delaware	EPED B Company	Member		100.0000
BBPP Holdings Ltda.	Brazil	British Gas International Holdings B.V.	Unaffiliated Parties		33.3333
		EPIC Gas International Servicos do Brasil Ltda.	Owner		33.3333
		TotalFinaElf Gas and Power Brazil	Unaffiliated Parties		33.3334
Bear Creek Storage Company, L.L.C.	Louisiana	Southern Natural Gas Company	Member		50.0000
		Tennessee Gas Pipeline Company	Member		50.0000
Berkshire Feedline Acquisition Limited Partnership	Massachusetts	Berkshire Pittsfield, Inc.	Unaffiliated Parties — GP Owner		1.0000
		General Electric Capital Corporation	Unaffiliated Parties — GP Owner		49.0000
		El Paso Energy International Company	Limited Partner		50.0000
Black Warrior Methane Corp.	Alabama	El Paso E&P Company, L.P.	Stockholder		50.0000
		Jim Walter Resources, Inc.	Unaffiliated Parties		50.0000
Black Warrior Transmission Corp.	Alabama	El Paso E&P Company, L.P.	Stockholder		50.0000
		Jim Walter Resources, Inc.	Unaffiliated Parties		50.0000
Cheyenne Plains Gas Pipeline Company, L.L.C.	Delaware	Cheyenne Plains Investment Company, L.L.C.	Member		100.0000
Cheyenne Plains Investment Company, L.L.C.	Delaware	GIP-B1 Master Partnership, L.P.	Unaffiliated Parties		6.8200
		Global Infrastructure Partners — A, L.P.	Unaffiliated Parties		17.6150
		GIP-C Holding Partnership, L.P.	Unaffiliated Parties		25.5650
		El Paso Cheyenne Holdings, L.L.C.	Member		50.0000
CIG Finance Company, L.L.C.	Delaware	Colorado Interstate Gas Company	Member		100.0000
CIG Funding Company, L.L.C.	Delaware	CIG Finance Company, L.L.C.	Member		100.0000
CIG Gas Storage Company	Delaware	El Paso CNG Company, L.L.C.	Stockholder		100.0000
CIG Merchant Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
CIG Pipeline Services Company, L.L.C.	Delaware	El Paso Noric Investments III, L.L.C.	Member		100.0000
Citrus Corp.	Delaware	CrossCountry Citrus, LLC	Unaffiliated Parties		50.0000
		El Paso Citrus Holdings, Inc.	Stockholder		50.0000
Citrus Energy Services, Inc.	Delaware	Citrus Corp.	Stockholder		100.0000
Cliffside Helium, LLC	Delaware	EPWP Resources Company	Member		4.0000

Page 1

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		The BOC Group, Inc.	Unaffiliated Parties		26.0000
		Praxair, Inc.	Unaffiliated Parties		34.0000
		Air Products Manufacturing Corp.	Unaffiliated Parties		36.0000
Cliffside Refiners, L.P.	Delaware	Cliffside Helium, LLC	General Partner		1.0000
		EPWP Resources Company	Limited Partner		3.9600
		The BOC Group, Inc.	Unaffiliated Parties — LP Owner		25.7400
		Wall Chemical, Inc.	Unaffiliated Parties — LP Owner		33.6600
		Air Products Helium, Inc.	Unaffiliated Parties — LP Owner		35.6400
Coastal Canada Petroleum, Inc.	New Brunswick	Coscol Petroleum Corporation	Owner		100.0000
Coastal Eagle Point Oil Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Coastal Energy Resources Ltd.	Mauritius	Coscol Petroleum Corporation	Owner		100.0000
Coastal Europe Limited	United Kingdom	Coastal Stock Company Limited	Owner		100.0000
Coastal Mart, Inc.	Delaware	El Paso Remediation Company	Stockholder		100.0000
Coastal Offshore Insurance Ltd.	Bermuda	El Paso CNG Company, L.L.C.	Owner		100.0000
Coastal Oil New England, Inc.	Massachusetts	Coscol Petroleum Corporation	Stockholder		100.0000
Coastal Petrochemical International A.V.V.	Aruba	Coscol Petroleum Corporation	Owner		100.0000
Coastal Petroleum N.V.	Aruba	Coastal Stock Company Limited	Owner		100.0000
Coastal Petroleum N.V. Chile Limitada	Chile	El Paso Energy International Company	Owner		0.0030
		Coastal Petroleum N.V.	Owner		99.9970
Coastal Power International II Ltd.	Cayman Islands	El Paso CGP Company, L.L.C.	Owner		100.0000
Coastal Stock Company Limited	Bermuda	Coscol Petroleum Corporation	Owner		100.0000
Coastal Subic Bay Terminal, Inc.	Philippines	Coscol Petroleum Corporation	Owner		100.0000
Coastal Wartsila Petroleum Private Limited	India	Coastal Energy Resources Ltd.	Owner		50.0000
		Unaffiliated Party/Parties unknown	Unaffiliated Parties		50.0000
Colbourne Insurance Company Limited	United Kingdom	El Paso CGP Company, L.L.C.	Owner		100.0000
Colorado Interstate Gas Company	Delaware	El Paso Noric Investments III, L.L.C.	Partner		42.0000
		EPPP CIG GP Holdings, L.L.C.	Partner		58.0000
Colorado Interstate Issuing Corporation	Delaware	Colorado Interstate Gas Company	Stockholder		100.0000
Copper Eagle Gas Storage, LLC	Delaware	El Paso Natural Gas Company	Member		100.0000
Coronado Energy E&P Company, L.L.C.	Delaware	El Paso E&P Company, L.P.	Member		100.0000
Coscol Holding Company Ltd.	Cayman Islands	Coscol Petroleum Corporation	Owner		100.0000
Coscol Petroleum Corporation	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
Cross Country Development L.L.C.	Delaware	Wilson Sporting Goods Co.	Unaffiliated Parties		45.1700
		El Paso Natural Gas Company	Member		54.8300
Crystal E&P Company, L.L.C.	Delaware	El Paso E&P Company, L.P.	Member		100.0000
Crystal Gas Storage, Inc.	Delaware	El Paso Remediation Company	Stockholder		100.0000
Eastern Insurance Company Limited	Bermuda	El Paso Corporation	Stockholder		100.0000
El Paso Amazonas Energia Ltda.	Brazil	El Paso Energia do Brasil Ltda.	Owner		0.0001

Page 2

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		EPED B Company	Owner		99.9999
El Paso Brazil Holdings Company	Cayman Islands	El Paso Brazil, L.L.C.	Owner		100.0000
El Paso Brazil, L.L.C.	Delaware	El Paso Cayman BAS-97 Company	Member		12.5000
		El Paso Cayman BM-CAL-4 Company	Member		12.5000
		El Paso Cayman BM-CAL-5 Company	Member		12.5000
		El Paso Cayman BM-ES-5 Company	Member		12.5000
		El Paso Cayman Brazil Ventures Company	Member		12.5000
		El Paso Cayman CAL-M-312 Company	Member		12.5000
		El Paso Cayman CAL-M-372 Company	Member		12.5000
		El Paso Production International Cayman Company	Member		12.5000
El Paso Canada Pipeline Company	Nova Scotia	El Paso Pipeline Holding B.V.	Owner		100.0000
El Paso Capital Trust II	Delaware	El Paso Corporation	Sponsor		100.0000
El Paso Cayger III Company	Cayman Islands	EPED B Company	Owner		100.0000
El Paso Cayger IV Company	Cayman Islands	El Paso Energy Cayger II Company	Owner		100.0000
El Paso Cayman BAS-97 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-CAL-4 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-CAL-5 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-ES-5 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman BM-POT-13 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman Brazil Ventures Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman CAL-M-312 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso Cayman CAL-M-372 Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		5.0000
		El Paso E&P International Holding Company	Owner		95.0000
El Paso CGP Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso Cheyenne Holdings, L.L.C.	Delaware	El Paso CNG Company, L.L.C.	Member		100.0000
El Paso Citrus Holdings, Inc.	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso CNG Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso Compression Services de Mexico, S. de R.L. de C.V.	Mexico	El Paso Gas Transmission de Mexico, S. de R.L. de C.V.	Owner		0.0134
		Grupo El Paso, S. de R.L. de C.V.	Owner		99.9866
El Paso Corporate Foundation	Texas	El Paso Corporation	Member		100.0000
El Paso Corporation	Delaware	Unaffiliated Parties	Stockholder		100.0000

Page 3

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
El Paso E&P Cayman Finance Ltd.	Cayman Islands	El Paso E&P International Holding Company	Owner		100.0000
El Paso E&P Company, L.P.	Delaware	El Paso Exploration & Production Management, Inc.	General Partner		1.0000
		El Paso E&P Holdings Company, L.L.C.	Limited Partner		99.0000
El Paso E&P Finance Company, L.L.C.	Delaware	El Paso E&P Cayman Finance Ltd.	Member		100.0000
El Paso E&P Holdings Company, L.L.C.	Delaware	El Paso Exploration & Production Management, Inc.	Stockholder		100.0000
El Paso E&P International Holding Company	Delaware	El Paso Exploration & Production Company	Stockholder		100.0000
El Paso E&P S. Alamein Cayman Company	Cayman Islands	El Paso Preferred Holdings Company	Owner		10.0000
		El Paso E&P International Holding Company	Owner		90.0000
El Paso E&P S. Feiran Cayman Company	Cayman Islands	El Paso Preferred Holdings Company	Owner of Preferred Stock		5.0000
		El Paso E&P International Holding Company	Owner of Ordinary Stock		95.0000
El Paso E&P S. Mariut Cayman Company	Cayman Islands	El Paso Preferred Holdings Company	Owner of Preferred Stock		5.0000
		El Paso E&P International Holding Company	Owner of Ordinary Stock		95.0000
El Paso E&P Tanta Cayman Company	Cayman Islands	El Paso Preferred Holdings Company	Owner of Preferred Stock		5.0000
		El Paso E&P International Holding Company	Owner of Ordinary Stock		95.0000
El Paso E&P Zapata, L.P.	Texas	El Paso South Texas E&P Company, L.L.C.	General Partner		1.0000
		El Paso E&P Company, L.P.	Limited Partner		99.0000
El Paso Egypt Production Company	Cayman Islands	El Paso E&P S. Mariut Cayman Company	Owner		100.0000
El Paso Egypt S. Alamein Company	Cayman Islands	El Paso E&P S. Alamein Cayman Company	Owner		100.0000
El Paso Egypt S. Feiran Company	Cayman Islands	El Paso E&P S. Feiran Cayman Company	Owner		100.0000
El Paso Egypt Tanta Company	Cayman Islands	El Paso E&P Tanta Cayman Company	Owner		100.0000
El Paso El Sauz B.V.	Netherlands	EPED Holding Company	Owner		100.0000
El Paso Elba Express Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso Energia do Brasil Ltda.	Brazil	El Paso International Finance Company	Owner		0.0001
		El Paso Oleo e Gas do Brasil Ltda.	Owner		0.0001
		El Paso Energy Brazil Corporation	Owner		99.9998
El Paso Energia Servicios S de R.L. de C.V.	Mexico	El Paso Mexico Management S. de R.L. de C.V.	Owner		0.0300
		Grupo El Paso, S. de R.L. de C.V.	Owner		99.9700
El Paso Energy Argentina Limitada S.A.	Argentina	Triunion Energy Inversiones Company	Owner		4.9000
		Triunion Energy Company	Owner		95.1000
El Paso Energy Argentina Service Company	Delaware	EPED Holding Company	Stockholder		100.0000
El Paso Energy Brazil Corporation	Cayman Islands	EPED B Company	Owner		100.0000
El Paso Energy Capital Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
El Paso Energy Capital Trust I	Delaware	El Paso Corporation	Sponsor		100.0000
El Paso Energy Cayger II Company	Cayman Islands	Aquamarine Power Holdings, L.L.C.	Owner		100.0000
El Paso Energy E.S.T. Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Energy International Company	Delaware	El Paso Tennessee Pipeline Co.	Stockholder		100.0000
El Paso Energy Marketing de Mexico, S de RL de CV	Mexico	El Paso Merchant Energy Company	Owner		0.1100

Page 4

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		El Paso Mexico Holding B.V.	Owner		99.8900
El Paso Energy Portland Corporation	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
El Paso Energy Service Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso EPNG Investments, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso Exploration & Production Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Exploration & Production Management, Inc.	Delaware	El Paso Exploration & Production Company	Stockholder		100.0000
El Paso Field Services, L.L.C.	Delaware	El Paso CGP Company, L.L.C.	Member		100.0000
El Paso Fife I Company	Cayman Islands	EPED B Company	Owner		100.0000
El Paso Gas Services Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Gas Transmission de Mexico, S. de R.L. de C.V.	Mexico	El Paso Compression Services de Mexico, S. de R.L. de C.V.	Owner		0.0001
		Grupo El Paso, S. de R.L. de C.V.	Owner		99.9999
El Paso Global Networks Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Industrial Energy Company, L.L.C.	Delaware	El Paso Marketing, L.P.	Member		100.0000
El Paso International Finance Company	Cayman Islands	EPED Holding Company	Owner		100.0000
El Paso Maritime B.V.	Netherlands	El Paso Oleo e Gas do Brasil Ltda.	Owner		100.0000
El Paso Marketing, L.P.	Delaware	El Paso Merchant Energy Company	General Partner		1.0000
		El Paso Merchant Energy-Gas Company, L.L.C.	Limited Partner		99.0000
El Paso Merchant Energy Company	Delaware	EPEC Corporation	Stockholder		100.0000
El Paso Merchant Energy North America Company, L.L.C.	Delaware	El Paso Tennessee Pipeline Co.	Member		100.0000
El Paso Merchant Energy-Gas Company, L.L.C.	Delaware	El Paso Merchant Energy Company	Member		100.0000
El Paso Merchant Energy-Petroleum Company	Delaware	El Paso CGP Company, L.L.C.	Stockholder		100.0000
El Paso Mexico Holding B.V.	Netherlands	EPED Holding Company	Owner		100.0000
El Paso Mexico Management S. de R.L. de C.V.	Mexico	El Paso Compression Services de Mexico, S. de R.L. de C.V.	Owner		0.0300
		Grupo El Paso, S. de R.L. de C.V.	Owner		99.9700
El Paso Midstream Group, Inc.	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Midwest Company	Delaware	El Paso Energy Capital Company	Stockholder		100.0000
El Paso Mojave Pipeline Co.	Delaware	El Paso Natural Gas Company	Stockholder		100.0000
El Paso Natural Gas Company	Delaware	El Paso EPNG Investments, L.L.C.	Stockholder		100.0000
El Paso Nederland Energie B.V.	Netherlands	El Paso El Sauz B.V.	Owner		100.0000
El Paso Neuquen Holding Company	Cayman Islands	El Paso Energy Argentina Service Company	Owner		100.0000
El Paso Noric Investments III, L.L.C.	Delaware	El Paso CNG Company, L.L.C.	Member		100.0000
El Paso Oleo e Gas do Brasil Ltda.	Brazil	El Paso Brazil Holdings Company	Owner		0.1998
		El Paso Brazil, L.L.C.	Owner		99.8002
El Paso Pipeline Corporation	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Pipeline GP Company, L.L.C.	Delaware	El Paso Pipeline Holding Company, L.L.C.	Member		100.0000
El Paso Pipeline Holding B.V.	Netherlands	El Paso Corporation	Owner		100.0000
El Paso Pipeline Holding Company, L.L.C.	Delaware	El Paso Pipeline Corporation	Member		1.0000

Page 5

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		El Paso Corporation	Member		99.0000
El Paso Pipeline LP Holdings, L.L.C.	Delaware	El Paso Pipeline Holding Company, L.L.C.	Member		100.0000
El Paso Pipeline Partners Operating Company, L.L.C.	Delaware	El Paso Pipeline Partners, L.P.	Member		100.0000
El Paso Pipeline Partners, L.P.	Delaware	El Paso Pipeline GP Company, L.L.C.	General Partner		2.0000
		Unaffiliated Parties	Limited Partner		33.1000
		El Paso Pipeline LP Holdings, L.L.C.	Limited Partner		64.9000
El Paso Preferred Holdings Company	Delaware	El Paso E&P International Holding Company	Stockholder		100.0000
El Paso Production Holdings B.V.	Netherlands	El Paso Corporation	Owner		100.0000
El Paso Production International Cayman Company	Cayman Islands	El Paso Preferred Holdings Company	Owner of Preferred Stock		10.0000
		El Paso E&P International Holding Company	Owner of Common Stock		90.0000
El Paso Production Oil & Gas Gathering Company, L.L.C.	Delaware	El Paso E&P Holdings Company, L.L.C.	Member		100.0000
El Paso Production Resale Company, L.L.C.	Delaware	El Paso Exploration & Production Management, Inc.	Stockholder		100.0000
El Paso Reata Energy Company, L.L.C.	Delaware	El Paso Marketing, L.P.	Member		100.0000
El Paso Remediation Company	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso Rio Negro Energia Ltda.	Brazil	El Paso Energia do Brasil Ltda.	Owner		0.0001
		EPED B Company	Owner		99.9999
El Paso Ruby Holding Company, L.L.C.	Delaware	El Paso CNG Company, L.L.C.	Member		100.0000
El Paso Services Holding Company	Delaware	El Paso Tennessee Pipeline Co.	Stockholder		100.0000
El Paso SLOC Holding Company	Cayman Islands	Coscol Petroleum Corporation	Owner		100.0000
El Paso SNG Holding Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
El Paso South Texas E&P Company, L.L.C.	Delaware	El Paso E&P Company, L.P.	Member		100.0000
El Paso Tankships Malta, Ltd.	Malta	Coscol Holding Company Ltd.	Owner		0.0007
		El Paso SLOC Holding Company	Owner		99.9993
El Paso Technology Pakistan (Private) Limited	Pakistan	Directors/Officers/Other Individuals	Owner		0.0001
		El Paso CGP Company, L.L.C.	Owner		99.9999
El Paso Tennessee Pipeline Co.	Delaware	El Paso Corporation	Stockholder		100.0000
El Paso TGPC Investments, L.L.C.	Delaware	El Paso Tennessee Pipeline Co.	Member		100.0000
El Paso Wyoming Gas Supply Company, L.L.C.	Delaware	El Paso Pipeline Partners Operating Company, L.L.C.	Member		100.0000
Elba Express Company, L.L.C.	Delaware	El Paso Elba Express Company, L.L.C.	Member		100.0000
EnCap Investments L.L.C.	Delaware	David Miller	Unaffiliated Parties		8.3333
		Gary Petersen	Unaffiliated Parties		8.3333
		Martin Phillips	Unaffiliated Parties		8.3333
		Robert Zorich	Unaffiliated Parties		8.3333
		El Paso Merchant Energy North America Company, L.L.C.	Member		33.3333
		EnCap Investments L.P.	Unaffiliated Parties		33.3333
EnerVest Energy, L.P.	Delaware	Coronado Energy E&P Company, L.L.C.	Partner		23.0000

Page 6

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		Unaffiliated Party/Parties unknown	Partner		77.0000
EPEC Communications Corporation	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
EPEC Corporation	Delaware	El Paso Services Holding Company	Stockholder		100.0000
EPEC Oil Company Liquidating Trust		El Paso Energy E.S.T. Company	Trustee		100.0000
EPEC Polymers, Inc.	Delaware	El Paso Remediation Company	Stockholder		100.0000
EPEC Realty, Inc.	Delaware	Tennessee Gas Pipeline Company	Stockholder		100.0000
EPED B Company	Cayman Islands	EPED Holding Company	Owner		100.0000
EPED Holding Company	Delaware	El Paso Energy International Company	Stockholder		100.0000
EPGM Gasoductos, S. de R.L. de C.V.	Mexico	El Paso Mexico Management S. de R.L. de C.V.	Member		0.0001
		Grupo El Paso, S. de R.L. de C.V.	Member		99.9999
EPIC Gas International Servicos do Brasil Ltda.	Brazil	El Paso Services Holding Company	Owner		0.0001
		El Paso Energy International Company	Owner		14.9736
		EPED Holding Company	Owner		85.0263
EPNG Finance Company, L.L.C.	Delaware	El Paso Natural Gas Company	Member		100.0000
EPNG Funding Company, L.L.C.	Delaware	EPNG Finance Company, L.L.C.	Member		100.0000
EPNG Mojave, Inc.	Delaware	El Paso Natural Gas Company	Stockholder		100.0000
EPPP CIG GP Holdings, L.L.C.	Delaware	El Paso Pipeline Partners Operating Company, L.L.C.	Member		100.0000
EPPP SNG GP Holdings, L.L.C.	Delaware	El Paso Pipeline Partners Operating Company, L.L.C.	Member		100.0000
EPWP Resources Company	Delaware	El Paso CNG Company, L.L.C.	Stockholder		100.0000
Fife Power	Scotland	El Paso Fife I Company	Owner		50.0000
		Fife Limited	Unaffiliated Parties		50.0000
Florida Gas Transmission Company, LLC	Delaware	Citrus Corp.	Member		100.0000
Four Star Oil & Gas Company	Delaware	Chevron Netherlands B.V.	Unaffiliated Party — Owner of Class A Stock		0.2826
		Chevron Global Energy Inc.	Unaffiliated Party — Owner of Class A and Class B Stock		20.2940
		Chevron U.S.A. Inc.	Unaffiliated Party — Owner of Class A and Class B Stock		31.3737
		MBOW Four Star Corporation	Stockholder		48.0497
Gas TransBoliviano S.A.	Bolivia	BG Overseas Holdings Limited	Unaffiliated Parties		2.0000
		EPED B Company	Owner		2.0000
		Petrobras Gas S.A.	Unaffiliated Parties		11.0000
		Enron (Bolivia) C.V.	Unaffiliated Parties		17.0000
		Shell Gas (Latin America) B.V.	Unaffiliated Parties		17.0000
		Transredes S.A.	Unaffiliated Parties		51.0000
Gasoductos de Chihuahua, S. de R.L. de C.V.	Mexico	EPGM Gasoductos, S. de R.L. de C.V.	Owner		50.0000
		Pemex — Gas Y Petroquimica Basica	Unaffiliated Parties		50.0000
Gasoductos de la Sierra S. de R.L. de C.V.	Mexico	Grupo El Paso, S. de R.L. de C.V.	Owner		0.0300

Page 7

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		EPGM Gasoductos, S. de R.L. de C.V.	Owner		99.9700
Gasoductos de Tamaulipas, S. de R.L. de C.V.	Mexico	Gasoductos Servicios, S. de R.L. de C.V.	Owner		0.0100
		Gasoductos de Chihuahua, S. de R.L. de C.V.	Owner		99.9900
Gasoductos Servicios, S. de R.L. de C.V.	Mexico	Gasoductos de Tamaulipas, S. de R.L. de C.V.	Owner		0.0100
		Gasoductos de Chihuahua, S. de R.L. de C.V.	Owner		99.9900
GEBF, L.L.C.	Louisiana	Chevron U.S.A. Inc.	Unaffiliated Parties		33.3333
		ConocoPhillips Company	Unaffiliated Parties		33.3333
		Crystal Gas Storage, Inc.	Member		33.3334
GLE Channel Improvement, LLC	Delaware	Gulf LNG Energy (MS), LLC	Member		100.0000
Grupo El Paso, S. de R.L. de C.V.	Mexico	El Paso El Sauz B.V.	Owner		0.0300
		El Paso Nederland Energie B.V.	Owner		99.9700
Gulf LNG Development, LLC	Delaware	Crest Financial Ltd.	Unaffiliated Parties		10.8000
		Unaffiliated Parties	Unaffiliated Parties		19.2000
		Sonangol Holdings USA Company	Unaffiliated Parties		20.0000
		Southern Gulf LNG Company, L.L.C.	Member		50.0000
Gulf LNG Energy (MS), LLC	Delaware	Gulf LNG Energy (South), LLC	Member		100.0000
Gulf LNG Energy (Port), LLC	Delaware	Gulf LNG Energy (MS), LLC	Member		100.0000
Gulf LNG Energy (South), LLC	Delaware	Gulf LNG Energy (US), LLC	Member		100.0000
Gulf LNG Energy (US), LLC	Delaware	Gulf LNG Holdings Group, LLC	Member		100.0000
Gulf LNG Energy, LLC	Delaware	Gulf LNG Energy (Port), LLC	Member		100.0000
Gulf LNG Holdings Group, LLC	Delaware	Sonangol Holdings USA Company	Unaffiliated Parties		20.0000
		Crest Investment Members	Unaffiliated Parties		30.0000
		Southern Gulf LNG Company, L.L.C.	Member		50.0000
Gulf LNG Pipeline, LLC	Delaware	Gulf LNG Energy, LLC	Member		100.0000
Habibullah Coastal Power Company (Private) Limited	Pakistan	Directors/Officers/Other Individuals	Individual Owner(s)		0.0001
		Quetta Power Holding Company II Ltd.	Owner		0.9999
		Quetta Power Holding Company I Ltd.	Owner		99.0000
Harbortown Commercial Partnership	Michigan	MichCon Development Corp.	Unaffiliated Parties		33.3330
		ANR Development Company, L.L.C.	General Partner		66.6670
Harbortown Condominium Partnership	Michigan	MichCon Development Corp.	Unaffiliated Parties		33.3330
		ANR Development Company, L.L.C.	General Partner		66.6670
Harbortown Development Partnership	Michigan	MichCon Development Corp.	Unaffiliated Parties		33.3330
		ANR Development Company, L.L.C.	General Partner		66.6670
Harbortown Limited Dividend Housing Association	Michigan	ANR Development Company, L.L.C.	General Partner		50.0000
		MichCon Development Corp.	Unaffiliated Parties		50.0000
Interenergy Company	Cayman Islands	EPED B Company	Owner		100.0000
Malone Superfund Site and Douglas King et al Litigation Successor Trust		EPEC Polymers, Inc.	Trustee		100.0000
MBOW Four Star Corporation	Delaware	El Paso Exploration & Production Company	Stockholder		100.0000

Page 8

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
Mesquite Investors, L.L.C.	Delaware	El Paso Merchant Energy North America Company, L.L.C.	Member		100.0000
Mojave Pipeline Company	Texas	El Paso Mojave Pipeline Co.	Partner		50.0000
		EPNG Mojave, Inc.	Partner		50.0000
Mojave Pipeline Operating Company	Texas	Mojave Pipeline Company	Stockholder		100.0000
Mt. Franklin Insurance Ltd.	Bermuda	El Paso Corporation	Owner		100.0000
Quetta Power Holding Company I Ltd.	Cayman Islands	H.E.I. Ltd.	Unaffiliated Parties		25.0000
		Habibullah Energy Limited (Pakistan)	Unaffiliated Parties		25.0000
		Coastal Power International II Ltd.	Owner		50.0000
Quetta Power Holding Company II Ltd.	Cayman Islands	Coastal Power International II Ltd.	Owner		1.0000
		Habibullah Energy Limited	Unaffiliated Parties		1.0000
		Quetta Power Holding Company I Ltd.	Owner		98.0000
Ruby Pipeline Holding Company, L.L.C.	Delaware	GIP-B1 Master Partnership, L.P.	Unaffiliated Parties		6.8200
		Global Infrastructure Partners — A, L.P.	Unaffiliated Parties		17.6150
		GIP-C Holding Partnership, L.P.	Unaffiliated Parties		25.5650
		El Paso Ruby Holding Company, L.L.C.	Member		50.0000
Ruby Pipeline, L.L.C.	Delaware	Ruby Pipeline Holding Company, L.L.C.	Member		100.0000
Sandbar Petroleum Company	Delaware	El Paso Energy International Company	Stockholder		100.0000
SNG Finance Company, L.L.C.	Delaware	Southern Natural Gas Company	Member		100.0000
SNG Funding Company, L.L.C.	Delaware	SNG Finance Company, L.L.C.	Member		100.0000
SNG Pipeline Services Company, L.L.C.	Delaware	El Paso SNG Holding Company, L.L.C.	Member		100.0000
SNG RenCen Company, L.L.C.	Delaware	Tennessee Gas Pipeline Company	Member		100.0000
Sonora LNG Terminal Holding, S. de R.L. de C.V.	Mexico	Sonora Pipeline Holding, S. de R. L. de C.V.	Owner		0.0300
		Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		99.9700
Sonora Pipeline Holding, S. de R. L. de C.V.	Mexico	Sonora LNG Terminal Holding, S. de R.L. de C.V.	Owner		0.0300
		Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		99.9700
Sonora Pipeline, S. de R.L. de C.V.	Mexico	Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		0.0300
		Sonora Pipeline Holding, S. de R. L. de C.V.	Owner		99.9700
Sonora Services Energy, S. de R.L. de C.V.	Mexico	Sonora Pipeline Holding, S. de R. L. de C.V.	Owner		0.0300
		Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		99.9700
Sonora Terminal and Pipeline, S. de R.L. de C.V.	Mexico	Grupo El Paso, S. de R.L. de C.V.	Owner		50.0000
		Sonora Pacific Mexico S. de R.L. de C.V.	Unaffiliated Parties		50.0000
Southeast Gas Storage, L.L.C.	Delaware	El Paso Corporation	Member		0.0000
Southern Gulf LNG Company, L.L.C.	Delaware	El Paso Corporation	Member		100.0000
Southern LNG Inc.	Delaware	El Paso Corporation	Stockholder		100.0000
Southern Natural Gas Company	Delaware	EPPP SNG GP Holdings, L.L.C.	Partner		25.0000
		El Paso SNG Holding Company, L.L.C.	Partner		75.0000
Southern Natural Issuing Corporation	Delaware	Southern Natural Gas Company	Stockholder		100.0000
Starr County Gathering System	Texas	EEX Natural Gas Company	Unaffiliated Parties		1.0000

Page 9

OWNERSHIP LIST

As of December 31, 2009 (Revised)

	Place of			%
Entity Name	Incorporation	Owner	Relationship	Ownership
		El Paso E&P Company, L.P.	General Partner		30.0000
		EEX Pipeline Company, L.P.	Unaffiliated Parties		69.0000
TDF, S. de R.L. de C.V.	Mexico	Gasoductos Servicios, S. de R.L. de C.V.	Owner		0.0001
		Transportadora del Norte SH, S. de R.L. de C.V.	Owner		99.9999
Tennessee Gas Pipeline Company	Delaware	El Paso TGPC Investments, L.L.C.	Stockholder		100.0000
Terminal GNL de Sonora, S. de R.L. de C.V.	Mexico	Sonora Terminal and Pipeline, S. de R.L. de C.V.	Owner		0.0300
		Sonora LNG Terminal Holding, S. de R.L. de C.V.	Owner		99.9700
TGP Finance Company, L.L.C.	Delaware	Tennessee Gas Pipeline Company	Member		100.0000
TGP Funding Company, L.L.C.	Delaware	TGP Finance Company, L.L.C.	Member		100.0000
Transport USA, Inc.	Pennsylvania	ANR Advance Holdings, Inc.	Stockholder		100.0000
Transportadora Brasiliera Gasoduto Bolivia-Brazil S.A.	Brazil	Enron	Unaffiliated Parties		4.0000
		Shell	Unaffiliated Parties		4.0000
		Transporte de Hidrocarburos	Unaffiliated Parties		12.0000
		BBPP Holdings Ltda.	Owner		29.0000
		Petrobras affiliate	Unaffiliated Parties		51.0000
Transportadora del Norte SH, S. de R.L. de C.V.	Mexico	Gasoductos Servicios, S. de R.L. de C.V.	Owner		0.0001
		Gasoductos de Chihuahua, S. de R.L. de C.V.	Owner		99.9999
Triunion Energy Company	Cayman Islands	EPED B Company	Owner		23.2000
		Agua del Cajon (Cayman) Company	Owner		38.4000
		Interenergy Company	Owner		38.4000
Triunion Energy Inversiones (Chile) Limitada	Chile	Triunion Energy Company	Owner		0.4000
		Triunion Energy Pacifico Company	Owner		99.6000
Triunion Energy Inversiones Company	Cayman Islands	Triunion Energy Company	Owner		100.0000
Triunion Energy Inversiones Pacifico (Chile) Limitada	Chile	Triunion Energy Pacifico Company	Owner		0.2200
		Triunion Energy Inversiones (Chile) Limitada	Owner		99.7800
Triunion Energy Pacifico Company	Cayman Islands	Triunion Energy Inversiones Company	Owner		100.0000
UnoPaso Exploracao e Producao de Petroleo e Gas Ltda.	Brazil	El Paso Brazil Holdings Company	Owner		0.0001
		El Paso Oleo e Gas do Brasil Ltda.	Owner		0.0001
		El Paso Brazil, L.L.C.	Owner		99.9998
WIC Holdings Company, L.L.C.	Delaware	El Paso Pipeline Partners Operating Company, L.L.C.	Member		100.0000
WYCO Development LLC	Colorado	WYCO Holding Company, L.L.C.	Member		50.0000
		Xcel Energy WYCO Inc.	Unaffiliated Parties		50.0000
WYCO Holding Company, L.L.C.	Delaware	Colorado Interstate Gas Company	Member		100.0000
Wyoming Interstate Company, Ltd.	Colorado	El Paso Wyoming Gas Supply Company, L.L.C.	Limited Partner		50.0000
		WIC Holdings Company, L.L.C.	General Partner		50.0000
Young Gas Storage Company, Ltd.	Colorado	The City of Colorado Springs	Unaffiliated Parties — LP Owner		5.0000
		CIG Gas Storage Company	General Partner		47.5000
		Xcel Energy Markets Holdings Inc.	Unaffiliated Parties		47.5000

Page 10

EX-23.A

Exhibit 23.A

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statement (Form S-3 No. 333-158205) and related Prospectus of El Paso Corporation, and in the following Registration Statements on Form S-8:

Form S-8 No.	Pertaining to:
333-162995	El Paso Corporation 2005 Omnibus Incentive Compensation Plan
333-127951	El Paso Corporation Retirement Savings Plan
333-126599	El Paso Corporation 2005 Omnibus Incentive Compensation Plan
333-126597	El Paso Corporation 2005 Compensation Plan for Non-employee Directors
333-96959	El Paso Corporation Employee Stock Purchase Plan
333-26813	El Paso Energy Corporation Retirement Savings Plan
333-26831	El Paso Natural Gas Company Omnibus Plan for Management Employees
333-26823  and 333-94717	El Paso Energy Corporation Strategic Stock Plan
033-46519	Omnibus Compensation Plan and Stock Option Plan for Non-employee Directors
033-49956	El Paso Natural Gas Company Retirement Savings Plan
033-51851	El Paso Natural Gas Company Stock Option Plan for Management Employees
033-57553	1995 Omnibus Compensation Plan, 1995 Incentive Compensation Plan and 1995 Compensation Plan for Non-employee Directors
033-51853	El Paso Natural Gas Company Incentive Compensation Plan
333-75781	El Paso Energy Corporation Sonat Savings Plan
333-78949	El Paso Energy Corporation Employee Stock Purchase Plan
333-78951	El Paso Energy Corporation Deferred Compensation Plan
333-78979	El Paso Corporation 1999 Omnibus Incentive Compensation Plan and El Paso Energy Corporation Omnibus Plan for Management Employees
333-94719	El Paso Energy Corporation Omnibus Plan for Management Employees
333-64240	El Paso Corporation 2001 Stock Option Plan for Non-employee Directors
333-31060	El Paso Corporation Coastal Aruba Refining Company N.V. Thrift Plan (formerly Coastal Aruba Refining Company N. V. Thrift Plan)

of our reports dated March 1, 2010, with respect to the consolidated financial statements and schedule of El Paso Corporation, and the effectiveness of internal control over financial reporting of El Paso Corporation, included in this Annual Report (Form 10-K) for the year ended December 31, 2009.

/s/ Ernst & Young LLP  

Houston, Texas
March 1, 2010

EX-23.B

Exhibit 23.B

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-158205) and Form S-8 (File Nos. 333-162995, 333-127951, 333-126599, 333-126597, 333-96959, 333-26813, 333-26831, 333-26823, 033-46519, 033-49956, 033-51851, 033-57553, 033-51853, 333-75781, 333-78949, 333-78951, 333-78979, 333-94717, 333-94719, 333-64240, 333-31060) of El Paso Corporation of the following reports:

• Our report dated February 20, 2009, relating to the consolidated financial statements of Four Star Oil & Gas Company which appears in this Form 10-K

• Our report dated February 25, 2010, relating to the consolidated financial statements of Citrus Corp. and Subsidiaries which appears in this Form 10-K

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 25, 2010

EX-23.D

Exhibit 23.D

CONSENT OF RYDER SCOTT COMPANY, L.P.

     As independent petroleum engineers, Ryder Scott Company, L.P. hereby consents to the incorporation by reference in the Registration Statements on Form S-3 (File Nos. 333-158205) and Form S-8 (File Nos. 333-162995, 333-127951, 333-126599, 333-126597, 333-96959, 333-26813, 333-26831, 333-26823, 033-46519, 033-49956, 033-51851, 033-57553, 033-51 853, 333-75781, 333-78949, 333-78951, 333-78979, 333-94717, 333-94719, 333-64240, 333-31060) of El Paso Corporation of the reference to us and our reports under the captions “Part I. Business — Exploration and Production Segment — Natural Gas and Oil Properties” and “Part II. Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Supplemental Natural Gas and Oil Operations (Unaudited)” and our reserve reports attached as Exhibit 99.A in the Annual Report on Form 10-K of El Paso Corporation for the year ended December 31, 2009.

/s/ Ryder Scott Company, L.P.  

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580 

Houston, Texas
February 26, 2010

1200, 530 8TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3S8	TEL (403) 262-2799	FAX (403) 262-2790
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

EX-31.A

Exhibit 31.A

CERTIFICATION

I, Douglas L. Foshee, certify that:

1. I have reviewed this Annual Report on Form 10-K of El Paso Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; and

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2010

/s/ Douglas L. Foshee  

Douglas L. Foshee 

President and Chief Executive Officer
(Principal Executive Officer)
El Paso Corporation
 

EX-31.B

Exhibit 31.B

CERTIFICATION

I, John R. Sult, certify that:

1. I have reviewed this Annual Report on Form 10-K of El Paso Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; and

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2010

/s/ John R. Sult  

John R. Sult 

Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
El Paso Corporation 

EX-32.A

Exhibit 32.A

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report on Form 10-K for the period ending December 31, 2009, of El Paso Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas L. Foshee, President and Chief Executive Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Douglas L. Foshee

Douglas L. Foshee

President and Chief Executive Officer

(Principal Executive Officer)

El Paso Corporation

March 1, 2010

A signed original of this written statement required by Section 906 has been provided to El Paso Corporation and will be retained by El Paso Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit 32.B

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report on Form 10-K for the period ending December 31, 2009, of El Paso Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John R. Sult, Senior Vice President and Chief Financial Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ John R. Sult

John R. Sult

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

El Paso Corporation

March 1, 2010

A signed original of this written statement required by Section 906 has been provided to El Paso Corporation and will be retained by El Paso Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.A

Exhibit 99.A

EL PASO PRODUCTION COMPANY

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2009

/s/ Jeffrey D. Wilson

Jeffrey D. Wilson, P.E.
Senior Vice President

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580

[SEAL]

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

1100 LOUISIANA SUITE 3800	HOUSTON, TEXAS 77002-5218	FAX (713) 651-0849 TELEPHONE (713) 651-9191

January 19, 2010

El Paso Production Company
El Paso Tower
1001 Louisiana
Houston, TX 77002

Gentlemen:

     At the request of El Paso Production Company (El Paso), Ryder Scott Company (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by El Paso’s engineering and geological staff based on the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

     The reserves audit conducted by Ryder Scott was completed on January 18, 2010. This third party letter report presents the results of our reserves audit based on the guidelines set forth under Section 229.1202(a)(7) and (8) of the SEC regulations. The estimated reserves shown herein represent El Paso’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by El Paso and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2009.

     The properties reviewed by Ryder Scott incorporate El Paso reserve determinations of certain working and royalty interests located in the states of Alabama, Colorado, Louisiana, New Mexico, Oklahoma, Texas, Utah and Wyoming, in the federal waters offshore Louisiana and Texas and in offshore Brazil. Additionally, Ryder Scott reviewed El Paso reserve determinations of the company’s equity interest in Four Star Oil & Gas, comprised of certain properties located in the states of Alabama, Colorado, New Mexico and Texas. These equity interests are presented separately.

     The proved net reserves attributable to the working and royalty interest properties that we reviewed account for 87 percent of the total proved equivalent cubic foot, MMCFE, basis based on estimates prepared by El Paso as of December 31, 2009. The properties that we reviewed represent 90 percent of the total proved discounted future net income based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by El Paso as of December 31, 2009.

     The proved net reserves attributable to the equity interest in Four Star Oil & Gas that we reviewed account for 83 percent of the total proved equivalent cubic foot, MMCFE, basis based on estimates prepared by El Paso as of December 31, 2009. The properties that we reviewed represent 85 percent of the total proved discounted future net income based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by El Paso as of December 31, 2009.

     As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

1200, 530 8TH AVENUE, S.W.CALGARY, ALBERTA T2P 3S8 TEL (403) 262-2799 FAX (403) 262-2790
621 17TH STREET, SUITE 1550DENVER, COLORADO 80293-1501TEL (303) 623-9147 FAX (303) 623-4258

El Paso Company
January 19, 2010
Page 2

     Based on our review, including the data, technical processes and interpretations presented by El Paso, it is our opinion that the overall procedures and methodologies utilized by El Paso in determining the proved reserves comply with the current SEC regulations and the overall proved reserves for the reviewed properties as estimated by El Paso are, in the aggregate, reasonable within the established audit tolerance guidelines set forth in the SPE auditing standards.

     The estimated reserves presented in this report are related to hydrocarbon prices. El Paso has informed us that in the preparation of their reserve and income projections, as of December 31, 2009, they used average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by El Paso attributable to El Paso’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS
Estimated Net Reserves
Attributable to Certain Working and Royalty Interest Properties of
El Paso Production Company
As of December 31, 2009

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves of Properties
Audited by Ryder Scott
Oil/Condensate — Barrels		16,010,841		7,462,983		34,575,552		58,049,376
Plant Products — Barrels		61,059		99,362		—		160,421
Gas — MMCF		1,043,511		218,077		597,498		1,859,086
Total Gas Equivalents — MMCFE*		1,139,942		263,451		804,951		2,208,344
Net Reserves of Properties
Not Audited by Ryder Scott
Oil/Condensate — Barrels		4,222,379		2,103,892		669,403		6,995,674
Plant Products — Barrels		3,041		140,178		—		143,219
Gas — MMCF		191,533		79,214		26,744		297,491
Total Gas Equivalents — MMCFE*		216,886		92,678		30,760		340,324
Total Net Reserves
Oil/Condensate — Barrels		20,233,220		9,566,875		35,244,955		65,045,050
Plant Products — Barrels		64,100		239,540		—		303,640
Gas — MMCF		1,235,044		297,291		624,242		2,156,577
Total Gas Equivalents — MMCFE*		1,356,828		356,129		835,712		2,548,669

* 1 bbl liquid = 6 MCF gas equivalents

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

El Paso Company
January 19, 2010
Page 3

SEC PARAMETERS
Estimated Net Remaining Reserves
Attributable to the Equity Interest of
El Paso Production Company in Four Star Oil & Gas
As of December 31, 2009

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves of Properties
Audited by Ryder Scott
Oil/Condensate — Barrels		1,584,063		—		47,209		1,631,272
Plant Products — Barrels		3,872,722		—		896,546		4,769,268
Gas — MMCF		110,716		—		17,523		128,239
Total Gas Equivalents — MMCFE*		143,457		—		23,186		166,643
Net Reserves of Properties
Not Audited by Ryder Scott
Oil/Condensate — Barrels		275,728		—		10		275,738
Plant Products — Barrels		402,293		20,184		72,350		494,827
Gas — MMCF		21,926		2,603		5,255		29,784
Total Gas Equivalents — MMCFE*		25,994		2,724		5,689		34,407
Total Net Reserves
Oil/Condensate — Barrels		1,859,791		—		47,219		1,907,010
Plant Products — Barrels		4,275,015		20,184		968,896		5,264,095
Gas — MMCF		132,642		2,603		22,778		158,023
Total Gas Equivalents — MMCFE*		169,451		2,724		28,875		201,050

* 1 bbl liquid = 6 MCF gas equivalents

     Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an as-sold basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

     In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

     Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, could be more or less than the estimated amounts.

     An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

El Paso Company
January 19, 2010
Page 4

Audit Data, Methodology, Procedure and Assumptions

     The reserves for the properties that we reviewed were estimated by performance methods or the volumetric method. In general, reserves attributable to producing wells and/or reservoirs were estimated by performance methods such as decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through December 2009 in those cases where such data were considered to be definitive. In certain cases, producing reserves were estimated by the volumetric method where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. Reserves attributable to non-producing and undeveloped reserves included herein were estimated by the volumetric method, which utilized all pertinent well and seismic data available through December 2009.

     Of the audited working interest and royalty volumes, less than 12% of the reserves were estimated with volumetrics alone. An additional 38% of the audited reserves were estimated using volumetrics in combination with performance. Over 88% of the audited reserves were based in whole or in part on performance. Simulation models were used in part to estimate 16% of the audited reserves. Coal bed methane wells account for 37% of the audited reserves. Horizontal wells account for less than 10% of the audited reserves.

     The volumes associated with Four Star Oil & Gas are entirely based on performance estimates.

     To estimate economically recoverable oil and gas reserves, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the effective date of the report. El Paso has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of El Paso’s forecast of future production and income, we have relied upon data furnished by El Paso with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by El Paso.

     As previously stated, the hydrocarbon prices used by El Paso are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.

     The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in El Paso’s individual property evaluations.

     While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

El Paso Company
January 19, 2010
Page 5

     Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed. The gas volumes included herein do not attribute gas consumed in operations as reserves.

     Operating costs used by El Paso are based on the operating expense reports of El Paso and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. When applicable for operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Other operating costs include deductions for transportation and processing fees, where applicable. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

     Development costs used by El Paso are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by El Paso were accepted without independent verification.

     Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled. El Paso has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. All of the audited undeveloped reserves are scheduled to be drilled within five years from the as of date of this report.

     Current costs used by El Paso were held constant throughout the life of the properties.

     El Paso’s forecasts of future production rates are based on historical performance from wells now on production or estimated initial production rates based on test data and other related information for those wells or locations that are not currently producing. Forecasts of future production rates may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in the forecasts prepared by El Paso.

     The reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subject to significantly varying contractual fiscal terms that affect the net revenue to El Paso for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with El Paso the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of El Paso’s representations regarding such contractual information should be construed as a legal opinion on this matter.

     Ryder Scott did not evaluate country and geopolitical risks in the countries where El Paso operates or has interests. El Paso’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

El Paso Company
January 19, 2010
Page 6

     The estimates of reserves presented herein were based upon a detailed study of the properties in which El Paso owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

     Certain technical personnel of El Paso are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

     The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our audit included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

Audit Opinion

     In our opinion, El Paso’s estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves as set forth in the Society of Petroleum Engineers’ Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information, and we found no bias in the utilization and analysis of data in estimates for these properties.

     The overall proved reserves for the reviewed properties as estimated by El Paso are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Other Properties

     Other properties, as used herein, are those properties of El Paso that we did not review. The proved net reserves attributable to the other working and royalty interest properties account for 13 percent of the total proved equivalent cubic foot, MMCFE, basis based on estimates prepared by El Paso as of December 31, 2009. The other properties represent 10 percent of the total proved discounted future net income based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by El Paso as of December 31, 2009.

     The proved net reserves attributable to the other equity interest in Four Star Oil & Gas that we did not review account for 17 percent of the total proved equivalent cubic foot, MMCFE, basis based on estimates prepared by El Paso as of December 31, 2009. The other properties represent 15 percent of the total proved discounted future net income based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by El Paso as of December 31, 2009.

     The same technical personnel of El Paso were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification

     Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

El Paso Company
January 19, 2010
Page 7

number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

     Ryder Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

     Ryder Scott requires that staff engineers and geoscientists have received professional accreditation, and are maintaining in good standing, a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization prior to becoming an officer of the Company.

     We are independent petroleum engineers with respect to El Paso. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

     The professional qualifications of the undersigned, the technical person primarily responsible for auditing the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

     This report was prepared for the exclusive use of El Paso Production Company and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,


RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
 

/s/ Jeffrey D. Wilson  

Jeffrey D. Wilson, P.E.
TBPE License No. 86426
Senior Vice President     [SEAL] 

/sm

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Engineer

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Jeffrey D. Wilson was the primary technical person responsible for the estimate of the reserves presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1998, is a Senior Vice President and also serves as a member of the Board of Directors responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Exxon. For more information regarding Mr. Wilson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Wilson earned a Bachelor of Science degree in Mechanical Engineering from the University of Houston in 1991, graduating with Magna Cum Laude honors, and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

As part of his 2009 continuing education hours, Mr. Wilson attended an internally presented 13 hours of formalized training as well as a day long public forum, and/or various professional society presentations specifically on the new SEC regulations relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attended an additional 7 hours of formalized in-house training as well as 12 hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. Mr. Wilson also taught a 12 hour class on advanced economic modeling techniques and production sharing contract modeling using PHDWin.

Based on his educational background, professional training and more than 18 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

          On January 14, 2009, the United States Securities and Exchange Commission (“the Commission”) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect with all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10 (a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).

     Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.102 (5).

     Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.

     Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
Page 2

RESERVES (SEC DEFINITIONS)

     Securities and Exchange Commission Regulation S-X §229.4-10(a) (26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

     Securities and Exchange Commission Regulation S-X §229.4-10(a) (22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

RESERVES DEFINITIONS
Page 3

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

[Remainder of this page is left blank intentionally]

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE),
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

          Reserves status categories define the development and producing status of wells and reservoirs.

DEVELOPED RESERVES (SEC DEFINITIONS)

     Securities and Exchange Commission Regulation S-X §229.4-10(a) (6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

          While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

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RESERVES STATUS DEFINITIONS AND GUIDELINES
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Shut-In
Shut-in Reserves are expected to be recovered from:

(1)	completion intervals which are open at the time of the estimate but which have not yet started producing;
(2)	wells which were shut-in for market conditions or pipeline connections; or
(3)	wells not capable of production for mechanical reasons.

Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.

     In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

     Securities and Exchange Commission Regulation S-X §229.4-10(a) (31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

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