El Paso Exploration & Production 10-K 2006 FY Annual report

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, 2006

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 333-106586

El Paso Exploration & Production Company

(Exact name of Registrant as Specified in Its Charter)

Delaware	76-0659544
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)
El Paso Building	77002
1001 Louisiana Street	(Zip Code)
Houston, Texas (Address of Principal Executive Offices)

Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso     Noþ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso     Noþ

     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. Yesþ      Noo.

     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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero      Accelerated filero      Non-accelerated filerþ

     Indicate by check mark whether the registrant is a shell company (As defined in Rule 12b-2 of the Exchange Act).
Yeso Noþ.

     State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant:None

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

     Common Stock, par value $1 per share. Shares outstanding on February 28, 2007: 1,000

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

Documents Incorporated by Reference: None

EL PASO EXPLORATION & PRODUCTION COMPANY
TABLE OF CONTENTS

Caption	Page
PART I
Item 1. Business		1
Item 1A. Risk Factors		9
Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		9
Item 1B. Unresolved Staff Comments		16
Item 2. Properties		16
Item 3. Legal Proceedings		16
Item 4. Submission of Matters to a Vote of Security Holders		*
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		17
Item 6. Selected Financial Data		*
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		25
Item 8. Financial Statements and Supplementary Data		26
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		60
Item 9A. Controls and Procedures		60
Item 9B. Other Information		61
PART III
Item 10. Directors, Executive Officers and Corporate Governance		*
Item 11. Executive Compensation		*
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		*
Item 13. Certain Relationships and Related Transactions, and Director Independence		*
Item 14. Principal Accountant Fees and Services		61
PART IV
Item 15. Exhibits and Financial Statement Schedules		61
Signatures		63
Sixth Supplemental Indenture
Seventh Supplemental Indenture
Second Amendment Amended and Restated Credit Agreement
Consent of Ryder Scott
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906
Ryder Scott Reserve Report
Ryder Scott Reserve Report

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

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

/d	=	per day	Mcfe	=	thousand cubic feet of natural gas equivalents
Bbl	=	Barrels	MMBtu	=	million British thermal units
BBtu	=	billion British thermal units	MMcf	=	million cubic feet
Bcf	=	billion cubic feet	MMcfe	=	million cubic feet of natural gas equivalents
Bcfe	=	billion cubic feet of natural gas equivalents	NGL	=	natural gas liquids
Block	=	nine square miles of offshore properties	TBtu	=	trillion British thermal units
MBbls	=	thousand barrels	Tcfe	=	trillion cubic feet of natural gas equivalents
Mcf	=	thousand cubic feet

     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”, “EPEP” or “the Company”, we are describing El Paso Exploration & Production Company and/or our subsidiaries.

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PART I

ITEM 1. BUSINESS

General

     We are a Delaware corporation formed in 1999 as a wholly-owned direct subsidiary of El Paso Corporation (El Paso). On December 31, 2005, El Paso made a capital contribution to us of several domestic companies engaged in the exploration and production of natural gas and oil that were previously part of El Paso CGP Company, L.L.C. (El Paso CGP), another subsidiary of El Paso. On October 1, 2006, El Paso also contributed its current international exploration and production businesses to us. The information in this Annual Report on Form 10-K reflects the contribution of these companies and their related operations for all periods presented.

     We are engaged in the exploration for and the acquisition, development and production of natural gas, oil and NGL in the United States, Brazil and Egypt. As of December 31, 2006, we controlled over 2.9 million net leasehold acres. During 2006, daily equivalent natural gas production averaged approximately 730 MMcfe/d and our proved natural gas and oil reserves at December 31, 2006 were approximately 2.4 Tcfe, excluding 0.2 Tcfe related to our unconsolidated investment in Four Star Oil & Gas Company (Four Star). We are focused on growing our reserve base 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. We have a balanced portfolio of development, exploitation and exploration projects, including long-lived and shorter-lived properties divided into the following regions discussed below:

United States

     Onshore. The Onshore region includes operations that are primarily focused on unconventional tight gas sands and coal bed methane producing areas, which are generally characterized by repeatable drilling programs, higher drilling success rates and longer reserve lives. We have a large inventory of drilling prospects in this region. During 2006, we invested $500 million on capital projects and production averaged 345 MMcfe/d. The principal operating areas are listed below:

		2006
					Average
				Capital	Production
Region	Description	Net Acres		Investment	(MMcfe/d)
East Texas / north Louisiana (Arklatex)	Concentrated land position primarily focused on tight gas sands production in the Travis Peak/Hosston and Cotton Valley formations.		104,000	$203 million		122
Black Warrior Basin	Established shallow coal bed methane producing areas of northwestern Alabama. We have high average working interests in our operated properties in addition to an average 50 percent working interest covering approximately 46,000 net acres operated by Black Warrior Methane, which produces from the Brookwood Field.		172,000	$49 million		64
Mid-Continent	Primarily in Oklahoma with a focus on development projects in the Arkoma Basin where we utilize horizontal drilling in the Hart shorne Coals area, West Verdon field, an oil producing waterflood project, and shallow natural gas production in the Hugoton field.		319,000	$56 million		28

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		2006
					Average
				Capital	Production
Region	Description	Net Acres		Investment	(MMcfe/d)
Rocky Mountain (Rockies)	Primarily in Wyoming and Utah with a focus in the Powder River and Uintah basins, consisting predominantly of operated oil fields utilizing both primary and secondary recovery methods combined with non-operated coal bed methane fields. We also operate the Altamont and Bluebell processing plants and related gathering systems in Utah.		364,000	$120 million		55
Raton Basin	Primarily focused on coal bed methane production in northern New Mexico and southern Colorado, where we own the minerals and have a 100 percent working interest in the Vermejo Park Ranch.		605,000	$72 million		76

     Included in our Mid-Continent region is our interest in 127,000 net acres in the Illinois Basin, primarily in the New Albany Shale area in south-western Indiana. We are the operator of these properties and maintain a 50 percent working interest in this large emerging area, which is still under evaluation. We have drilled 22 wells through the end of 2006.

     Texas Gulf Coast. The Texas Gulf Coast region focuses on developing and exploring for tight gas sands in south Texas. We have an inventory of over 10,000 square miles of three dimensional (3D) seismic data. During 2006, we invested $217 million on capital projects in this region and production averaged 187 MMcfe/d. The principal operating areas are listed below:

		2006
					Average
				Capital	Production
Region	Description	Net Acres		Investment	(MMcfe/d)
Vicksburg/Frio Trends	Includes concentrated and contiguous assets located in south Texas, including the Jeffress and Monte Christo fields primarily in Hidalgo county in which we have an average 90 percent working interest.		81,000	$111 million		123
Upper Gulf Coast Wilcox	Located onshore Texas Gulf Coast including the Renger, Dry Hollow and Speaks fields in Lavaca County. Average well depth is between 13,000 to 18,000 feet.		31,000	$60 million		32
South Texas Wilcox	Includes the Bob West and Roleta fields in Zapata County where we completed the acquisition discussed below in January 2007.		25,000	$29 million		27

     In January 2007, we acquired operated producing properties and undeveloped acreage in Zapata County, Texas with an average working interest of 85 percent for $249 million. These properties complement our existing south Texas Wilcox operations, providing a re-entry into the Lobo trend and a multi-year drilling inventory with significant additional exploration and development drilling opportunities. The 23,000 net acres acquired had net production of approximately 12 MMcfe/d and estimated proved reserves of approximately 84 Bcfe on the acquisition date, of which approximately 73 percent was undeveloped.

     Gulf of Mexico Shelf and south Louisiana. Our Gulf of Mexico shelf and south Louisiana operations are generally characterized by relatively high initial production rates, resulting in near-term cash flows, and high decline rates. During 2006, we invested $310 million on drilling, workover and facilities projects in this region and production averaged 174 MMcfe/d. The principal operating areas are listed below:

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		2006
				Capital	Average
				Investment	Production
Region	Description	Net Acres		(in millions)	(MMcfe/d)
Gulf of Mexico Shelf	Primarily deep shelf drilling interests in 173 Blocks south of the Louisiana, Texas and Alabama shorelines focused on deep (greater than 12,000 feet) gas reserves in relatively shallow waters depths (less than 400 feet).		688,000	$246 million		163
South Louisiana	Primarily in Vermillion Parish and associated bays and waters in southwestern Louisiana covered by the Catapult 3D seismic project. We have internally processed 2,600 square miles of contiguous 3D seismic data in this project.		34,000	$64 million		11

     Unconsolidated Investment in Four Star.We own a 43.1 percent investment in Four Star. Four Star operates onshore in the San Juan, Permian, Hugoton and South Alabama Basins and the Gulf of Mexico. During 2006, our proportionate share of Four Star’s daily equivalent natural gas production averaged approximately 68 MMcfe/d and at December 31, 2006, proved natural gas and oil reserves, net to our interest, were 222 Bcfe. In January 2007, Four Star acquired 79 wells in the San Juan basin with daily production of approximately 5 MMcfe/d and proved reserves of 16 Bcfe, net to our interest, on the acquisition date.

International

     Brazil.Our Brazil operations cover approximately 361,000 net acres. These operations include interests in 13 concessions located in the Espirito Santo, Potiguar and Camamu Basins, including our 35 percent working interest in the Pescada Arabaiana fields in the Potiguar Basin. In 2006, we invested $80 million in capital projects in Brazil and production averaged approximately 24 MMcfe/d from the Pescada Arabaiana fields.

     Egypt.Our Egypt operations include a 20 percent non-operated working interest in approximately 13,000 net acres in the South Feiran concession located in the Gulf of Suez, which is in the seismic, exploratory drilling and evaluation phases. We were the winning bidder of the South Mariut Block in the second quarter of 2006 with a $3 million payment due on final receipt of the concession and an agreement for a $22 million firm working commitment over three years. The block is approximately 1.2 million acres and is located onshore in the western part of the Nile Delta. We expect to receive formal governmental approvals and sign the concession agreement during the first quarter of 2007.

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Natural Gas and Oil Properties

Natural Gas, Oil and Condensate and NGL Reserves and Production

     The tables below present our estimated proved reserves based on our internal reserve report as of December 31, 2006 by region and classification as well as our 2006 production by region.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:

	Net Proved Reserves
	Natural		Oil/									2006
	Gas		Condensate		NGL		Total					Production
	(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(Percent)			(MMcfe)
Reserves and Production by Region
United States
Onshore		1,308,742		28,947		1,060		1,488,789		62	%		126,093
Texas Gulf Coast		344,596		2,265		8,004		406,209		17	%		68,269
Gulf of Mexico Shelf and south Louisiana		209,897		9,467		948		272,384		11	%		63,537
Total United States		1,863,235		40,679		10,012		2,167,382		90	%		257,899
Brazil		56,383		31,847		—		247,466		10	%		8,619
Total		1,919,618		72,526		10,012		2,414,848		100	%		266,518
Unconsolidated investment in Four Star		167,046		2,947		6,209		221,984		100	%		24,663
Reserves by Classification
United States
Producing		1,251,019		22,415		7,402		1,429,923		66	%
Non-Producing		217,881		7,201		1,263		268,665		12	%
Undeveloped		394,335		11,063		1,347		468,794		22	%
Total proved		1,863,235		40,679		10,012		2,167,382		100	%
Brazil
Producing		19,931		489		—		22,864		9	%
Non-Producing		3,405		335		—		5,418		2	%
Undeveloped		33,047		31,023		—		219,184		89	%
Total proved		56,383		31,847		—		247,466		100	%
Worldwide
Producing		1,270,950		22,904		7,402		1,452,787		60	%
Non-Producing		221,286		7,536		1,263		274,083		11	%
Undeveloped		427,382		42,086		1,347		687,978		29	%
Total proved		1,919,618		72,526		10,012		2,414,848		100	%
Unconsolidated investment in Four Star
Producing		136,489		2,874		5,068		184,140		83	%
Non-Producing		2,733		—		26		2,892		1	%
Undeveloped		27,824		73		1,115		34,952		16	%
Total Four Star		167,046		2,947		6,209		221,984		100	%

     The consolidated information in the table above is 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.

     Ryder Scott Company, L.P. (Ryder Scott), an independent reservoir engineering firm that reports to the Audit Committee of El Paso’s Board of Directors, prepared an estimate on 84 percent of our consolidated natural gas and oil reserves. Additionally, Ryder Scott prepared an estimate of 80 percent of the proved reserves of Four Star, our unconsolidated affiliate. Our estimates of Four Star’s proved natural gas and oil reserves are prepared by our internal

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reservoir engineers and do not reflect those prepared by the engineers of Four Star. Based on the amount of proved reserves determined by Ryder Scott, we believe our reported reserve amounts are reasonable. Ryder Scott’s reports are included as exhibits to this Annual Report on Form 10-K.

     There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production, and projecting the timing of development expenditures, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The reserve data represents only estimates which are often different from the quantities of natural gas and oil that are ultimately recovered. 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, and on engineering and geological interpretations and judgment.

     All estimates of proved reserves are determined according to the rules prescribed by the Securities and Exchange Commission (SEC). These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including 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.

     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. Recovery of proved undeveloped 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 proved undeveloped reserves and proved non-producing reserves are 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.

Acreage and Wells

     The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2006, (ii) our interest in natural gas and oil wells at December 31, 2006 and (iii) our exploratory and development wells drilled during the years 2004 through 2006. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.

Acreage

	Developed				Undeveloped				Total
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
United States
Onshore		874,525		556,828		1,612,025		1,135,010		2,486,550		1,691,838
Texas Gulf Coast		93,573		73,373		91,230		63,452		184,803		136,825
Gulf of Mexico Shelf and south Louisiana		508,716		359,064		401,075		363,046		909,791		722,110
Total		1,476,814		989,265		2,104,330		1,561,508		3,581,144		2,550,773
Brazil		49,262		17,242		1,158,643		343,563		1,207,905		360,805
Egypt		—		—		64,740		12,948		64,740		12,948
Worldwide Total		1,526,076		1,006,507		3,327,713		1,918,019		4,853,789		2,924,526

     In the United States, our net developed acreage is concentrated primarily in the Gulf of Mexico (36 percent), Utah (13 percent), Texas (9 percent), Alabama (9 percent), New Mexico (9 percent), Oklahoma (8 percent) and Louisiana (7 percent). Our net undeveloped acreage is concentrated primarily in New Mexico (31 percent), the Gulf of Mexico (22 percent), Wyoming (10 percent), West Virginia (8 percent), Indiana (7 percent), Alabama (5 percent), Texas (4 percent) and Louisiana (3 percent). Approximately 23 percent, 20 percent and 8 percent of our total United States net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2007, 2008 and 2009. Approximately 16 percent, 25 percent and 12 percent of our total Brazilian net undeveloped acreage is held under leases

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that have minimum remaining primary terms expiring in 2007, 2008 and 2009. Approximately 33 percent of our total Egyptian net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2008. We employ various techniques to manage the expiration of leases, including extending lease terms, and drilling the acreage ourselves or through farm out agreements with other operators.

Productive Wells

													Wells
													Being Drilled at
	Natural Gas				Oil				Total				December 31, 2006
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)(3)		Gross(1)		Net(2)
United States
Onshore		3,880		2,954		801		548		4,681		3,502		52		38
Texas Gulf Coast		843		703		—		—		843		703		6		5
Gulf of Mexico Shelf and south Louisiana		187		122		58		40		245		162		6		4
Total United States		4,910		3,779		859		588		5,769		4,367		64		47
Brazil		4		1		6		2		10		3		—		—
Worldwide Total		4,914		3,780		865		590		5,779		4,370		64		47

Wells Drilled

	Net Exploratory(2)						Net Development(2)
	2006		2005		2004		2006		2005		2004
United States
Productive		106		86		13		319		279		298
Dry		6		2		10		2		4		3
Total		112		88		23		321		283		301
Brazil
Productive		—		—		—		—		—		—
Dry		—		—		1		—		—		—
Total		—		—		1		—		—		—
Worldwide
Productive		106		86		13		319		279		298
Dry		6		2		11		2		4		3
Total		112		88		24		321		283		301

(1)	Gross interest reflects the total acreage or wells we participated in, regardless of our ownership interest in the acreage or wells.
(2)	Net interest is the aggregate of the fractional working interests that we have in the gross acreage, gross wells or gross wells drilled.
(3)	At December 31, 2006, we operated 3,957 of the 4,370 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.

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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:

	2006		2005		2004
Consolidated Volumes, Prices, and Costs per Unit:
Net Production Volumes
United States
Natural gas (MMcf)		213,262		206,714		238,009
Oil, condensate and NGL (MBbls)		7,439		7,516		8,498
Total (MMcfe)		257,899		251,807		288,994
Brazil(1)
Natural gas (MMcf)		7,140		15,578		6,848
Oil, condensate and NGL (MBbls)		247		620		320
Total (MMcfe)		8,619		19,300		8,772
Worldwide
Natural gas (MMcf)		220,402		222,292		244,857
Oil, condensate and NGL (MBbls)		7,686		8,136		8,818
Total (MMcfe)		266,518		271,107		297,766
Total (MMcfe/d)		730		743		814
Natural Gas Average Realized Sales Price ($/Mcf)
United States
Excluding hedges	$	6.77	$	7.92	$	6.02
Including hedges	$	5.40	$	5.33	$	5.09
Brazil
Excluding hedges	$	2.61	$	2.33	$	2.01
Including hedges	$	2.61	$	2.33	$	2.01
Worldwide
Excluding hedges	$	6.64	$	7.53	$	5.90
Including hedges	$	5.31	$	5.12	$	5.00
Oil, Condensate, and NGL Average Realized Sales Price ($/Bbl)
United States
Excluding hedges	$	55.95	$	45.86	$	34.44
Including hedges	$	55.95	$	45.86	$	34.44
Brazil
Excluding hedges	$	64.02	$	53.42	$	43.01
Including hedges	$	54.48	$	42.42	$	39.19
Worldwide
Excluding hedges	$	56.21	$	46.43	$	34.75
Including hedges	$	55.90	$	45.60	$	34.61
Average Transportation Cost
United States
Natural gas ($/Mcf)	$	0.24	$	0.20	$	0.17
Oil, condensate and NGL ($/Bbl)	$	0.85	$	0.69	$	1.16
Worldwide
Natural gas ($/Mcf)	$	0.23	$	0.18	$	0.17
Oil, condensate and NGL ($/Bbl)	$	0.82	$	0.63	$	1.12
Average Production Cost($/Mcfe)(2)
United States
Average lease operating cost	$	0.97	$	0.73	$	0.62
Average production taxes		0.28		0.27		0.11
Total production cost	$	1.25	$	1.00	$	0.73
Brazil
Average lease operating cost	$	0.28	$	0.42	$	—
Average production taxes		0.53		—		—
Total production cost	$	0.81	$	0.42	$	—
Worldwide
Average lease operating cost	$	0.95	$	0.72	$	0.60
Average production taxes		0.29		0.24		0.11
Total production cost	$	1.24	$	0.96	$	0.71
Unconsolidated affiliate volumes (Four Star)(3)
Natural gas (MMcf)		18,140		6,689
Oil, condensate and NGL (MBbls)		1,087		359
Total equivalent volumes MMcfe		24,663		8,844
MMcfe/d		68		24

(1)	Production volumes in Brazil decreased due to a contractual reduction of our ownership interest in the Pescada-Arabaiana Field in 2006.
(2)	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).
(3)	Includes our proportionate share of volumes in Four Star which was acquired in the third quarter of 2005.

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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:

	2006		2005		2004
	(In millions)
United States
Acquisition Costs:
Proved	$	2	$	643	$	33
Unproved		34		143		32
Development Costs		738		503		395
Exploration Costs:
Delay rentals		6		3		7
Seismic acquisition and reprocessing		23		7		29
Drilling		294		133		149
Asset Retirement Obligations		3		1		30
Total full cost pool expenditures		1,100		1,433		675
Non-full cost pool expenditures		8		22		11
Total cost incurred(1)	$	1,108	$	1,455	$	686
Acquisition of unconsolidated investment in Four Star(1)	$	—	$	769	$	—
Brazil and Egypt
Acquisition Costs:
Proved	$	2	$	8	$	69
Unproved		1		1		3
Development Costs		40		6		1
Exploration Costs:
Seismic acquisition and reprocessing		7		7		15
Drilling		46		8		10
Asset Retirement Obligations		—		—		3
Total full cost pool expenditures		96		30		101
Non-full cost pool expenditures		—		—		3
Total cost incurred	$	96	$	30	$	104
Worldwide
Acquisition Costs:
Proved	$	4	$	651	$	102
Unproved		35		144		35
Development Costs		778		509		396
Exploration Costs:
Delay rentals		6		3		7
Seismic acquisition and reprocessing		30		14		44
Drilling		340		141		159
Asset Retirement Obligations		3		1		33
Total full cost pool expenditures		1,196		1,463		776
Non-full cost pool expenditures		8		22		14
Total cost incurred(1)	$	1,204	$	1,485	$	790
Acquisition of unconsolidated investment in Four Star(1)	$	—	$	769	$	—

⁽¹⁾ In 2005, amount includes $179 million of deferred income tax adjustments related to the acquisition of full-cost pool properties and $217 million related to the acquisition of our unconsolidated investment in Four Star.

     We spent approximately $192 million in 2006, $247 million in 2005 and $156 million in 2004 to develop proved undeveloped reserves that were included in our reserve report as of January 1 of each year.

Markets and Competition

     We primarily sell our domestic natural gas and oil to third parties through El Paso Marketing, L.P. (El Paso Marketing), an indirect wholly-owned subsidiary of El Paso, 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 to Petrobras, Brazil’s state-owned energy company. We also 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 to protect the economic assumptions associated with our capital investment programs. As of December 31, 2006, we had entered into derivative contracts on approximately 133,000 BBtu of our

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anticipated natural gas production in 2007 and approximately 21,000 BBtu of our anticipated natural gas production from 2008 through 2012. We also have derivative contracts on our Brazilian oil production that provide us with a fixed price on approximately 192 MBbls in 2007. 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 the exploration and production business will be dependent on our ability to find or acquire additional reserves at costs that yield acceptable returns on the capital invested.

Regulatory and Operating 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, the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners. We are also subject to governmental and 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 Brazil and Egypt exploration and production operations are subject to environmental regulations administered by those countries, which includes political subdivisions in those countries. These domestic and international laws and regulations relating to the protection of the environment affect our natural gas and oil operations through their effect on the construction and operation of facilities, water disposal rights, drilling operations, production or the delay or prevention of future offshore lease sales. In addition, El Paso maintains insurance on our behalf to limit exposure to sudden and accidental spills and oil pollution liability.

Environmental

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

Employees

     As of February 1, 2007 we had approximately 1,031 full-time employees, none of whom are subject to collective bargaining arrangements.

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 or 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.

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Risks Related to Our Business

Natural gas and oil prices are volatile. A substantial decrease in natural gas and oil prices could adversely affect our financial results.

     Our future financial condition, revenues, results of operations, cash flows and future rate of growth 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. These factors include:

• the level of consumer demand for, and the supply of, natural gas and oil;

• the availability and reliability of commodity processing, gathering and pipeline capacity;

• the level of imports of, and the price of, foreign natural gas, LNG, and oil;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• domestic governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions, such as unusually warm or cold weather and hurricanes in the Gulf of Mexico;

• market uncertainty;

• political conditions or hostilities in natural gas and oil producing regions;

• worldwide economic conditions; and

• changes in demand for the use of natural gas and oil because of changes in weather patterns and market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.

     Further, because the majority of our proved reserves at December 31, 2006 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 significant decline in natural gas and oil prices could result in a downward revision of our reserves and a full cost ceiling test write-down in the carrying value of our natural gas and oil properties, which could be substantial and would negatively impact our net income and stockholder’s equity.

Our use of hedging arrangements may adversely affect our future results of operations or liquidity.

     To reduce our exposure to fluctuations in the prices of natural gas and oil, we enter into futures, swaps and option contracts traded on the New York Mercantile Exchange (NYMEX), over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions. We also enter into hedging arrangements with our affiliate El Paso Marketing. Hedging arrangements expose us to risk of financial loss in some circumstances, including if:

• expected production is less than the amount hedged; or

• the counterparty to the hedging contract defaults on its contractual obligations.

Further, our hedging arrangements limit the benefit we would receive from increases in the prices for natural gas and oil.

     The use of derivatives also may require the posting of cash collateral with counterparties which can impact working capital when commodity prices change. El Paso provides us with natural gas marketing and hedging services and we

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currently do not post cash collateral with counterparties. In addition, these hedging arrangements may impact the carrying value of our natural gas and oil properties in our full cost pool as we include hedges in our ceiling test calculation.

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

     Estimating quantities of proved natural gas and oil reserves is a complex process that involves significant interpretations and assumptions. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geographical and engineering data. 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. 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 producing 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 reserves, as prescribed by the SEC, which may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the natural gas and oil industry, in general, are subject. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions could cause the estimated quantities and net present value of our reserves to differ materially.

     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 stockholder’s equity.

     A portion of our estimated proved reserves are undeveloped. Recovery of undeveloped 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.

The success of our 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 or 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 reserves, cash flows and results of operations.

The success of our business is dependent, in part, on factors that are beyond our control.

     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 significant increases in 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;

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

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• increased federal or state regulations, including environmental regulations, that limit or restrict the ability to drill natural gas or oil wells, 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 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 to fund drilling programs to develop and replace a reserve base with rapid depletion characteristics.

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 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 by governmental authorities based on environmental and other considerations. 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.

     El Paso maintains insurance coverage on our behalf to reduce exposure to potential losses resulting from these operating hazards. The nature of the risks is such that some liabilities could exceed our insurance policy limits, or, as in the case of environmental fines and penalties, cannot be insured, which could adversely affect our future results of operations, cash flows or financial condition.

     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 because 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.

Our drilling operations may be delayed or canceled as a result of factors beyond our control, resulting in significant costs to us.

     Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors that are beyond our control, including:

• unexpected drilling conditions;

• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

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• adverse weather conditions;

• compliance with environmental and other governmental requirements; and

• costs of, or shortages or delays in the availability of, drilling rigs, oil field equipment, qualified personnel and services.

     A delay or curtailment of our operations due to these or other factors can result in significant costs or significant reductions in revenue to us. These types of shortages or cost increases could significantly decrease our profit margin, cash flow and operating results or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted. Future drilling, production and development costs have a major impact on our ability to earn adequate returns on invested capital and to generate positive cash flow.

We are vulnerable to risks associated with operating in the Gulf of Mexico.

     Our operations and financial results could be significantly impacted by conditions in the Gulf of Mexico because we explore and produce in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the Gulf of Mexico, including those relating to:

• adverse weather conditions;

• oil field service costs and availability;

• compliance with environmental and other laws and regulations;

• remediation and other costs resulting from oil spills or releases of hazardous materials; and

• failure of equipment or facilities.

     Further, production of reserves from reservoirs in the shallow waters of the Gulf of Mexico shelf generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production, and as a result, our reserve replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

Our foreign operations and investments involve special risks.

     Our activities in areas outside the United States, including exploration and production projects in Brazil and Egypt, 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 including:

• loss of revenue, property and equipment as a result of hazards such as wars and 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 or other regulatory approvals necessary to conduct our operations.

Our growth may be dependent upon successful acquisitions which are subject to many uncertainties and could subject us to significant unknown liabilities.

     We expect that acquisitions of exploration and production businesses, producing properties and undeveloped properties will contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, exploration or development potential,

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future natural gas and oil prices, operating costs, title to properties and potential environmental and other liabilities. We face significant operational, execution and integration risks when our acquisitions consist primarily of proved undeveloped reserves or exploration prospects. Our assessments are based on factors that are inherently uncertain. If we are unable to make successful acquisitions, the growth of our company may be negatively impacted.

     In connection with our acquisitions we are often not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities associated with acquired properties. We may acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. We may not be able to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Our review prior to signing a definitive purchase agreement may be even more limited. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage.

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

Risks Related to Legal and Regulatory Matters

Ongoing litigation and investigations related to the restatement of our financial statements associated with our reserve estimates could significantly adversely affect our business.

     In 2004, we restated our historical financial statements as a result of a downward revision in our natural gas and oil reserves. The restatement related to the manner in which we applied the accounting rules related to some of our historical hedges and the classification of amounts in our historical statements of cash flows for amounts provided to El Paso under its cash management program. As a result of this reduction in reserve estimates, several class action lawsuits were filed against El Paso and several of its subsidiaries. The reserve revisions are also the subject of an investigation by the SEC and may result in significant fines to El Paso. These investigations and lawsuits, and possible future claims based on these same facts, may further negatively impact El Paso’s and our credit ratings and place further demands on El Paso’s and our liquidity. We cannot provide assurance at this time that the effects and results of these or other investigations or of the class action lawsuits will not be material to our financial condition, results of operations and liquidity.

We are subject to complex laws and regulations, including environmental and safety regulations that can negatively affect the cost, manner or feasibility of doing business.

     Our operations and facilities are subject to certain federal, state and local laws and regulations relating to the exploration for, and development, production, processing, treating, transportation and sale of, natural gas and oil, as well as environmental and safety matters. Additionally, current or future tax policies, rates, and drilling or production incentives by federal, state and local governments impact our operations and the ability to operate profitably.

     Under these laws and regulations, we could be liable for:

• personal injuries;

• property and natural resource damages;

• oil spills and releases or discharges of hazardous materials;

• well reclamation costs;

• remediation and clean-up costs and other governmental sanctions, such as fines and penalties; and

• other environmental damages.

     Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations could harm our business, results of operations and financial condition. Increased federal or state regulations, including environmental regulations, could limit or restrict the ability to drill natural gas or oil wells, reduce operational flexibility, or increase capital and operating costs. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations. In addition, our operations could be significantly delayed

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or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

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

     Our operations are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation and remediation or clean-up of contaminated properties (one of which has been designated as a Superfund site by the Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)), as well as damage claims arising out of the contamination of properties or impact on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate exactly the 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 Part II, Item 8, Financial Statements and Supplementary Data, Note 7. These uncertainties include:

• estimating pollution control and clean up costs, including sites for which only preliminary site investigation or assessments have been completed;

• discovering new sites or additional information at existing sites;

• quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties (PRPs); and

• evaluating and understanding environmental laws and regulations, including their interpretation and enforcement.

     Currently, various legislative and regulatory measures to address greenhouse gas (GHG) emissions (including carbon dioxide and methane) are in various phases of discussion or implementation. These include the Kyoto Protocol, proposed federal legislation and state actions to develop statewide or regional programs, each of which have imposed or would impose reductions in GHG emissions. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. These actions could also impact the consumption of natural gas and oil, thereby affecting our operations.

Risks Related to Our Affiliation with El Paso

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

We are a wholly-owned direct subsidiary of El Paso and its financial condition and business strategy subjects us to potential risks that are beyond our control.

     Subject to the limitations in our credit agreements and in our indentures, El Paso has substantial control over:

• our payment of dividends;

• decisions on our financings and our capital raising activities;

• mergers or other business combinations;

• our acquisitions or dispositions of assets; and

• our participation in El Paso’s cash management program.

     El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.

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     Due to our relationship with El Paso, adverse developments or announcements concerning El Paso could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated B2 by Moody’s Investor Service and B by Standard & Poor’s and El Paso is on a positive outlook with these agencies. The ratings assigned to our senior unsecured indebtedness are currently rated B1 by Moody’s Investor Service and B+ by Standard & Poor’s and we are on a positive outlook with these agencies. Downgrades of our credit ratings could increase our cost of capital and collateral requirements, and could impede our access to capital markets.

     We participate in El Paso’s cash management program, which matches cash surpluses and needs for its participating affiliates. If El Paso is unable to meet its liquidity needs, there can be no assurance that we will be able to access cash under the cash management program, or that our affiliates would pay their obligations to us. However, we might still be required to satisfy affiliated company payables. Our inability to borrow or recover such amounts could adversely affect our ability to repay our outstanding indebtedness. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 9.

ITEM 1B. UNRESOLVED STAFF COMMENTS

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

ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

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

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

     Item 4, Submission of Matters to a Vote of Security Holders, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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PART II

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

     All of our common stock, par value $1 per share, is owned by El Paso and, accordingly, our stock is not publicly traded. Subject to certain limitations, we pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. During 2005 and 2004 we declared dividends to El Paso of $199 million and $138 million, which included, $16 million and $81 million of non-cash dividends.

ITEM 6. SELECTED FINANCIAL DATA

     Item 6, Selected Financial Data has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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

     The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. The notes to our consolidated financial statements contain information that is pertinent to the following analysis, including a discussion of our significant accounting policies.

     Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risks and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed beginning on page 9.

     On December 31, 2005, El Paso made a capital contribution to us of several domestic exploration and production companies. On October 1, 2006, El Paso also contributed its current international exploration and production businesses to us. The financial information in this section reflects the combined results of our historically reported operations and those of the contributed properties for all periods presented.

Overview and Strategy

     Our business consists of natural gas and oil exploration and production activities. Our operating results are driven by the ability to locate and develop economic natural gas and oil reserves and extract those reserves with 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 domestic natural gas and oil reserve portfolio blends slower decline rate, typically longer-lived assets in our Onshore region with steeper decline rate, shorter-lived assets in our Texas Gulf Coast and Gulf of Mexico Shelf and south Louisiana regions. We believe the combination of our assets in these regions provides significant near-term cash flow while providing consistent opportunities for competitive investment returns. In addition, our international activities in Brazil and Egypt provide opportunity for significant reserve additions and longer term cash flows.

     As part of our business strategy, we attempt to create value through our drilling activities and through acquisitions of assets and companies. For 2007, we expect our growth to occur principally through drilling activities. However, we believe strategic acquisitions can support our objectives by:

• Re-shaping our portfolio to provide greater optionality for achieving our long term performance goals;

• Leveraging operational expertise we already possess in key operating areas, geologies or techniques;

• Balancing our exposure to regions, basins and commodities;

• Achieving risk-adjusted returns competitive with those available within our existing inventory; and

• Increasing our reserves more rapidly by supplementing our current drilling inventory.

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     In addition to executing on our strategy, our profitability and performance can be substantially impacted by (i) changes in commodity prices, (ii) industry-wide increases in drilling and oilfield service costs, 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 have entered into derivative contracts on a portion of our natural gas and oil production to reduce the financial impact of downward commodity price movements. We are also actively managing increases in operating and capital costs.

Significant Operational Factors Affecting the Year Ended December 31, 2006

Production.Our average daily production for the year was approximately 730 MMcfe/d (excluding 68 MMcfe/d from our equity investment in Four Star). Our production levels grew in every quarter of 2006. However, our average daily production was lower than originally expected primarily due to events in our Gulf of Mexico Shelf and Onshore regions. Below is a further analysis our 2006 production by region (MMcfe/d):

	2006		2005		2004
United States
Onshore		345		300		231
Texas Gulf Coast(1)		187		211		283
Gulf of Mexico Shelf / south Louisiana		174		179		276
		706		690		790
International
Brazil(2)		24		53		24
Total Consolidated		730		743		814
Four Star(3)		68		24		—

(1)	During 2006, we completed the sale of certain non-strategic south Texas properties with production of five MMcfe/d for $80 million.
	In January 2007, we acquired certain properties with net production of approximately 12 MMcfe/d on the acquisition date.
(2)	Production volumes decreased due to contractual reduction of our ownership interest in the Pescada-Arabaiana Field in 2006.
(3)	Amounts represent our proportionate share of the production of Four Star which was acquired in the third quarter of 2005.

     In our Onshore region, we have increased our 2006 production through drilling programs and the Medicine Bow acquisition in 2005 despite the impact of higher maintenance activities and delivery delays for two rigs contracted in East Texas reducing our expected 2006 production. In the Texas Gulf Coast, we were able to stabilize production levels after a repositioning effort in the region in 2004. In the Gulf of Mexico Shelf/south Louisiana, production in both 2005 and 2006 was adversely effected by hurricanes Katrina and Rita and construction delays on certain new wells in 2006. However, we were successful in developing projects in the West Cameron area and our Catapult project that helped offset natural declines. In Brazil, a contractual reduction of our ownership interest in the Pescada-Arabaiana fields in early 2006 resulted in a decrease in production.

2006 Drilling Results

Onshore.We drilled 604 successful gross wells out of 606 gross wells drilled.

Texas Gulf Coast.We experienced an 88 percent success rate on 49 gross wells drilled.

Gulf of Mexico Shelf and south Louisiana.We experienced an 82 percent success rate on 17 gross wells drilled. We placed ten new wells in production, including five wells in south Louisiana, and five wells in the Gulf of Mexico. We expect an additional four wells drilled in 2006 to come on production in early 2007.

Brazil.In the Pinauana Field in the Camamu basin, we filed a plan of development, signed a rig contract and commenced drilling on the first two exploratory wells in February 2007. Additionally, in the ES-5 Block in the Espirito Santo Basin, we continue to discuss a possible exploration well with Petrobras.

Egypt.We were the winning bidder of the South Mariut Block in the second quarter of 2006 with a $3 million payment due on final receipt of the concession and an agreement for a $22 million firm working commitment over three years. The block is approximately 1.2 million acres and is located onshore in the western part of the Nile Delta. We expect to receive formal governmental approvals and sign the concession agreement during the first quarter of 2007.

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Cash Operating Costs. We monitor cash operating costs to determine the amount of cash required to produce our natural gas and oil volumes. These costs are calculated on a per MMcfe basis and are calculated as total operating expenses less depreciation or depletion, and amortization expense, other non-cash items, and cost of products and services on our income statement. In 2006, cash operating costs increased to $1.86/MMcfe from $1.67/MMcfe in 2005. Our operating cost increases were primarily a result of inflation in the cost of fuel, power, and other services, increases in subsurface maintenance in certain Onshore fields and unrecoverable hurricane repair costs, among other items. We do not expect a significant amount of costs in 2007 related to hurricanes Katrina and Rita.

Reserve Replacement Costs / Reserve Replacement Ratio.We calculate two primary metrics, (i) a reserve replacement ratio and (ii) a reserve replacement cost, 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 cost to assess the cost of adding reserves which is ultimately included in deprecation, 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 a lower cost than our competition. We calculate these ratios as follows:

Reserve replacement ratio	Sum of reserve additions(1)
	Actual production for the corresponding period
Reserve replacement cost / Mcfe	Total oil and gas capital costs(2)
	Sum of reserve additions(1)

(1)

Reserve additions include proved reserves and reflect reserve revisions, 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. Amounts are derived directly from the proved reserves table presented in Item 8, Financial Statements and Data, Supplementary Oil and Gas Operations.

(2)

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 cost incurred table presented in Item 8, Financial Statements and Data, Supplementary Oil and Gas Operations.

     Both the reserve replacement ratio and reserve replacement cost 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 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 and undeveloped. At December 31, 2006, proved developed reserves represents approximately 71 percent of total proved reserves. Proved developed reserves will generally begin producing within the year they are added whereas proved undeveloped reserves generally require a major future expenditure.

     The table below shows our reserve replacement costs and reserve replacement ratio for each of the three years ended December 31:

	2006		2005		2004
			$/ Mcfe
Reserve replacement costs, including acquisitions		4.17		2.75		21.85
Reserve replacement costs, excluding acquisitions		4.19		3.19	NA(1)
			% of Production
Reserve replacement ratio, including acquisitions		108		195		11
Reserve replacement ratio, excluding acquisitions		107		93		(10	)

⁽¹⁾ Not meaningful in 2004 due to downward revisions in previous estimate of reserves.

     In 2006, our reserve replacement costs increased primarily due to industry service cost inflation and mechanical problems incurred in executing our drilling program, downward revisions in previous estimates of reserves due to lower commodity prices at December 31, 2006 and international capital investments where proved reserves have yet to be recorded. In 2004, our reserve replacement ratio was negatively

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impacted by downward revisions in previous estimates of reserves. We typically cite reserve replacement costs in the context of a multi-year trend, in recognition of its limitation as a single year measure, but also to demonstrate consistency and stability, which are essential to our business model. For the three year period ending December 31, 2006, our average reserve replacement costs were $3.99/Mcfe including acquisitions and $5.20/Mcfe excluding acquisitions.

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

	2006			2005			2004
Total oil and gas capital(1)	$	1,193		$	1,462		$	743
Less: acquisition capital		(4	)		(651	)		(102	)
Capital expenditures, excluding acquisitions	$	1,189		$	811		$	641

⁽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 cost incurred table presented in Item 8, Financial Statements and Supplementary Data, Supplemental Natural Gas and Oil Operations.

Outlook for 2007

     For 2007, we anticipate the following on a worldwide basis:

• Average daily production volumes for the year of approximately 740 MMcfe/d to 795 MMcfe/d, which excludes approximately 60 to 65 MMcfe/d from our equity investment in Four Star. Our goal is to achieve a three to eight percent average annual production growth over the next several years.

• Capital expenditures, excluding acquisitions, between $1.4 billion and $1.5 billion, which represent a 20 percent increase over 2006. While 85% of our planned 2007 capital program is allocated to our domestic program, we plan to spend $215 million in international capital in 2007, primarily in our Brazil exploration and development program. In January 2007, we acquired producing properties and undeveloped acreage in Zapata County, Texas, for $249 million, which complement our existing Texas Gulf Coast operations and provide a re-entry into the Lobo trend. The assets acquired had net production of approximately 12 MMcfe/d on the acquisition date. Estimated proved reserves were approximately 84 Bcfe, of which approximately 73 percent was undeveloped.

• Average cash operating costs, which include production costs, general and administrative expenses and other expenses, of approximately $1.68/Mcfe to $2.00/Mcfe for the year; and

• Depreciation, depletion and amortization rate of between $2.60/Mcfe and $2.85/Mcfe in the first quarter of 2007 compared with $2.68/Mcfe in the fourth quarter of 2006.

Price Risk Management Activities

     We enter into derivative contracts on our natural gas and oil production to stabilize cash flows, to 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 this strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. The following table and discussion that follows shows the contracted volumes and the minimum, maximum and average prices we will receive under these contracts when combined with the sale of the underlying hedged production as of December 31, 2006:

	Fixed Price												Basis
	Swaps(1)				Floors(1)				Ceilings(1)				Swaps(1)(2)
	Volumes		Price		Volumes		Price		Volumes		Price		Volume
Natural Gas
2007		78	$	7.70		55	$	8.00		55	$	16.89		110
2008		5	$	3.42		—		—		—		—		—
2009		5	$	3.56		—		—		—		—		—
2010-2012		11	$	3.81		—		—		—		—		—
Oil
2007		192	$	35.15		—		—		—		—		—

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(1)	Volumes presented are TBtu for natural gas. Prices presented are per MMBtu of natural gas.
(2)	Our basis swaps effectively “lock-in” locational price differences on a portion of our natural gas production in Texas and Oklahoma.

     Our natural gas fixed price swap, floor and ceiling contracts in the table above are designated as accounting hedges. Gains and losses associated with these natural gas contracts are deferred in accumulated other comprehensive income and will be recognized in earnings upon the sale of the related production at market prices, resulting in a realized price that is approximately equal to the hedged price. Our oil swaps and approximately 51 TBtu of our natural gas basis swaps are not designated as hedges. Accordingly, changes in the fair value of these swaps are not deferred, but are recognized in earnings each period.

     The table above does not include derivative contracts we terminated in the fourth quarter of 2006 on which we will record an additional $62 million of gains (before income taxes) in 2007 which are currently deferred in accumulated other comprehensive income.

Results of Operations

Overview

     Our management as well as El Paso’s management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business which consists of consolidated operations as well as investments in unconsolidated affiliates. We believe EBIT is useful to investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes and (iii) interest and debt expense. We exclude interest from this measure so that our readers may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow.

     The following is a reconciliation of EBIT to our net income for the years ended December 31:

	2006			2005
	(In millions)
Operating revenues	$	1,618		$	1,543
Operating expenses		(1,255	)		(1,166	)
Operating income		363			377
Other income, net		15			25
EBIT		378			402
Affiliated interest expense		(3	)		(61	)
Interest expense		(86	)		(83	)
Income taxes		(93	)		(96	)
Net income	$	196		$	162

Operating Results and Variance Analysis

     The tables below and the discussion that follows provide the operating results and an analysis of significant variances in these results during the years ended December 31:

	2006		2005
	(In millions, except
	volumes and prices)
Operating revenues:
Natural gas	$	1,170	$	1,138
Oil, condensate and NGL		430		371
Other		18		34
Total operating revenues		1,618		1,543
Operating expenses:
Depreciation, depletion and amortization		673		643
Production costs(1)		331		264

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	2006		2005
	(In millions, except
	volumes and prices)
Cost of product and services		87		62
General and administrative expenses		156		186
Other		8		11
Total operating expenses		1,255		1,166
Operating income		363		377
Other income, net(2)		15		25
EBIT	$	378	$	402

					Percent
	2006		2005		Variance
Consolidated volumes, prices and costs per unit:
Natural gas
Volumes (MMcf)		220,402		222,292		(1	)%
Prices ($/Mcf)(3)
Average realized prices including hedges	$	5.31	$	5.12		4	%
Average realized prices excluding hedges	$	6.64	$	7.53		(12	)%
Average transportation costs ($/Mcf)	$	0.23	$	0.18		28	%
Oil, condensate and NGL
Volumes (MBbls)		7,686		8,136		(6	)%
Prices ($/Bbl)(3)
Average realized prices including hedges	$	55.90	$	45.60		23	%
Average realized prices excluding hedges	$	56.21	$	46.43		21	%
Average transportation costs ($/Bbl)	$	0.82	$	0.63		30	%
Total equivalent volumes
Mmcfe		266,518		271,107		(2	)%
MMcfe/d		730		743		(2	)%
Production costs and other cash operating costs ($/Mcfe)
Average lease operating costs	$	0.95	$	0.72		32	%
Average production taxes		0.29		0.24		21	%
Total production costs(1)		1.24		0.96		29	%
Average general and administrative expenses		0.59		0.68		(13	)%
Average taxes other than production and income		0.03		0.03		—	%
Total cash operating costs(4)	$	1.86	$	1.67		11	%
Unit of production depletion cost ($/Mcfe)	$	2.39	$	2.21		8	%
Unconsolidated affiliate volumes (Four Star)(2)
Natural Gas (MMcf)		18,140		6,689
Oil, condensate and NGL (MBbls)		1,087		359
Total equivalent volumes
Mmcfe		24,663		8,844
MMcfe/d		68		24

(1)	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).
(2)	Includes equity earnings from our investment or proportionate share of volumes in Four Star acquired in the third quarter of 2005.
(3)	Prices are stated before transportation costs.
(4)	See further discussion on page 19.

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Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

     Our EBIT for 2006 decreased $24 million as compared to 2005. The table below lists the significant drivers of the variance in our operating results in 2006 as compared to 2005:

	Variance
	Operating			Operating
	Revenue			Expense			Other			EBIT
	Favorable/(Unfavorable)
	(In millions)
Natural Gas Revenue
Lower prices in 2006	$	(197	)	$	—		$	—		$	(197	)
Impact of hedges		243			—			—			243
Lower production volumes in 2006		(14	)		—			—			(14	)
Oil, Condensate and NGL Revenue
Higher realized prices in 2006		75			—			—			75
Impact of hedges		5			—			—			5
Lower production volumes in 2006		(21	)		—			—			(21	)
Depreciation, Depletion and Amortization Expense
Higher depletion rate in 2006		—			(49	)		—			(49	)
Lower production volumes in 2006		—			10			—			10
Other		—			10			—			10
Production Costs
Higher lease operating costs in 2006		—			(56	)		—			(56	)
Higher production taxes in 2006		—			(12	)		—			(12	)
General and administrative expenses		—			30			—			30
Earnings from unconsolidated affiliates(1)		—			—			(9	)		(9	)
Other
Change in fair value of oil and basis swaps		(31	)		—			—			(31	)
Processing plants		3			(14	)		—			(11	)
Other		12			(8	)		(1	)		3
Total Variances	$	75		$	(89	)	$	(10	)	$	(24	)

⁽¹⁾ We acquired Four Star in August 2005.

     Operating Revenues.Natural gas revenues decreased by approximately $197 million as natural gas prices were not as strong in 2006 as compared to 2005. However, we experienced lower hedging program losses for 2006 of $295 million compared to losses of $543 million in 2005. Realized oil, condensate and NGL prices increased in 2006 when compared to 2005.

     Our production volumes have benefited from our acquisitions in 2005. However, overall production volumes decreased in our Texas Gulf Coast and Gulf of Mexico Shelf and south Louisiana regions due to natural declines and the sale of certain non-strategic south Texas properties with average production of 5 MMcfe/d in 2006. Also, our Gulf of Mexico Shelf and south Louisiana region production continued to be impacted in 2006 by hurricanes Katrina and Rita which occurred in late 2005. Our production volumes in Brazil decreased due to the contractual reduction of our ownership interest in the Pescada-Arabaiana Field in 2006.

     Depreciation, depletion, and amortization expense.During 2006, we experienced higher depletion rates compared to 2005 as a result of higher finding and development costs and the cost of acquired reserves. However, lower production volumes in 2006 partially offset the impact of these higher depletion rates.

     Production costs.In 2006, our lease operating costs increased as compared to 2005 in all regions as a result of inflation in fuel cost, power, and other services. In our Onshore region, additional increases were due to increases in subsurface maintenance and our acquisition of Medicine Bow. In the Gulf of Mexico Shelf, additional increases were due to hurricane repairs not recoverable through insurance. Additionally, production taxes increased as a result of lower production tax credits in Texas taken in 2006 compared to 2005.

     General and administrative expenses.Our general and administrative expenses decreased during 2006 as compared to the same period in 2005 primarily due to lower cost allocation from El Paso.

     Other.During 2006, we recorded a loss of approximately $40 million for changes in the fair value of our derivative contracts that do not qualify for hedge accounting as compared to $9 million in 2005, primarily due to changes in basis

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differentials in south Texas and the Texas Panhandle. In 2006, our EBIT was also unfavorably impacted by earnings from Four Star due to lower natural gas prices and by operations at our processing plants. Our EBIT was favorably impacted by insurance recoveries from Hurricane Ivan in 2006.

Affiliated Interest Expense

     Affiliated interest expense for the twelve months ended December 31, 2006, was $58 million lower than the same period in 2005 due primarily to lower average advance balances under El Paso’s cash pool program. The average advance balances for the twelve months of 2006 decreased as compared to the same period in 2005 from $1.3 billion to $66 million. The decrease in the average advance balances is primarily due to the December 31, 2005 non-cash capital contributions from El Paso, which reduced amounts outstanding. The average short-term interest rates for the twelve month period increased to 5.7% in 2006 from 4.2% in 2005. For a discussion of the cash management program, see Item 8, Financial Statements and Supplementary Data, Note 9.

Interest Expense

     Interest expense for the year ended December 31, 2006 increased $3 million compared to the same period in 2005 due primarily to amounts borrowed under the $500 million revolving credit facility. We entered into the facility in conjunction with our Medicine Bow acquisition in August 2005.

Income Taxes

     Income taxes included in our income from continuing operations and our effective tax rates for the periods ended December 31 were as follows:

	Year Ended December 31,
	2006			2005
	(In millions, except for rates)
Income taxes	$	93		$	96
Effective tax rate		32	%		37	%

     Our effective tax rates for each period differed from the federal statutory rate of 35 percent, primarily due to earnings from unconsolidated affiliates where we anticipate receiving dividends that qualify for the dividend received deduction, and from state income taxes. See Part II, Item 8, Financial Statements and Supplementary Data, Note 3, for a reconciliation of the statutory rate to the effective rates.

Commitments and Contingencies

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

Liquidity

     Our primary sources of liquidity are cash generated from operations, advances from El Paso through its cash management program and our $500 million revolving credit facility (see Part II, Item 8, Financial Statements and Supplementary Data, Note 6). Other sources may include capital contributions from El Paso and our access to the capital markets. Under El Paso’s cash management program, depending on whether we have short-term cash surpluses or requirements, we either provide cash to El Paso, subject to limitations under our financing arrangements, or El Paso provides cash to us. Changes in overall amounts borrowed from El Paso under the cash management program are reflected as financing activities and changes in overall advances to El Paso are reflected as investing activities in our statement of cash flows. As of December 31, 2006, we had advanced $59 million to El Paso under El Paso’s cash management program. As of December 31, 2005, we had borrowed $255 million from El Paso.

     During 2006 we entered into new derivative option and swap contracts on our 2007 natural gas production. These contracts were executed under agreements that will not require us to post any incremental net cash margin in future periods since they are collateralized by the same natural gas and oil properties that collateralize our $500 million revolving credit facility. As of December 31, 2006, we had $145 million outstanding under the revolving credit facility. On January 4, 2007, we borrowed an additional $255 million under our $500 million revolving credit facility in connection with our acquisition of producing properties and undeveloped acreage in Zapata County, Texas. Based on our expected capital spending program, and

24

forecasted operating cash flows using current projections of the amounts of hedged production and current commodity price levels, we may be required to draw on our revolving credit facility or obtain advances from El Paso through the cash management program to fund a portion of our capital expenditures, and meet working capital and debt service needs.

New Accounting Pronouncements Issued But Not Yet Adopted

     See Part II, Item 8, Financial Statements and Supplementary Data, Note 1 underNew Accounting Pronouncements Issued But Not Yet Adopted.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We use derivative financial instruments and energy related contracts to manage market risks associated with natural gas and oil. Our primary market risk exposures are those related to changing commodity prices. Our market risks are monitored by El Paso’s Corporate Risk Management Committee to ensure compliance with the stated risk management policies.

Commodity Price Risk

     We have market risks related to the natural gas and oil we produce. Our primary commodity price risk is that natural gas and oil prices can decline, which impacts our sales revenue related to our natural gas and oil production. We attempt to mitigate commodity price risk and to stabilize cash flows associated with forecasted sales of our natural gas and oil production through the use of derivative contracts.

     The table below presents the hypothetical sensitivity to changes in fair values arising from immediate selected potential changes in the quoted market prices of the derivative commodity instruments used to mitigate these market risks. Any gain or loss on these derivative commodity instruments would be substantially offset by a corresponding gain or loss on the sale of the hedged commodity positions, which are not included in the table. These derivatives do not hedge all of our commodity price risk related to our forecasted sales of natural gas and oil production and as a result, we are subject to commodity price risks on our remaining forecasted natural gas and oil production.

				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			(Decrease)			Fair Value			Increase
							(In millions)
Impact of changes in commodity prices on derivative commodity instruments
December 31, 2006	$	35		$	(44	)	$	(79	)	$	118		$	83
December 31, 2005	$	(747	)	$	(850	)	$	(103	)	$	(641	)	$	106

Interest Rate Risk

     Our debt-related instruments are sensitive to changing interest rates. The table below shows the maturity of the carrying amounts and related weighted-average interest rates on our long-term interest-bearing securities as well as the total fair value of those securities. The fair values of our long-term debt securities have been estimated based on quoted market prices for the same or similar issues.

	December 31, 2006								December 31, 2005
	Expected Fiscal Year of
	Maturity of Carrying Amounts
							Fair		Carrying		Fair
	2010		Thereafter		Total		Value		Amounts		Value
	(In millions)
Long-term debt — 7.75% fixed rate		—	$	1,200	$	1,200	$	1,256	$	1,200	$	1,257
Long-term debt —LIBOR + (1.25% to 1.875%)(1)	$	145		—	$	145	$	145	$	500	$	500

⁽¹⁾ Interest rate varies depending on usage of our $500 million revolving credit facility.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

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

	Page
Reports of Independent Registered Public Accounting Firms		27
Consolidated Statements of Income		30
Consolidated Balance Sheets		31
Consolidated Statements of Cash Flows		32
Consolidated Statements of Stockholder’s Equity		33
Consolidated Statements of Comprehensive Income		33
Notes to Consolidated Financial Statements		34
1. Basis of Presentation and Summary of Significant Accounting Policies		34
2. Acquisitions and Divestitures		37
3. Income Taxes		38
4. Financial Instruments and Price Risk Management Activities		40
5. Property, Plant and Equipment		41
6. Debt and Available Credit Facilities		42
7. Commitments and Contingencies		42
8. Retirement Benefits		44
9. Investments in and Earnings from Unconsolidated Affiliates and Related Party Transactions		44
10. Consolidating Financial Statements		46
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)		54
Supplemental Natural Gas and Oil Operations (Unaudited)		54
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts		60

26

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
El Paso Exploration & Production Company:

     We have audited the accompanying consolidated balance sheet of El Paso Exploration & Production Company as of December 31, 2006, and the related consolidated statement of income, comprehensive income, stockholder’s equity, and cash flows for the year then ended. Our audit also included the financial statement schedule listed in the Index appearing under 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 audit. The financial statements of Four Star Oil and Gas Company (a corporation in which the Company has a 43.1 percent interest) has been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for Four Star Oil and Gas Company, is based solely on the report of the other auditors. In the consolidated financial statements, the Company’s investment in Four Star Oil and Gas Company, excluding excess purchase price, represents approximately 2% of total assets as of December 31, 2006, and the Company’s equity in the net income of Four Star Oil and Gas Company, before amortization of the excess purchase price, represents approximately 22% of income before income taxes for the year then ended.

     We conducted our audit 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for our opinion.

     In our opinion, based on our audit and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of El Paso Exploration & Production Company at December 31, 2006, and the consolidated results of its operations and its cash flows for the year then ended, 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, present fairly in all material respects the information set forth therein.

     As discussed in Note 1 to the consolidated financial statements, on October 1, 2006 El Paso Corporation contributed its international exploration and production businesses owned by several of El Paso Corporation’s subsidiaries to El Paso Exploration & Production Company. These contributions were accounted for as a transaction between entities under common control. Accordingly, the consolidated financial statements present the businesses on a combined basis for all periods presented.

/s/ Ernst & Young LLP

Houston, Texas
February 26, 2007

27

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of
El Paso Exploration & Production Company:

In our opinion, the accompanying consolidated balance sheet as of December 31, 2005 and the related consolidated statements of income, comprehensive income, stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2005 present fairly, in all material respects, the financial position of El Paso Exploration & Production Company and its subsidiaries (the “Company”) at December 31, 2005, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2005 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule 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 of financial statements 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 discussed in Note 1 to the consolidated financial statements, on October 1, 2006 El Paso Corporation contributed its international exploration and production businesses to the Company. This contribution was accounted for as a transaction between entities under common control. Accordingly, the consolidated financial statements for all periods have been presented on a combined basis as though the Company had always owned these businesses.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 28, 2007

28

Report of Independent Registered Public Accounting Firm

To the Stockholders of Four Star Oil & Gas Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Four Star Oil & Gas Company (the “Company”) and its subsidiary at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 Note 3 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

February 23, 2007

Houston, Texas

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EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME
(In millions)

	Year Ended December 31,
	2006			2005			2004
Operating revenues
Natural gas and oil sales
Third parties	$	729		$	777		$	579
Affiliates		871			732			952
Other		18			34			23
		1,618			1,543			1,554
Operating expenses
Cost of sales		87			62			60
Operation and maintenance		409			387			377
Depreciation, depletion and amortization		673			643			585
Taxes, other than income taxes		86			74			34
		1,255			1,166			1,056
Operating income		363			377			498
Earnings from unconsolidated affiliates		10			19			4
Other income		5			6			3
Interest expense
Third parties		(86	)		(83	)		(74	)
Affiliated		(3	)		(61	)		(28	)
Income before income taxes		289			258			403
Income taxes		(93	)		(96	)		(142	)
Net income	$	196		$	162		$	261

See accompanying notes.

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EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)

	December 31,			December 31,
	2006			2005
ASSETS
Current assets
Cash and cash equivalents	$	132		$	60
Accounts receivable
Customer, net of allowance of $8 in 2006 and $10 in 2005		54			62
Affiliates		291			355
Other		122			83
Notes receivable from affiliate		59			75
Assets from price risk management activities		144			—
Deferred income taxes		73			221
Other		48			76
Total current assets		923			932
Property, plant and equipment, at cost
Natural gas and oil properties
Proved properties, at full cost		16,042			15,135
Unevaluated costs excluded from amortization		410			491
Other		119			141
		16,571			15,767
Less accumulated depreciation, depletion and amortization		(11,383	)		(10,993	)
Total property, plant and equipment, net		5,188			4,774
Other assets
Investments in unconsolidated affiliates		729			761
Deferred income taxes		43			57
Other		42			41
		814			859
Total assets	$	6,925		$	6,565
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	82		$	97
Affiliates		19			32
Other		267			180
Notes payable to affiliate		—			255
Liabilities from price risk management activities		41			631
Asset retirement obligations		56			31
Income taxes payable		106			8
Other		42			35
Total current liabilities		613			1,269
Long-term debt		1,345			1,700
Other
Liabilities from price risk management activities		68			116
Deferred income taxes		408			288
Asset retirement obligations		133			163
Other		46			53
		655			620
Commitments and contingencies
Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized and outstanding		—			—
Additional paid-in capital		4,310			3,703
Accumulated deficit		(82	)		(278	)
Accumulated other comprehensive income (loss)		84			(449	)
Total stockholder’s equity		4,312			2,976
Total liabilities and stockholder’s equity	$	6,925		$	6,565

See accompanying notes.

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EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)

	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities
Net income	$	196		$	162		$	261
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		673			643			585
Deferred income tax expense		(8	)		88			169
Earnings from unconsolidated affiliates, adjusted for cash distributions		34			15			(4	)
Other non-cash items		4			—			8
Asset and liability changes
Accounts and notes receivable		37			(210	)		(23	)
Accounts payable		(28	)		32			(6	)
Price risk management activities		50			(17	)		2
Affiliate income taxes		137			(10	)		(166	)
Other asset changes		(18	)		13			(16	)
Other liability changes		(19	)		(33	)		(62	)
Net cash provided by operating activities		1,058			683			748
Cash flows from investing activities
Capital expenditures		(1,114	)		(827	)		(719	)
Net proceeds from the sale of assets		122			10			14
Cash paid for acquisitions, net of cash acquired		—			(1,025	)		(49	)
Change in note receivable from affiliate		16			(52	)		215
Change in restricted cash		(1	)		3			(11	)
Net cash used in investing activities		(977	)		(1,891	)		(550	)
Cash flows from financing activities
Repayment of amounts borrowed under revolving credit		(530	)		—			—
Net proceeds from borrowings under revolving credit facility		175			495			—
Dividends to parent		—			(183	)		(57	)
Contributions from parent		500			262			137
Change in note payable with affiliate		(154	)		547			(180	)
Net cash provided by (used in) financing activities		(9	)		1,121			(100	)
Change in cash and cash equivalents		72			(87	)		98
Cash and cash equivalents
Beginning of period		60			147			49
End of period	$	132		$	60		$	147
Supplemental Cash Flow Information
Interest paid, net of amounts capitalized	$	91		$	141		$	103
Income tax payments (refunds)		(36	)		45			180

See accompanying notes.

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EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(In millions, except share amounts)

	For the Years Ended December 31,
	2006					2005					2004
	Shares		Amount			Shares		Amount			Shares		Amount
Common stock, $1.00 par:
Balance at beginning of year		1,000	$	—			1,000	$	—			1,000	$	—
Balance at end of year		1,000		—			1,000		—			1,000		—
Additional paid-in capital:
Balance at beginning of year				3,703					2,287					2,242
Contributions from parent				607					1,615					182
Allocated tax benefit (expense) of equity plans				—					—					1
Dividends to parent				—					(199	)				(138	)
Balance at end of year				4,310					3,703					2,287
Accumulated deficit:
Balance at beginning of year				(278	)				(440	)				(701	)
Net income				196					162					261
Balance at end of year				(82	)				(278	)				(440	)
Accumulated other comprehensive income (loss):
Balance at beginning of year				(449	)				(269	)				(241	)
Other comprehensive income (loss)				533					(180	)				(28	)
Balance at end of year				84					(449	)				(269	)
Total stockholder’s equity		1,000	$	4,312			1,000	$	2,976			1,000	$	1,578

See accompanying notes.

EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)

	Year Ended December 31,
	2006		2005			2004
Net income	$	196	$	162		$	261
Net gains (losses) from cash flow hedging activities:
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $201, $275 and $100 in 2006, 2005 and 2004)		357		(493	)		(176	)
Reclassification adjustments for changes in initial value to settlement date (net of income taxes of $99, $176 and $85 in 2006, 2005 and 2004)		176		313			148
Other comprehensive income (loss)		533		(180	)		(28	)
Comprehensive income (loss)	$	729	$	(18	)	$	233

See accompanying notes.

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EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation and Consolidation

     We are a Delaware corporation formed in 1999 as a wholly-owned direct subsidiary of El Paso Corporation (El Paso). We engage in the exploration for and the acquisition, development, and production of natural gas, oil and NGL in the United States and internationally. On December 31, 2005, El Paso contributed the domestic exploration and production businesses owned by of one of its subsidiaries, El Paso CGP, to us. In addition, on October 1, 2006, El Paso contributed its international exploration and production businesses to us. These contributions were part of El Paso’s ongoing simplification of its business structure which included combining all of its exploration and production activities under one reporting entity. We accounted for these contributions as a transaction between entities under common control. Accordingly, our financial statements for all periods have been adjusted to include the combined statements of income, balance sheet, cash flows and comprehensive income as though we always owned these businesses.

     The natural gas and oil properties contributed to us by El Paso are reflected in these financial statements at El Paso’s basis in these properties. The domestic natural gas and oil properties were combined with our domestic historical properties to form a single combined domestic full cost pool. Accordingly, we have reflected the impact of combining these properties into one domestic full cost pool in our historical balance sheet and in our historical depletion expense, ceiling test charges, and gains/(losses) on asset sales in our historical income statements. Additionally, settlements under certain derivative contracts between the contributed businesses and El Paso affiliates related to the contributed natural gas and oil properties are reflected as dividends to our parent (refer to our statement of stockholder’s equity and Note 9 for the effect of these dividends on total stockholder’s equity).

     The following table reflects the effect on operating revenues and net income of the contribution of the international natural gas and oil properties to us by El Paso in 2006:

	Year Ended December 31,
	2006		2005			2004
	(In millions)
Operating revenues	$	24	$	54		$	27
Net income		3		(12	)		7

     Our consolidated financial statements include the accounts of all majority owned and controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and if 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 financial statements in conformity with U.S. generally accepted accounting principles (GAAP) which 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.

Cash and Cash Equivalents

     We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2006 and 2005, we had $12 million and $11 million of restricted cash in other non-current assets. This cash is restricted to collateralize letters of credit issued in connection with concessions for our operations in Brazil and Egypt.

Allowance for Doubtful Accounts

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We establish provisions for losses on accounts and notes receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.

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 acquisitions, 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 on a quarterly basis. We transfer unproved property costs into the amortizable base when properties are determined to have proved reserves. In addition, in areas where a natural gas or oil reserve base exists, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory dry holes are determined to be unsuccessful. Additionally, the amortizable base includes future development costs and 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, net of related income tax effects, are limited to a ceiling based on the present value of future net revenues discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, net of related income tax effects. We utilize end-of-period spot prices when calculating future net revenues unless those prices result in a ceiling test charge, in which case we evaluate price recoveries subsequent to the end of the period. If total capitalized costs exceed the ceiling, we are required to write-down our capitalized costs to the ceiling.. Any required write-downs are included in our income statement as a ceiling test charge. Our ceiling test calculations include the effects of derivative instruments we have designated as, and that qualify as, cash flow hedges of our anticipated future natural gas and oil production. Our ceiling test calculations exclude the estimated future cash outflows associated with asset retirement liabilities relating to proved developed reserves.

     When we sell or convey interests in our 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 our 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.

Property, Plant and Equipment (Other than Natural Gas and Oil Properties)

     Our, property, plant and equipment, other than our assets accounted for under the full cost method, is recorded at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our property, plant and equipment using the straight-line method over the useful lives of the assets ranging from three to 22 years.

Revenue Recognition

     Our revenues are derived primarily through the physical sale of natural gas, oil, condensate and NGL. Revenues from sales of these products are recorded upon delivery and the passage of title using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual natural gas 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 natural gas reserves for a given property, we record a liability. Costs associated with the transportation and delivery of production are included in cost of sales.

Environmental Costs and Other Contingencies

     Environmental Costs.We record liabilities at their undiscounted amounts on our balance sheet in other current and long-term liabilities when our 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

35

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 EPA or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

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

     Other Contingencies.We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of that contingency can be reasonably estimated, we accrue a liability for that loss. 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

     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. Our natural gas fixed price swap, floor and ceiling contracts and natural gas basis swaps that qualify for hedge accounting are designated as cash flow hedges.

     We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged forecasted transaction. We also regularly assess whether these derivatives are highly effective in offsetting changes in cash flows of the hedged items. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we discontinue the hedging relationship.

     Our derivative contracts are recorded at their fair value on our balance sheet as assets and liabilities from price risk management activities. Where we have a master netting agreement with a counterparty in place and have the legal right of offset, we present derivative assets and liabilities with the counterparty on a net basis. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. Receivables and payables resulting from the settlement of our derivative instruments are reported as either trade or affiliate receivables or payables.

     Changes in derivative fair values that are designated as cash flow hedges are deferred in accumulated other comprehensive income (loss) to the extent that they are effective and then recognized in earnings as a component of operating revenues in our income statement when the hedged transactions occur. The ineffective portion of a cash flow hedge’s change in value, if any, as well as changes in derivative fair values not designated as hedges, are recognized immediately in earnings as a component of operating revenue in our income statement. Cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows in our cash flow statement.

     See Note 4 for a further discussion of our price risk management activities.

Income Taxes

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

36

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

Accounting for Asset Retirement Obligations

     We account for our asset retirement obligations in accordance with FASB Statement No. 143,Accounting for Asset Retirement Obligationsand FASB Interpretation No. (FIN) 47,Accounting for Conditional Asset Retirement Obligations.We record a liability for legal obligations associated with the replacement, removal, or retirement of our long-lived assets. Our asset retirement liabilities are 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 long-lived 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 in depreciation, depletion and amortization expense in our income statement.

Evaluation of Prior Period Misstatements in Current Financial Statements

     In December 2006, we adopted the provisions of the Securities and Exchange Commission’s Staff Accounting Bulletin (SAB) No. 108.Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how to evaluate the impact of financial statement misstatements from prior periods that have been identified in the current year. The adoption of these provisions did not have any impact on our financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

     As of December 31, 2006, the following accounting standards and interpretations had not yet been adopted by us.

     Accounting for Uncertainty in Income Taxes.In July 2006, the FASB issued FIN No. 48,Accounting for Uncertainty in Income Taxes.FIN No. 48 clarifies SFAS No. 109,Accounting for Income Taxes,and requires us to evaluate our tax positions for all jurisdictions and for all years where the statute of limitations has not expired. FIN No. 48 requires companies 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 benefit for their tax positions. 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 ultimate settlement. The cumulative effect of applying this interpretation will be recorded as an adjustment to the beginning balance of accumulated deficit, or other components of stockholder’s equity, as appropriate, in the period of adoption. This interpretation is effective for fiscal years beginning after December 15, 2006, and we do not anticipate that it will have a material impact on our financial statements.

     Fair Value Measurements.In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements, which provides guidance on measuring the fair value of assets and liabilities in the financial statements. We will be required to adopt the provisions of this standard no later than 2008, and are currently evaluating the impact, if any, that it will have on our financial statements.

2. Acquisitions and Divestitures

     Zapata County.In January, 2007, we acquired operated producing properties and undeveloped acreage in Zapata County, Texas, with an average working interest of 85 percent, for $249 million. These properties complement our existing South Texas Wilcox operations and provide a re-entry into the Lobo area. The 23,000 net acres acquired in this transaction provide a multi-year drilling inventory with significant additional exploration and development drilling opportunities. On the date of acquisition, the assets had net production of approximately 12 MMcfe/d and estimated proved reserves of approximately 84 Bcfe, of which approximately 73 percent was undeveloped. We borrowed $255 million under our $500 million revolving credit facility on January 4, 2007 to fund this acquisition.

     Medicine Bow.In August 2005, we completed the acquisition of Medicine Bow, a privately held energy company, for total cash consideration of approximately $0.9 billion. Medicine Bow owns a 43.1 percent interest in Four Star, an unconsolidated affiliate. Our proportionate share of the operating results associated with Four Star is reflected as earnings from unconsolidated affiliates in our financial statements (see Note 9).

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     The Medicine Bow acquisition was accounted for using the purchase method of accounting. No goodwill was recorded associated with the acquisition. As part of our purchase price allocation, we allocated approximately $0.4 billion to property, plant and equipment (of which $0.3 billion related to properties in our natural gas and oil domestic full cost pool), $0.8 billion to our unconsolidated investment in Four Star, and $0.4 billion related to deferred tax liabilities. We have reflected Medicine Bow’s results of operations in our income statement beginning September 1, 2005. The following summary unaudited pro forma consolidated results of operations for the years ended December 31, 2005 and 2004 reflect the combination of our historical income statements with Medicine Bow’s, adjusted for certain effects of the acquisition and related funding. These pro forma results are prepared as if the acquisition had occurred as of the beginning of the periods presented and are not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at that date, nor are they necessarily indicative of future operating results.

	Year Ended
	December 31,
	2005(1)		2004
	(In millions)
Revenues	$	1,582	$	1,604
Net income		172		250

⁽¹⁾ Excludes a $13 million pre-tax charge for change in control payments triggered at Medicine Bow as a result of the acquisition.

     Other Acquisitions.During the first quarter of 2005, we also acquired properties including (i) a 100 percent interest in GMT, a company engaged in the exploration, development and production of natural gas and oil in east Texas for $181 million, or $178 million net of cash acquired, (ii) properties in south Texas for approximately $31 million and (iii) the interest held by one of the parties under net profit agreements for approximately $53 million.

     Divestitures.During 2006, we completed the sale of certain non-strategic south Texas and Brazilian natural gas and oil properties for approximately $122 million.

3. Income Taxes

     Pretax Income and Income Tax Expense.The tables below show our pretax income and the components of income tax expense for each of the three years ended December 31:

	2006			2005			2004
				(In millions)
Pretax Income (Loss)
U.S	$	287		$	264		$	400
Foreign		2			(6	)		3
	$	289		$	258		$	403
Income Tax Expense
Current
Federal	$	100		$	(7	)	$	(31	)
State		(1	)		2			1
Foreign		2			13			3
		101			8			(27	)
Deferred
Federal		(25	)		72			158
State		20			23			9
Foreign		(3	)		(7	)		2
		(8	)		88			169
Total income tax expense	$	93		$	96		$	142

     Effective Tax Rate Reconciliation.Our income taxes, included in net income, differ 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:

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	2006			2005			2004
	(In millions, except rates)
Income tax expense at the statutory federal rate of 35%	$	101		$	90		$	141
Increase (decrease)
State income tax, net of federal income tax benefit		12			16			6
Earnings from unconsolidated affiliates where we anticipate receiving dividends		(18	)		(11	)		—
Valuation allowances		19			—			—
Foreign income taxed at different rates		(20	)		6			5
Other		(1	)		(5	)		(10	)
Income tax expense	$	93		$	96		$	142
Effective tax rate		32	%		37	%		35	%

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

	2006			2005
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	410		$	274
Employee benefits		34			26
Investment in unconsolidated affiliates		197			214
Price risk management activities		1			—
Other		51			58
Total deferred tax liability		693			572
Deferred tax assets
Net operating loss and tax credit carryforwards		343			280
Price risk management activities		—			276
Other		75			6
Valuation allowances		(19	)		—
Total deferred tax asset		399			562
Net deferred tax liability	$	(294	)	$	(10	)

     Approximately $2 million of deferred tax liabilities are recorded as other current liabilities on our balance sheet as of December 31, 2006.

     Net operating loss and tax carryovers.The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2006:

	Amount		Expiration Year
	(In millions)
U.S. federal net operating loss	$	670		2017-2026
State net operating loss	$	249		2007-2024

     We also have U.S. federal alternative minimum tax carryforwards of approximately $26 million, which are carried forward indefinitely and capital loss carryforwards of $9 million for which the carryover period will end in 2008. We have foreign net operating loss carryforwards of $118 million and capital loss carryforwards of $56 million which are carried forward indefinitely. Usage of our federal carryover is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as separate return limitation year rules of IRS regulations.

     Cumulative undistributed earnings from 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, 2006, the portion of the cumulative undistributed earnings from these investments on which we have not recorded U.S. income taxes was approximately $2 million.

     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 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. 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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4. Financial Instruments and Price Risk Management Activities

     The following table presents the carrying amounts and estimated fair values of our financial instruments as of December 31:

	2006						2005
	Carrying			Fair			Carrying			Fair
	Amount			Value			Amount			Value
				(In millions)
Long-term debt	$	1,345		$	1,401		$	1,700		$	1,757
Net assets (liabilities) from price risk management activities
Derivatives with third parties		121			121			—			—
Derivatives with affiliate		(86	)		(86	)		(747	)		(747	)
Net assets (liabilities) from price risk management activities	$	35		$	35		$	(747	)	$	(747	)

     As of December 31, 2006 and 2005, the carrying amounts of cash and cash equivalents and trade receivables and payables represented fair value because of the short-term nature of these instruments. We estimated the fair value of debt with fixed interest rates based on quoted market prices for the same or similar issues.

     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. When our derivative contracts qualify for hedge accounting treatment, we designate them as hedges. Our derivative contracts are recorded at their fair value on our balance sheet as assets and liabilities from price risk management activities. The best indication of fair value is quoted market prices. However, when quoted market prices are not available, we estimate the fair value of those derivatives. We use commodity pricing data either obtained or derived from an independent pricing source to develop price curves. The curves are then used to estimate the value of settlements in future periods based on the contractual settlement quantities and dates. We discount these estimated settlement values using a LIBOR curve.

     As of December 31, 2006 and 2005, the value of cash flow hedges included in accumulated other comprehensive income was a net unrealized gain of $84 million and loss of $449 million, net of income taxes. We estimate that unrealized gains of $124 million, net of income taxes, will be reclassified from accumulated other comprehensive income during 2007. Reclassifications occur upon physical delivery of the hedge commodity and the corresponding expiration of the hedge. The maximum term of our cash flow hedges is 6 years; however, most of our cash flow hedges with third parties expire within the next 12 months.

     For the years ended December 31, 2006, 2005 and 2004, we recognized a net gain of $10 million and losses of $6 million and $1 million, net of income taxes, related to the ineffective portion of all cash flow hedges. As of December 31, 2006 and 2005, we had accumulated other comprehensive income, net of income tax, of approximately $35 million and $11 million related to derivatives that we either terminated or where we removed the hedging designation on approximately 75 TBtu of natural gas in 2006 and 154 MMbls and 383 MMbls of crude oil in 2006 and 2005. For the years ended December 31, 2006 and 2005, we reclassified $1 million and $7 million, net of income taxes, from accumulated other comprehensive income and recorded a reduction to operating revenues as a result of discontinuing hedge accounting. We anticipate that accumulated other comprehensive income as of December 31, 2006 related to these positions will be reclassified into income in 2007. Additionally, all of our oil swaps and approximately 51 TBtu of our natural gas basis swaps are not designed as hedges. Accordingly, changes in the fair values of these swaps are not deferred, but are recognized as other operating revenue in our income statement each period.

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     We enter into derivative contracts with El Paso Marketing pursuant to a master hedging contract. We and El Paso Marketing are not required to post collateral or other security for credit risk as we are under common control. We also enter into derivatives directly with third parties. As of December 31, 2006, we recorded assets from price risk management activities of $144 million and liabilities from price risk management activities of $109 million. As of December 31, 2005, we recorded liabilities from price risk management activities of $747 million.

     We are subject to credit risk related to our net assets from price risk management activities. 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. 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) and (ii) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Our assets from price risk management activities at December 31, 2006 represent derivative instruments from three counterparties, each of which are financial institutions with an “investment grade” (minimum Standard & Poor’s rating of BBB- or Moody’s rating of Baa3) credit rating. Subject to the terms of our $500 million revolving credit facility, collateral or other securities are not exchanged in relation to price risk management activities with third parties.

5. Property, Plant and Equipment

     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 2007 and 2008. Presented below is an analysis of the capitalized costs of natural gas and oil properties by year of expenditure that are not being amortized as of December 31, 2006, pending determination of proved reserves (in millions):

	Cumulative		Costs Excluded						Cumulative
	Balance(1)		for Years Ended(1)						Balance
	December 31,		December 31						December 31,
	2006		2006		2005		2004		2003
United States
Acquisition	$	280	$	39	$	182	$	24	$	35
Exploration		52		36		3		1		12
Development		1		—		—		—		1
Total United States		333		75		185		25		48
Brazil & Egypt
Acquisition		5		1		—		1		3
Exploration		72		51		10		10		1
Development		—		—		—		—		—
Total Brazil & Egypt		77		52		10		11		4
Worldwide	$	410	$	127	$	195	$	36	$	52

⁽¹⁾ Includes capitalized interest of $24 million, $19 million, and $1 million for the years ended December 31, 2006, 2005, and 2004.

     Depreciation, Depletion and Amortization Rates.Our total amortization expense per Mcfe for the United States was $2.53, $2.37 and $1.96 in 2006, 2005, and 2004 and $2.28, $2.33 and $2.02 for Brazil in 2006, 2005, and 2004. Included in our depreciation, depletion and amortization expense is accretion expense of $0.07/Mcfe, $0.10/Mcfe and $0.08/Mcfe for 2006, 2005 and 2004 for the United States and $0.03/Mcfe in 2006 and $0.01/Mcfe for 2005 and 2004 for Brazil attributable to SFAS No. 143, which represents the change in the value of our asset retirement obligations as a result of the passage of time. During 2006, 2005 and 2004, our weighted average unit of production depletion rate on our natural gas and oil properties per Mcfe was $2.39, $2.21 and $1.84.

     Asset retirement obligations.We have legal obligations associated with our natural gas and oil wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted or we no longer plan to use them, and when we abandon them. We accrue a liability on those legal obligations when we can estimate the timing and amount of their settlement and include obligations where we will be legally required to replace, remove or retire the associated assets.

     In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including credit-adjusted discount rates ranging from six to eight percent and a projected inflation rate of 2.5 percent. Changes in estimate represent changes to the expected amount and timing of payments to settle our asset retirement obligation. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug our natural gas and oil wells and the costs to do so. In 2006, we also revised our estimates due primarily to the impacts of hurricanes Katrina and Rita. The net asset retirement liability 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:

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	2006			2005
	(In millions)
Net asset retirement liability at January 1	$	194		$	258
Liabilities settled(1)		(18	)		(87	)
Accretion expense		18			26
Liabilities incurred		5			9
Changes in estimate		(10	)		(12	)
Net asset retirement liability at December 31	$	189		$	194

⁽¹⁾ Decrease is due primarily to the sale of certain domestic natural gas and oil properties in 2005. For a further discussion of these divestitures see Note 2.

     Our changes in estimate represent changes to the expected amount and timing of payments to settle our asset retirement obligations. These changes primarily result from obtaining new information about the timing of our obligations to plug our natural gas and oil wells and the costs to do so.

6. Debt and Available Credit Facilities

     Our long-term debt and available credit facilities consisted of the following at December 31, 2006:

				Amount
Description	Interest Rate		Term(1)	Outstanding
				(Millions)
$1.2 billion senior notes		7.75%	June 1, 2013	$	1,200
$500 million revolving credit facility	LIBOR plus 1.25% -1.875%		August 30, 2010		145
Total				$	1,345

⁽¹⁾ We have the ability to prepay amounts outstanding as of December 31, 2006 under our $500 million revolving credit facility in 2007 or thereafter and our $1.2 billion senior notes after June 1, 2008. However, we do not currently have the intent to prepay or call this debt.

     $1.2 billion senior notes.Our 7.75 percent senior notes are fully and unconditionally guaranteed by our wholly-owned subsidiary guarantors on a joint and several basis. There are no independent assets or operations at the holding company level. We and our Restricted Subsidiaries (as defined in the indenture) are subject to a number of restrictions and covenants including (i) limitations on the incurrence of additional debt if there is a default or our Consolidated Coverage Ratio (as defined in the indenture) is below 2.0 to 1.0, (ii) limitations on dividends that can be made based on Free Cash Flow and Net Cash Proceeds (each as defined in the indenture; however, there are no restrictions on the amount of dividends that our Restricted Subsidiaries can make to us), (iii) limitations on asset sales, (iv) limitations on affiliate transactions, (v) limitations on liens securing debt and (vi) limitations on providing cash to El Paso under its cash management program. In addition, we have a $25 million cross-acceleration provision.

     $500 million credit facility.In August 2005, we entered into this facility to partially fund our acquisition of Medicine Bow. This facility can be used to fund borrowings or for the issuance of letters of credit and is collateralized by our natural gas and oil properties located in Vermejo Ranch in New Mexico and Colorado, Holly Field in Louisiana, Minden Field in Texas and the majority of our Coal Bed Methane properties in Alabama. Borrowing cost under this facility can range from Libor plus 1.25% to Libor plus 1.875% depending on usage. The availability of borrowings is subject to various conditions, which include compliance with the financial covenants and ratios required by the facility, absence of default under the facility and the continued accuracy of the representations and warranties contained in the facility. The financial coverage ratios under the facility require that our EBITDA (as defined in the facility) to interest expense ratio must not be less than 2.0 to 1.0, our debt to EBITDA ratio not to exceed 4.0 to 1.0 and our Collateral Coverage Ratio (as defined in the facility) must not be less than 1.5 to 1.0. In addition, we have a $25 million cross-acceleration provision. For the year ended December 31, 2006 we were in compliance with our debt related covenants.

     In May 2006, we received a capital contribution from El Paso of $500 million to repay all amounts outstanding under our revolving credit facility and as of December 31, 2006 we had borrowed $145 million. On January 4, 2007, we borrowed an additional $255 million to fund our Zapata County acquisition, which increased our borrowing rate to Libor plus 1.75%. The terms of this facility were amended in 2006 to increase the amount we can advance to El Paso from $125 million to $200 million under its cash management program. We also have the ability to use existing collateral supporting this facility to collateralize hedging agreements entered into to mitigate related commodity price risk exposure.

     $400 million credit facility.In May 2006, El Paso’s $400 million credit facility, under which we were an eligible borrower, matured unutilized.

     7. Commitments and Contingencies

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Legal Proceedings and Other Contingencies

     Gas Measurement Cases.A number of El Paso entities, including us, 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, which has 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 May 2005, a representative appointed by the court issued a recommendation to dismiss most of the actions. In October 2006, the U.S. District Judge issued an order dismissing all mismeasurement claims against all defendants. An appeal has been filed.

     Similar allegations were filed in a second set of actions initiated in 1999 inWill Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The plaintiff seeks 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. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

     Reserve Revisions.In March 2004, El Paso received a subpoena from the SEC requesting documents relating to its December 31, 2003 natural gas and oil reserve revisions. We continue to assist El Paso and its Audit Committee in their efforts to cooperate with the SEC in its investigation related to such reserve revisions.

     In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal and other contingent matters, we evaluate the merits of the case, 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, 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. However, it is possible 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, 2006, we had approximately $23 million accrued for all outstanding legal and other contingent matters.

Environmental Matters

     We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2006, we had accrued approximately $7 million for related environmental remediation costs associated onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our exposure could be as high as $13 million. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded 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.

     Below is a reconciliation of our accrued liability from January 1, 2006 to December 31, 2006 (in millions):

Balance at January 1, 2006	$	5
Additions/adjustments for remediation activities		3
Payments for remediation activities		(1	)
Balance at December 31, 2006	$	7

     For 2007, we estimate that our total remediation expenditures will be approximately $1 million, which will be expended under government directed clean-up plans.

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     CERCLA Matters.We have received notice that we could be designated, or have been asked for information to determine whether we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at this site through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2006, we have estimated our share of the remediation costs at this site to be approximately $1 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

     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.

Lease Obligations

     We lease office space and various equipment under operating lease agreements. As of December 31, 2006, the annual minimum lease payments under non-cancelable future operating lease commitments were less than $1 million for each of the years 2007 and 2011. These amounts exclude minimum annual commitments paid by El Paso, which are allocated to us through an overhead allocation. Rental expense for operating leases, including the overhead allocation, was approximately $1 million for the year ended December 31, 2006 and approximately $1 million and $7 million for the years ended December 31, 2005 and 2004.

Other Commercial Commitments

     At December 31, 2006, we have various commercial commitments totaling $134 million, primarily related to commitments associated with our drilling activities. Our annual obligations under these arrangements are $73 million in 2007, $15 million in 2008, $11 million in 2009 and 2010, $10 million in 2011 and $14 million thereafter.

Guarantees and Indemnification

     We periodically provide indemnification arrangements related to assets or businesses we have sold. These indemnifications arrangements include, but are not limited to, indemnification for income taxes, the resolution of existing disputes, environmental matters, and necessary expenditures to ensure the safety and integrity of assets sold. As of December 31, 2006, we had no recorded obligations related to our guarantees and indemnification arrangements. These arrangements had a total stated value of approximately $64 million.

8. Retirement Benefits

Pension and Retirement Benefits

     El Paso maintains a primary pension plan that is a defined benefit plan that covers substantially all of our employees and provides benefits under a cash balance formula. El Paso also maintains a defined contribution plan covering all of our employees. El Paso matches 75 percent of participant basic contributions up to 6 percent of eligible compensation and can also make additional discretionary matching contributions. El Paso is responsible for benefits accrued under these plans and allocates our related costs to us.

     Other Postretirement Benefits

     El Paso provides limited postretirement life insurance benefits for current and retired employees. El Paso is responsible for benefits accrued under its plan and allocates the related costs to its affiliates. We do not provide subsidized postretirement medical benefits.

9. Investments in and Earnings from Unconsolidated Affiliates and Related Party Transactions

Investments in Unconsolidated Affiliates

     Four Star Oil & Gas Company.We hold a 43.1 percent ownership investment in an unconsolidated affiliate, Four Star, which we acquired in connection with our Medicine Bow acquisition in August 2005. We account for our investment using the equity method of accounting and report our proportionate share of Four Star’s earnings as earnings from

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unconsolidated affiliates on our income statement net of amortization of the excess purchase price. We received dividends of $44 million and $34 million from Four Star in 2006 and 2005. Our investment in Four Star was greater than our equity in the net assets by $619 million and $670 million at December 31, 2006 and 2005. We amortize our investment in excess of our underlying equity in the net assets of Four Star, excluding amounts related to the unevaluated properties, using a unit-of-production method over the life of our estimate of Four Star’s natural gas and oil reserves. We recorded $54 million in 2006 and $20 million in 2005 to amortize our investment in excess of the underlying equity in the net assets of the investment. Below is summarized financial information reflecting our proportionate share of the operating results for the year ended December 31, 2006 and since the date of acquisition for the year ended December 31, 2005 and the financial position of Four Star at December 31, 2006 and 2005.

	2006		2005
	(In millions)
Operating results data:
Operating revenues	$	156	$	81
Operating expenses		61		20
Net income		64		39
Financial position data:
Current assets		64		64
Non-current assets		102		101
Current liabilities		30		51
Non-current liabilities		32		29
Equity in net assets		104		85

     In January 2007, Four Star acquired 79 wells in the San Juan basin with daily production of approximately 5 MMcfe/d and proved reserves of 16 Bcfe, net to our interest, on the acquisition date.

     Black Warrior Transmission Corp.We hold a 50 percent ownership interest in Black Warrior Transmission Corp. and account for this investment using the equity method of accounting. Our investment was $6 million as of December 31, 2006 and 2005. We recognized equity earnings of less than $1 million for each of the years ended December 31, 2006, 2005 and 2004 from this unconsolidated affiliate.

Related Party Transactions

     Cash Management Program.Subject to limitations in our indenture and our credit facility, we participate in El Paso’s cash management program which matches short-term cash surpluses and needs of its participating affiliates, thus minimizing total borrowings from outside sources by El Paso. At December 31, 2006 and 2005, we had a note receivable from El Paso of $59 million and a note payable to El Paso of $255 million, which are classified on our balance sheet as current note receivable to affiliate and current note payable to affiliate, primarily based on the anticipated repayment under the cash management program. The interest rate under the cash management program was 5.3% at December 31, 2006 and 5.0% at December 31, 2005.

     Capital Contributions.During 2006, 2005 and 2004 El Paso contributed $0.6 billion, $1.6 billion and $0.2 billion to us, primarily in conjunction with our reorganization. We used $0.5 billion of the capital contribution made in 2006 to repay all amounts outstanding on our revolving credit facility. Of the total contributions, approximately $0.1 billion, $1.3 billion and less than $0.1 billion were non-cash in 2006, 2005 and 2004.

     Dividends.During 2005 and 2004, we made dividends to our parent of approximately $0.2 billion and $0.1 billion. These amounts primarily related to settlements under derivative contracts between us and El Paso affiliates.

     Other Affiliated Transactions.During the ordinary course of conducting our business, we enter into transactions with affiliates primarily related to the sale, transport and hedging our natural gas, oil and NGL production. Historically, we also engaged in activities with other midstream affiliates of El Paso that provided natural gas and oil gathering, processing and treating services for us. The following table shows revenues and charges to/from our affiliates for the years ended December 31:

	2006		2005		2004
	(In millions)
Operating revenues	$	871	$	732	$	952
Operating expenses from affiliates		97		118		125
Reimbursements of operating expenses charged to affiliates		13		11		6

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• El Paso.El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. This allocation is based on the estimated level of resources devoted to our operations and the relative size of our EBIT, gross property and payroll. These expenses are primarily related to management, legal, financial, tax, consultative, administrative and other services, including employee benefits, annual incentive bonuses, rent, insurance, and information technology. El Paso currently bills us directly for compensation expense related to certain stock-based compensation awards granted directly to our employees as well as allocates to us our proportionate share of El Paso’s corporate compensation expense.

     At December 31, 2006 and 2005, we had accounts payable to our affiliates of approximately $19 million and $32 million. We also have a service agreement with El Paso that provides for a reimbursement of 2.5 cents per MMBtu in 2006 and 2005 for our expected administrative costs associated with hedging transactions we entered into in December 2004.

     During 2004, we had a temporary interruption of some our production in the Gulf of Mexico as a result of Hurricane Ivan. We have business interruption insurance through El Paso and received $11.5 million as reimbursement for 2004 lost revenues, which was recorded in operating revenues during 2006.

• El Paso Marketing.We sell our natural gas primarily to El Paso Marketing at spot market prices. At December 31, 2006 and 2005, substantially all of our affiliated accounts receivable of $291 million and $355 million related to sales of natural gas to El Paso Marketing. We are also a party to a master hedging contract with El Paso Marketing, L.P. whereby we hedge a portion of our natural gas production with El Paso Marketing. Realized gains and losses on these hedges are included in our affiliated operating revenues.

• El Paso Pipelines.We also contract for services with El Paso’s regulated interstate pipelines that provide transportation and related services for our natural gas production. At December 31, 2006 and December 31, 2005, we had contractual deposits of $6 million with El Paso’s regulated interstate pipelines.

     Taxes.We are party to a tax accrual policy with El Paso whereby El Paso files U.S. and certain state tax returns on our behalf. In certain states, we file and pay directly to the state taxing authorities. We have $98 million of federal income taxes payable at December 31, 2006 and state income taxes payable of $8 million at December 31, 2006 and 2005, recorded as current liabilities on our balance sheet. We have federal income tax receivables of $40 million in other current assets at December 31, 2005, on our balance sheet. The majority of these balances will become payable to or receivable from El Paso under the tax accrual policy as further described in Note 1.

10. Consolidating Financial Statements

     As discussed in Note 6, our senior notes of $1.2 billion are fully and unconditionally guaranteed by certain of our direct and indirect, wholly-owned domestic subsidiaries (the “Guarantor Subsidiaries”) on a joint and several basis. Our foreign subsidiaries and certain of our remaining domestic subsidiaries (the “Non-Guarantor Subsidiaries”) do not provide guarantees. Based on this distinction, the following presents condensed consolidating financial information as of and for the years ended December 31, 2006 and 2005 and condensed consolidating statements of operations and cash flows for the years ended December 31, 2006, 2005, and 2004 on an issuer, guarantor subsidiaries, non-guarantor subsidiaries, eliminating entries and consolidated basis. Elimination entries presented are necessary to combine the entities.

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EL PASO EXPLORATION & PRODUCTION COMPANY
CONSOLIDATING STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2006
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Operating revenues
Natural gas and oil sales
Third parties	$	—		$	695		$	34		$	—		$	729
Affiliates		—			873			(2	)		—			871
Other		—			19			(1	)		—			18
		—			1,587			31			—			1,618
Operating expenses
Cost of sales		—			87			—			—			87
Operation and maintenance		—			400			9			—			409
Depreciation, depletion and amortization		—			653			20			—			673
Taxes, other than income taxes		—			80			6			—			86
		—			1,220			35			—			1,255
Operating income (loss)		—			367			(4	)		—			363
Earnings from unconsolidated affiliates		—			10			—			—			10
Other income		—			4			1			—			5
Interest expense
Third party, net of interest capitalized		(116	)		25			5			—			(86	)
Affiliated		32			(35	)		—			—			(3	)
Income (loss) before income taxes and earnings from consolidated subsidiaries		(84	)		371			2			—			289
Income taxes		30			(125	)		2			—			(93	)
Income (loss) before earnings from consolidated subsidiaries		(54	)		246			4			—			196
Earnings from consolidated subsidiaries		250			4			—			(254	)		—
Net income	$	196		$	250		$	4		$	(254	)	$	196

EL PASO EXPLORATION &PRODUCTION COMPANY
CONSOLIDATING STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2005
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Operating revenues
Natural gas and oil sales
Third parties	$	—		$	708		$	69		$	—		$	777
Affiliates		—			739			(7	)		—			732
Other		—			43			(9	)		—			34
		—			1,490			53			—			1,543
Operating expenses
Cost of sales		—			62			—			—			62
Operation and maintenance		—			368			19			—			387
Depreciation, depletion and amortization		—			598			45			—			643
Taxes, other than income taxes		—			73			1			—			74
		—			1,101			65			—			1,166
Operating income (loss)		—			389			(12	)		—			377
Earnings from unconsolidated affiliates		—			19			—			—			19
Other income		—			5			1			—			6
Interest expense						��
Third party, net of interest capitalized		(107	)		19			5			—			(83	)
Affiliated		—			(61	)		—			—			(61	)
Income (loss) before income taxes and earnings from consolidated subsidiaries		(107	)		371			(6	)		—			258
Income taxes		37			(127	)		(6	)		—			(96	)
Income (loss) before earnings from consolidated subsidiaries		(70	)		244			(12	)		—			162
Earnings (loss) from consolidated subsidiaries		232			(12	)		—			(220	)		—
Net income (loss)	$	162		$	232		$	(12	)	$	(220	)	$	162

47

EL PASO EXPLORATION & PRODUCTION COMPANY
CONSOLIDATING STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2004
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Operating revenues
Natural gas and oil sales
Third parties	$	—		$	551		$	28		$	—		$	579
Affiliates		—			953			(1	)		—			952
Other		—			24			(1	)		—			23
		—			1,528			26			—			1,554
Operating expenses
Cost of sales		—			60			—			—			60
Operation and maintenance		—			365			12			—			377
Depreciation, depletion and amortization		—			567			18			—			585
Taxes, other than income taxes		—			33			1			—			34
		—			1,025			31			—			1,056
Operating income (loss)		—			503			(5	)		—			498
Earnings from unconsolidated affiliates		—			—			4			—			4
Other income		—			1			2			—			3
Interest expense
Third party, net of interest capitalized		(95	)		19			2			—			(74	)
Affiliated		—			(28	)		—			—			(28	)
Income (loss) before income taxes and earnings from consolidated subsidiaries		(95	)		495			3			—			403
Income taxes		34			(173	)		(3	)		—			(142	)
Income (loss) before earnings from consolidated subsidiaries		(61	)		322			—			—			261
Earnings (loss) from consolidated subsidiaries		322			—			—			(322	)		—
Net income (loss)	$	261		$	322		$	—		$	(322	)	$	261

48

EL PASO EXPLORATION & PRODUCTION COMPANY
CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2006
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—		$	95		$	37		$	—		$	132
Accounts receivable
Customer, net		—			49			5			—			54
Affiliates		—			291			—			—			291
Other		29			117			6			(30	)		122
Note receivable from affiliate		56			14			—			(11	)		59
Assets held for price risk management activities		—			144			—			—			144
Deferred income taxes		—			73			—			—			73
Other		—			39			9			—			48
Total current assets		85			822			57			(41	)		923
Property, plant and equipment, at cost
Natural gas and oil properties
Proved properties-full cost method		—			15,587			455			—			16,042
Unevaluated costs excluded from amortization		—			333			77			—			410
Other		—			118			1			—			119
		—			16,038			533			—			16,571
Less accumulated depreciation, depletion and amortization		—			(11,181	)		(202	)		—			(11,383	)
Total property, plant and equipment, net		—			4,857			331			—			5,188
Other assets
Investments in consolidated and unconsolidated affiliates		4,972			1,021			42			(5,306	)		729
Note receivable from affiliate		565			142			—			(707	)		—
Deferred income taxes		19			4			39			(19	)		43
Other		25			5			12			—			42
		5,581			1,172			93			(6,032	)		814
Total assets	$	5,666		$	6,851		$	481		$	(6,073	)	$	6,925
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	—		$	81		$	1		$	—		$	82
Affiliates		—			19			11			(11	)		19
Other		—			244			23			—			267
Liabilities from price risk management activities		—			35			6			—			41
Asset retirement obligation		—			56			—			—			56
Income tax payable		—			136			—			(30	)		106
Other		9			32			1			—			42
Total current liabilities		9			603			42			(41	)		613
Long-term debt		1,345			—			—			—			1,345
Other
Liabilities from price risk management activities		—			68			—			—			68
Note payable to affiliate		—			563			144			(707	)		—
Deferred income taxes		—			427			—			(19	)		408
Asset retirement obligation		—			130			3			—			133
Other		—			46			—			—			46
		—			1,234			147			(726	)		655
Commitments and contingencies
Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized and outstanding		—			—			—			—			—
Preferred stock		—			—			12			(12	)		—
Additional paid-in capital		4,310			4,734			311			(5,045	)		4,310
Retained earnings (accumulated deficit)		(82	)		196			(27	)		(169	)		(82	)
Accumulated other comprehensive gain (loss)		84			84			(4	)		(80	)		84
Total stockholder’s equity		4,312			5,014			292			(5,306	)		4,312
Total liabilities and stockholder’s equity	$	5,666		$	6,851		$	481		$	(6,073	)	$	6,925

49

EL PASO EXPLORATION & PRODUCTION COMPANY
CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2005
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	10		$	37		$	13		$	—		$	60
Accounts receivable
Customer, net		—			53			9			—			62
Affiliates		—			355			—			—			355
Other		—			80			3			—			83
Note receivable from affiliate		—			—			75			—			75
Deferred income taxes		—			221			—			—			221
Other		38			31			7			—			76
Total current assets		48			777			107			—			932
Property, plant and equipment, at cost Natural gas and oil properties
Proved properties-full cost method		—			14,764			371			—			15,135
Unevaluated costs excluded from amortization		—			384			107			—			491
Other		—			141			—			—			141
		—			15,289			478			—			15,767
Less accumulated depreciation, depletion and amortization		—			(10,810	)		(183	)		—			(10,993	)
Total property, plant and equipment, net		—			4,479			295			—			4,774
Other assets
Investments in consolidated and unconsolidated affiliates		4,007			1,046			—			(4,292	)		761
Note receivable from affiliate		586			—			—			(586	)		—
Deferred income taxes		15			22			35			(15	)		57
Other		30			—			11			—			41
		4,638			1,068			46			(4,893	)		859
Total assets	$	4,686		$	6,324		$	448		$	(4,893	)	$	6,565
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	—		$	97		$	—		$	—		$	97
Affiliates		—			32			—			—			32
Other		—			167			13			—			180
Notes payable to affiliate		—			126			129			—			255
Liabilities from price risk management activities		—			621			10			—			631
Asset retirement obligation		—			31			—			—			31
Income tax payable		—			8			—			—			8
Other		10			23			2			—			35
Total current liabilities		10			1,105			154			—			1,269
Long-term debt		1,700			—			—			—			1,700
Other
Liabilities from price risk management activities		—			111			5			—			116
Note payable to affiliate		—			586			—			(586	)		—
Deferred income taxes		—			303			—			(15	)		288
Asset retirement obligation		—			159			4			—			163
Other		—			53			—			—			53
		—			1,212			9			(601	)		620
Commitments and contingencies
Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized and outstanding		—			—			—			—			—
Preferred stock		—			—			12			(12	)		—
Additional paid-in capital		3,703			4,510			310			(4,820	)		3,703
Accumulated deficit		(278	)		(54	)		(32	)		86			(278	)
Accumulated other comprehensive loss		(449	)		(449	)		(5	)		454			(449	)
Total stockholder’s equity		2,976			4,007			285			(4,292	)		2,976
Total liabilities and stockholder’s equity	$	4,686		$	6,324		$	448		$	(4,893	)	$	6,565

50

EL PASO EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2006
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income	$	196		$	250		$	4		$	(254	)	$	196
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		—			653			20			—			673
Deferred income tax expense (benefit)		—			(5	)		(3	)		—			(8	)
Earnings from consolidated affiliates, adjusted for cash distributions		(200	)		(4	)		—			204			—
Earnings from unconsolidated affiliates, adjusted for cash distributions		—			34			—			—			34
Other non-cash items		4			—			—			—			4
Asset and liability changes
Accounts receivable		—			36			1			—			37
Accounts payable		—			(22	)		(6	)		—			(28	)
Price risk management activities		—			59			(9	)		—			50
Affiliate income taxes		8			129			—			—			137
Other asset changes		2			(17	)		(3	)		—			(18	)
Other liability changes		(6	)		(12	)		(1	)		—			(19	)
Net cash provided by (used in) operating activities		4			1,101			3			(50	)		1,058
Cash flows from investing activities
Capital expenditures		—			(1,040	)		(74	)		—			(1,114	)
Net proceeds from the sale of assets		—			84			38			—			122
Investment in consolidated subsidiaries		(125	)		(1	)		(42	)		168			—
Change in note receivable from affiliate		(34	)		(56	)		74			32			16
Change in restricted cash		—			—			(1	)		—			(1	)
Net cash provided by (used in) investing activities		(159	)		(1,013	)		(5	)		200			(977	)
Cash flows from financing activities
Net proceeds from the issuance of long-term debt		(530	)		—			—			—			(530	)
Net proceeds from borrowings under revolving credit facility		175			—			—			—			175
Dividends to parent		—			(50	)		—			50			—
Contributions from parent		500			167			1			(168	)		500
Change in note payable with affiliate		—			(147	)		25			(32	)		(154	)
Net cash provided by (used in) financing activities		145			(30	)		26			(150	)		(9	)
Change in cash and cash equivalents		(10	)		58			24			—			72
Cash and cash equivalents
Beginning of period		10			37			13			—			60
End of period	$	—		$	95		$	37		$	—		$	132

51

EL PASO EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2005
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	162		$	232		$	(12	)	$	(220	)	$	162
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		—			598			45			—			643
Deferred income tax expense (benefit)		(13	)		107			(6	)		—			88
Earnings from consolidated subsidiaries, adjusted for cash distributions		(232	)		12			—			220			—
Earnings from unconsolidated affiliates, adjusted for cash distributions		—			15			—			—			15
Asset and liability changes
Accounts and notes receivable		—			(216	)		6			—			(210	)
Accounts payable		—			31			1			—			32
Price risk management activities		—			(27	)		10			—			(17	)
Affiliate income taxes		(4	)		2			(8	)		—			(10	)
Other asset changes		3			12			(2	)		—			13
Other liability changes		3			(41	)		5			—			(33	)
Net cash provided by (used in) operating activities		(81	)		725			39			—			683
Cash flows from investing activities
Capital expenditures		—			(801	)		(26	)		—			(827	)
Net proceeds from the sale of assets		178			10			—			(178	)		10
Cash paid for acquisitions, net of cash acquired		(1,025	)		(178	)		—			178			(1,025	)
Proceeds from investment in consolidated subsidiaries		1,141			—			—			(1,141	)		—
Investment in consolidated subsidiaries		(147	)		(6	)		—			153			—
Change in note receivable from affiliate		(627	)		80			(52	)		547			(52	)
Change in restricted cash		—			—			3			—			3
Net cash used in investing activities		(480	)		(895	)		(75	)		(441	)		(1,891	)
Cash flows from financing activities
Net proceeds from borrowings under revolving credit facility		495			—			—			—			495
Dividends to parent		(183	)		(1,141	)		—			1,141			(183	)
Contributions from parent		262			147			6			(153	)		262
Change in note payable with affiliate		(3	)		1,073			24			(547	)		547
Net cash provided by financing activities		571			79			30			441			1,121
Change in cash and cash equivalents		10			(91	)		(6	)		—			(87	)
Cash and cash equivalents
Beginning of period		—			128			19			—			147
End of period	$	10		$	37		$	13		$	—		$	60

52

EL PASO EXPLORATION & PRODUCTION COMPANY
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2004
(In millions)

							Non-
				Guarantor			Guarantor
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income	$	261		$	322		$	—		$	(322	)	$	261
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		—			567			18			—			585
Deferred income tax expense (benefit)		(2	)		169			2			—			169
Earnings from consolidated subsidiaries, adjusted for cash distributions		(322	)		—			—			322			—
Earnings from unconsolidated affiliates, adjusted for cash distributions		—			—			(4	)		—			(4	)
Other non-cash items		—			8			—			—			8
Asset and liability changes
Accounts and notes receivable		—			(22	)		(2	)		1			(23	)
Accounts payable		(1	)		2			(6	)		(1	)		(6	)
Price risk management activities		—			2			—			—			2
Affiliate income taxes		(49	)		(125	)		8			—			(166	)
Other asset changes		1			(20	)		2			1			(16	)
Other liability changes		(1	)		(53	)		(7	)		(1	)		(62	)
Net cash provided by (used in) operating activities		(113	)		850			11			—			748
Cash flows from investing activities
Capital expenditures		—			(677	)		(42	)		—			(719	)
Net proceeds from the sale of assets and investments		—			(9	)		23			—			14
Cash paid for acquisitions, net of cash acquired		—			—			(49	)		—			(49	)
Proceeds from investment in consolidated subsidiaries		105			—			—			(105	)		—
Investment in consolidated subsidiaries		(137	)		(14	)		—			151			—
Change in note receivable from affiliate		81			174			(1	)		(39	)		215
Change in restricted cash		—			—			(11	)		—			(11	)
Net cash provided by (used in) investing activities		49			(526	)		(80	)		7			(550	)
Cash flows from financing activities
Net proceeds from the issuance of preferred stock		—			—			2			(2	)		—
Dividends to parent		(57	)		(105	)		—			105			(57	)
Contributions from parent		137			137			12			(149	)		137
Change in note payable with affiliate		(16	)		(270	)		67			39			(180	)
Net cash provided by (used in) financing activities		64			(238	)		81			(7	)		(100	)
Change in cash and cash equivalents		—			86			12			—			98
Cash and cash equivalents
Beginning of period		—			42			7			—			49
End of period	$	—		$	128		$	19		$	—		$	147

53

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter is summarized below:

	Quarters Ended
	March 31		June 30		September 30		December 31(1)		Total
	(In millions)
2006
Operating revenues	$	385	$	405	$	399	$	429	$	1,618
Operating income		104		98		74		87		363
Net income		57		44		40		55		196

	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In millions)
2005
Operating revenues	$	364	$	395	$	395	$	389	$	1,543
Operating income		94		106		101		76		377
Net income		45		49		46		22		162

⁽¹⁾ During the fourth quarter of 2006, we recognized additional operating revenue and operating income of $20 million and net income of $13 million for additional amortization of realized gains on hedges. This amount should have been recorded throughout 2005 and the first three quarters of 2006. As amounts were not material to the current or historical periods, the adjustment was recorded in the fourth quarter of 2006.

Supplemental Natural Gas and Oil Operations (Unaudited)

     We are engaged in the exploration for, and the acquisition, development and production of natural gas, oil and NGL, primarily in the United States, 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:

	United		Brazil
	States		& Egypt(1)		Worldwide
2006
Natural gas and oil properties:
Costs subject to amortization	$	15,582	$	460	$	16,042
Costs not subject to amortization		333		77		410
		15,915		537		16,452
Less accumulated depreciation, depletion and amortization		11,124		202		11,326
Net capitalized costs	$	4,791	$	335	$	5,126
2005
Natural gas and oil properties:
Costs subject to amortization	$	14,764	$	371	$	15,135
Costs not subject to amortization		384		107		491
		15,148		478		15,626
Less accumulated depreciation, depletion and amortization		10,731		183		10,914
Net capitalized costs	$	4,417	$	295	$	4,712

⁽¹⁾ Capitalized costs for Egypt were $4 million as of December 31, 2006.

     Total Costs Incurred. Costs incurred in natural gas and oil producing activities were as follows for each of the years ended December 31:

54

	United		Brazil
	States		& Egypt		Worldwide
2006
Property acquisition costs
Proved properties	$	2	$	2	$	4
Unproved properties		34		1		35
Exploration costs		323		53		376
Development costs		738		40		778
Costs expended in 2006		1,097		96		1,193
Asset retirement obligation costs		3		—		3
Total costs incurred(1)	$	1,100	$	96	$	1,196
2005
Property acquisition costs
Proved properties	$	643	$	8	$	651
Unproved properties		143		1		144
Exploration costs		143		15		158
Development costs		503		6		509
Costs expended in 2005		1,432		30		1,462
Asset retirement obligation costs		1		—		1
Total costs incurred(1)	$	1,433	$	30	$	1,463
Unconsolidated investment in Four Star(2)	$	769	$	—	$	769
2004
Property acquisition costs
Proved properties	$	33	$	69	$	102
Unproved properties		32		3		35
Exploration costs		185		25		210
Development costs		395		1		396
Costs expended in 2004		645		98		743
Asset retirement obligation costs		30		3		33
Total costs incurred(1)	$	675	$	101	$	776

(1)	The table above includes capitalized internal costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves of $50 million, $47 million and $44 million and capitalized interest of $30 million, $30 million and $22 million for the years ended December 31, 2006, 2005 and 2004.
(2)	In 2005 amount includes $179 million of deferred income tax adjustments related to the acquisitions of full-cost pool properties and $217 million related to the acquisition of our unconsolidated investment in Four Star.

     In our January 1, 2007 reserve report, the amounts estimated to be spent in 2007, 2008 and 2009 to develop our worldwide proved undeveloped reserves are $424 million, $473 million and $243 million.

55

     Natural Gas and Oil Reserves.Net quantities of proved developed and undeveloped reserves of natural gas, oil and condensate and NGL, and changes in these reserves at December 31, 2006, are presented below and 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 consolidated reserves 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.

     Ryder Scott, an independent reservoir engineering firm that reports to the Audit Committee of El Paso’s Board of Directors, prepared a reserve estimate of our natural gas and oil reserves for 84 percent of our properties. Additionally, Ryder Scott prepared an estimate of 80 percent of the proved reserves of Four Star, our unconsolidated affiliate. Our estimates of Four Star’s proved natural gas and oil reserves are prepared by our internal reservoir engineers and do not reflect those prepared by the engineers of Four Star. Based on the amount of proved reserves determined by Ryder Scott, we believe these reported reserve amounts are reasonable. Ryder Scott's reports are included as exhibits to this Annual Report on Form 10-K.

										Oil and Condensate									NGL
	Natural Gas (in Bcf)									(in MBbls)									(in MBbls)			Equivalent
	United									United									United			Volumes
	States(1)			Brazil			Worldwide			States(1)			Brazil			Worldwide			States(1)(3			(in Bcfe)
Consolidated
January 1, 2004		2,061			—			2,061			32,371			20,543			52,914			15,985			2,474
Revisions of previous estimates(1)		(172	)		—			(172	)		(999	)		252			(747	)		724			(172	)
Extensions, discoveries and other		79			38			117			2,214			1,848			4,062			58			142
Purchases of reserves in place		15			38			53			—			1,848			1,848			—			64
Sales of reserves in place		(21	)		—			(21	)		(1,276	)		—			(1,276	)		(47	)		(29	)
Production		(238	)		(7	)		(245	)		(4,979	)		(320	)		(5,299	)		(3,519	)		(298	)
December 31, 2004		1,724			69			1,793			27,331			24,171			51,502			13,201			2,181
Revisions of previous estimates		(43	)		(2	)		(45	)		260			7,927			8,187			1,148			11
Extensions, discoveries and other		183			5			188			8,145			772			8,917			169			242
Purchases of reserves in place		192			—			192			13,338			—			13,338			772			276
Sales of reserves in place		(18	)		—			(18	)		(969	)		—			(969	)		(89	)		(24	)
Production		(207	)		(16	)		(223	)		(4,877	)		(620	)		(5,497	)		(2,639	)		(271	)
December 31, 2005		1,831			56			1,887			43,228			32,250			75,478			12,562			2,415
Revisions of previous estimates(1)		8			(1	)		7			(1,514	)		(365	)		(1,879	)		(1,834	)		(15	)
Extensions, discoveries and other		254			8			262			5,012			209			5,221			958			299
Purchases of reserves in place		1			—			1			90			—			90			32			2
Sales of reserves in place		(17	)		—			(17	)		(230	)		—			(230	)		(174	)		(20	)
Production		(213	)		(7	)		(220	)		(5,907	)		(247	)		(6,154	)		(1,532	)		(266	)
December 31, 2006		1,864			56			1,920			40,679			31,847			72,526			10,012			2,415
Proved developed reserves
December 31, 2004		1,287			54			1,341			19,641			2,613			22,254			11,943			1,546
December 31, 2005		1,404			27			1,431			28,581			1,144			29,725			11,010			1,675
December 31, 2006		1,469			23			1,492			29,616			824			30,440			8,665			1,727
Unconsolidated investment in Four Star
December 31, 2006
Net proved developed and undeveloped reserves		167			—			167			2,947			—			2,947			6,209			222
Proved developed reserves		139			—			139			2,874			—			2,874			5,095			187
December 31, 2005
Net proved developed and undeveloped reserves		193			—			193			3,349			—			3,349			6,668			253
Proved developed reserves		158			—			158			3,266			—			3,266			5,399			210

⁽¹⁾ Comprised of 54 Bcfe downward revisions due to commodity price changes and 39 Bcfe positive revisions due to performance.

     There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve

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data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including 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. 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. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2006.

     Results of Operations. Results of operations from producing activities by fiscal year were as follows at December 31 (in millions):

	United			Brazil
	States			& Egypt			Worldwide
2006
Net revenues
Sales to external customers	$	665		$	43		$	708
Affiliated sales		867			(11	)		856
Total		1,532			32			1,564
Cost of sales(1)		(58	)		—			(58	)
Production costs(2)		(318	)		(7	)		(325	)
Depreciation, depletion and amortization		(638	)		(19	)		(657	)
		518			6			524
Income tax expense		(186	)		(2	)		(188	)
Results of operations from producing activities	$	332		$	4		$	336
Equity earnings from unconsolidated investment in Four Star	$	10		$	—		$	10
2005
Net revenues
Sales to external customers	$	741		$	62		$	803
Affiliated sales		748			(9	)		739
Total		1,489			53			1,542
Cost of sales(1)		(62	)		—			(62	)
Production costs(2)		(256	)		(8	)		(264	)
Depreciation, depletion and amortization		(598	)		(45	)		(643	)
		573			—			573
Income tax expense		(204	)		—			(204	)
Results of operations from producing activities	$	369		$	—		$	369
Equity earnings from unconsolidated investment in Four Star	$	19		$	—		$	19
2004
Net revenues
Sales to external customers	$	953		$	26		$	979
Affiliated sales		574			—			574
Total		1,527			26			1,553
Cost of sales(1)		(60	)		—			(60	)
Production costs(2)		(215	)		—			(215	)
Depreciation, depletion and amortization		(568	)		(18	)		(586	)
		684			8			692
Income tax expense		(248	)		(3	)		(251	)
Results of operations from producing activities	$	436		$	5		$	441

(1)	Cost of sales is primarily transportation costs.
(2)	Production cost includes lease operating costs and production related taxes, including ad valorem and severance taxes.

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Standardized Measure of Discounted Future Net Cash Flows.The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves at December 31 follows (in millions):

	United						World-
	States			Brazil			wide
2006
Future cash inflows(1)	$	12,349		$	1,977		$	14,326
Future production costs		(3,623	)		(431	)		(4,054	)
Future development costs		(1,280	)		(506	)		(1,786	)
Future income tax expenses		(1,089	)		(239	)		(1,328	)
Future net cash flows		6,357			801			7,158
10% annual discount for estimated timing of cash flows		(2,302	)		(377	)		(2,679	)
Standardized measure of discounted future net cash flows	$	4,055		$	424		$	4,479
Standardized measure of discounted future net cash flows, including effects of hedging activities	$	4,225		$	424		$	4,649
2005
Future cash inflows(1)	$	18,175		$	1,992		$	20,167
Future production costs		(3,968	)		(453	)		(4,421	)
Future development costs		(1,335	)		(309	)		(1,644	)
Future income tax expenses		(3,160	)		(286	)		(3,446	)
Future net cash flows		9,712			944			10,656
10% annual discount for estimated timing of cash flows		(3,660	)		(381	)		(4,041	)
Standardized measure of discounted future net cash flows	$	6,052		$	563		$	6,615
Standardized measure of discounted future net cash flows, including effects of hedging activities	$	5,573		$	560		$	6,133
2004
Future cash inflows(1)	$	11,895		$	1,077		$	12,972
Future production costs		(3,585	)		(135	)		(3,720	)
Future development costs		(1,234	)		(274	)		(1,508	)
Future income tax expenses		(1,184	)		(141	)		(1,325	)
Future net cash flows		5,892			527			6,419
10% annual discount for estimated timing of cash flows		(2,004	)		(219	)		(2,223	)
Standardized measure of discounted future net cash flows	$	3,888		$	308		$	4,196
Standardized measure of discounted future net cash flows, including effects of hedging activities	$	3,547		$	305		$	3,852
Unconsolidated investment in Four Star(2)
Standardized measure of discounted future net cash flows
2006	$	323		$	—		$	323
2005	$	617		$	—		$	617

(1)	United States excludes $219 million of future cash inflows in 2006 and $760 million and $524 million of future net cash outflows in 2005 and 2004 attributable to hedging activities. Brazil excludes $4 million and $5 million of future net cash outflows attributable to hedging activities in 2005 and 2004.
(2)	Four Star was acquired in 2005.

     For the calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using year-end prices of $5.64, $10.08, and $6.22 per MMBtu for natural gas and $61.05, $61.04, and $43.45 per barrel of oil at December 31, 2006, 2005, and 2004. After adjustments for transportation and other charges, net prices were $5.33 per Mcf for natural gas, $51.08 per barrel of oil and $34.36 per barrel of NGL at December 31, 2006. We may receive amounts different than the standardized measure of discounted cash flow for a number or reasons, including price changes and the effects of our hedging activities.

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     Changes in Standardized Measure of Discounted Future Net Cash Flows. The following are the principal sources of change in the standardized measure of discounted future net cash flows (in millions):

	Years Ended December 31,(1)
	2006			2005			2004
Sales and transfers of natural gas and oil produced net of production costs	$	(1,516	)	$	(1,477	)	$	(1,470	)
Net changes in prices and production costs		(2,891	)		2,884			29
Extensions, discoveries and improved recovery, less related costs		549			793			268
Changes in estimated future development costs		(55	)		2			4
Previously estimated development costs incurred during the period		192			247			156
Revision of previous quantity estimates		(38	)		47			(453	)
Accretion of discount		827			476			568
Net change in income taxes		1,123			(1,093	)		257
Purchases of reserves in place		4			956			114
Sale of reserves in place		(42	)		(83	)		(75	)
Change in production rates, timing and other		(289	)		(333	)		(94	)
Net change	$	(2,136	)	$	2,419		$	(696	)

⁽¹⁾ This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

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SCHEDULE II

EL PASO EXPLORATION & PRODUCTION COMPANY
VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2006, 2005 and 2004
(In millions)

			Charged
	Balance at		to Costs					Charged			Balance
	Beginning		and					to Other			at End
Description	of Period		Expenses		Deductions			Accounts			of Period
2006
Allowance for doubtful accounts	$	10	$	—	$	(2	)	$	—		$	8
Valuation allowance on deferred tax assets		—		19		—			—			19
Legal reserves and other contingencies		22		1		—			—			23
Environmental reserves		5		3		(1	)		—			7
2005
Allowance for doubtful accounts	$	12	$	—	$	(1	)	$	(1	)	$	10
Legal reserves and other contingencies		17		7		(2	)		—			22
Environmental reserves		5		—		—			—			5
2004
Allowance for doubtful accounts	$	14	$	1	$	(4	)	$	1		$	12
Legal reserves and other contingencies		20		—		(2	)		(1	)		17
Environmental reserves		5		—		—			—			5

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

     As previously reported in our Current Report on Form 8-K dated April 18, 2006 (as amended on May 9, 2006), the Audit Committee of the Board of Directors of El Paso appointed Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2006 and dismissed PricewaterhouseCoopers LLP. During the fiscal years ended December 31, 2006 and 2005, there were no “disagreements with our former accountant” or “reportable events” as defined in Item 304(a)(1)(iv) and Item 304(a)(1)(v) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

     As of December 31, 2006, we carried out an evaluation under the supervision and with the participation of our management, including our President and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures as defined by the Securities Exchange Act of 1934, as amended. This evaluation considered the various processes carried out under the direction of El Paso’s disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission (“SEC”) reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all error 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. Based on the results of this evaluation, our President and CFO concluded that our disclosure controls and procedures are effective at December 31, 2006.

Changes in Internal Control over Financial Reporting

     There has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting during the fourth quarter of 2006.

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ITEM 9B. OTHER INFORMATION

     None.

PART III

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

     The audit fees for the years ended December 31, 2006 and 2005 of $950,000 and $1.2 million were for professional services rendered by Ernst & Young LLP and PricewaterhouseCoopers LLP for the audits of our consolidated financial statements.

All Other Fees

     No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2006 and 2005.

Policy for Approval of Audit and Non-Audit Fees

     We are a wholly-owned direct subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see the El Paso proxy statement.

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	27
	Consolidated Statements of Income	30
	Consolidated Balance Sheets	31
	Consolidated Statements of Cash Flows	32
	Consolidated Statements of Stockholder’s Equity	33
	Consolidated Statements of Comprehensive Income	33
	Notes to Consolidated Financial Statements
2.	Financial statement schedules and supplementary information required to be submitted
	Schedule II — Valuation and Qualifying accounts	60
3.	Exhibits	64

     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.

Undertaking

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     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.

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SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El Paso Exploration & Production Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 28^th day of February 2007.

EL PASO EXPLORATION & PRODUCTION COMPANY
By:	/s/ BRENT J. SMOLIK
	Brent J. Smolik
	President

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

Signature	Title	Date
/s/ BRENT J. SMOLIK Brent J. Smolik	President and Director (Principal Executive Officer)	February 28, 2007
/s/ DANE E. WHITEHEAD Dane E. Whitehead	Senior Vice President, Chief Financial Officer and Director (Principal Financial Officer)	February 28, 2007

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EL PASO EXPLORATION & PRODUCTION COMPANY

EXHIBIT INDEX

     Each exhibit identified below is filed as a 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	Amended and Restated Certificate of Incorporation as filed with the Delaware Secretary of State on February 16, 2006 (Exhibit 3.A to our 2005 Form 10-K).
3.B	By-laws effective as of June 24, 2002 (Exhibit 3.2 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
4.A	Indenture dated as of May 23, 2003 by and between El Paso Production Holding Company, the Subsidiary Guarantors named therein and Wilmington Trust Company, as Trustee (Exhibit 4.1 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
4.A.1	First Supplemental Indenture dated January 31, 2004 among El Paso Production Holding Company, the Subsidiary Guarantors named therein and Wilmington Trust Company, as Trustee (Exhibit 4.A.1 to our 2003 Form 10-K).
4.A.2	Consent by the Holders (as defined therein) effective July 26, 2004 Relating to a Proposed Waiver under the Indenture, as Supplemented, Governing El Paso Production Holding Company’s $1,200,000,000 Aggregate Principal Amount of Issued and Outstanding 73/4% Senior Notes due 2013 (Exhibit 4.A.2 to our 2003 Form 10-K).
4.A.3	Second Supplemental Indenture dated July 26, 2004 among El Paso Production Holding Company, the Subsidiary Guarantors named therein and Wilmington Trust Company, as Trustee (Exhibit 4.A.3 to our 2003 Form 10-K).
4.A.4	Third Supplemental Indenture, dated as of August 31, 2005, among El Paso Production Holding Company, as Issuer, El Paso Production Company, El Paso Production GOM, Inc., El Paso Energy Raton Corporation, Medicine Bow Energy Corporation, Medicine Bow Operating Company and MBOW Four Star Corporation, as Subsidiary Guarantors, and Wilmington Trust Company, as Trustee (Exhibit 10.C to our Form 8-K filed on September 1, 2005).
4.A.5	Fourth Supplemental Indenture, dated as of December 31, 2005, among El Paso Exploration & Production Company, as Issuer, El Paso Production Company, Medicine Bow Energy Corporation, Medicine Bow Operating Company, MBOW Four Star Corporation, El Paso E&P Company, L.P., El Paso Production Oil & Gas Company, El Paso E&P Holdings, Inc., El Paso Production Resale Company, El Paso Energy Oil Transmission, L.L.C. and El Paso Production Oil & Gas Gathering, L.P., as Subsidiary Guarantors, and Wilmington Trust Company, as Trustee (Exhibit 4.A to our Form 8-K filed January 4, 2006).
4.A.6	Fifth Supplemental Indenture, dated as of June 30, 2006, among El Paso Exploration & Production Company, MBOW Four Star Corporation, El Paso Exploration & Production Management, Inc., El Paso E&P Holding, Inc., El Paso E&P Company, L.P., El Paso Production Resale Company, El Paso Energy Oil Transmission, L.L.C. and El Paso Production Oil & Gas Gathering, L.P., as Subsidiary Guarantors, and Wilmington Trust Company, as Trustee. (Exhibit 4.A to our 2006 Second Quarter Form 10-Q).
*4.A.7	Sixth Supplemental Indenture, dated as of October 1, 2006, among El Paso Exploration & Production Company, MBOW Four Star Corporation, El Paso Exploration & Production Management, Inc., El Paso E&P Holdings, Inc., El Paso E&P Company, L.P., El Paso Production Resale Company, El Paso Energy Oil Transmission, L.L.C., El Paso Production Oil & Gas Gathering, L.P., El Paso E&P International Holding Company, El Paso Preferred Holdings Company, and El Paso E&P Finance Company, L.L.C., as Subsidiary Guarantors, and Wilmington Trust Company, as Trustee.

64

Exhibit
Number	Description
*4.A.8	Seventh Supplemental Indenture, dated as of January 12, 2007, among El Paso Exploration & Production Company, MBOW Four Star Corporation, El Paso Exploration & Production Management, Inc., El Paso E&P Holdings, Inc., El Paso E&P Company, L.P., El Paso Production Resale Company, El Paso Energy Oil Transmission, L.L.C., El Paso Production Oil & Gas Gathering, L.P., El Paso E&P International Holding Company, El Paso Preferred Holdings Company, El Paso E&P Finance Company, L.L.C., El Paso South Texas E&P Company, L.L.C., and El Paso E&P Zapata, L.P., as Subsidiary Guarantors, and Wilmington Trust Company, as Trustee.
10.A	ISDA Master Agreement, dated as of January 1, 2001, between El Paso Merchant Energy, L.P. and El Paso Production Company (Exhibit 10.1 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
10.B	Services Agreement, dated as of May 23, 2003, between El Paso Energy Service Company and El Paso Production Holding Company (Exhibit 10.2 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
10.C	Federal and State Tax Reimbursement Agreement among El Paso Corporation and the Controlled Entities (named therein), effective as of May 22, 2003 (Exhibit 10.18 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
10.D	El Paso Corporation and Consolidated Subsidiaries Accounting Policy for the Accrual of U.S. Federal Income Taxes, effective as of January 1, 2002 (Exhibit 10.19 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
10.E	Intercompany State Income Tax Allocation and Payments Policy, effective for tax years beginning after January 29, 2001 (Exhibit 10.20 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
10.F	Stock Purchase Agreement dated July 18, 2005 among the Registrant, Medicine Bow Energy Corporation and the other parties identified therein (Exhibit 10.A to our Form 8-K filed on July 19, 2005)
10.G	Credit Agreement dated as of August 30, 2005, among El Paso Production Holding Company, El Paso Production Company, El Paso Energy Raton Corporation and El Paso Production GOM, Inc. and Fortis Capital Corp., The Royal Bank of Scotland plc and The Bank of Nova Scotia, and the Several Lenders from time to time Parties thereto (Exhibit 10.A to our Form 8-K filed on September 1, 2005).
10.H	Amended and Restated Credit Agreement, dated as of October 19, 2005, among El Paso Production Holding Company, El Paso Production Company, El Paso Energy Raton Corporation and El Paso Production GOM, Inc., as Borrowers, and Fortis Capital Corp., The Royal Bank of Scotland plc, The Bank of Nova Scotia, Societe Generale and WESTLB AG, New York Branch and the Several Lenders from time to time Parties thereto, including the Form of Guarantee Agreement made by the Guarantors in favor of Fortis Capital Corp., as agent for the Creditors (Exhibit 10.A to our Form 8-K filed on October 24, 2005); First Amendment dated as of March 27, 2006, among El Paso Exploration & Production Company, El Paso Production Company, El Paso E&P Company, L.P. and Fortis Capital Corp., as administrative agent for the Lenders party to that certain Amended and Restated Credit Agreement dated as of October 19, 2005. (Exhibit 10.A to our 2006 First Quarter Form 10-Q).
*10.I.1	Second Amendment dated as of December 1, 2006, among El Paso Exploration & Production Company, El Paso E&P Company, L.P. and Fortis Capital Corp., as administrative agent for the Lenders party to that certain Amended and Restated Credit Agreement dated as of October 19, 2005.
10.J	Waiver and Consent dated as of September 29, 2006, among El Paso Exploration & Production Company, El Paso E&P Company, L.P. and Fortis Capital Corp., as administrative agent for the Lenders party to that certain Amended and Restated Credit Agreement dated as of October 19, 2005. (Exhibit 10.A to our 2006 Third Quarter Form 10-Q).
10.K	Second Amendment dated as of December 1, 2006, among El Paso Exploration & Production Company, El Paso E&P Company, L.P. and Fortis Capital Corp., as administrative agent for the Lenders party to that certain Amended and Restated Credit Agreement dated as of October 19, 2005.
10.L	Credit Agreement, dated as of November 3, 2005, among El Paso Corporation and El Paso Production Oil & Gas USA, L.P., as Borrowers, Fortis Capital Corp., as Administrative Agent, Arranger and Bookrunner, and the several Lenders party from time to time thereto (Exhibit 10.A to our Form 8-K filed January 4, 2006).

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Exhibit
Number	Description
10.M	First Amendment, Consent and Waiver Agreement, dated as of December 20, 2005, among El Paso Corporation and El Paso Production Oil & Gas USA, L.P., as Borrowers, Fortis Capital Corp., as Administrative Agent for the Lenders, and the several Lenders party from time to time thereto (Exhibit 10.B to our Form 8-K filed January 4, 2006).
21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
*23.A	Consent of Ryder Scott
*31.A	Certification of Principal Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
*31.B	Certification of Chief Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
*32.A	Certification of Principal Executive Officer pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
*32.B	Certification of Chief Financial Officer pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
*99.A	Ryder Scott reserve report for El Paso Exploration & Production Company as of December 31, 2006
*99.B	Ryder Scott reserve report for Four Star Oil & Gas Company as of December 31, 2006

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.

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