Filing Compare · EL PASO EXPLORATION & PRODUCTION CO

CAPTIONTable PAGE ------- ---- Part I Item 1. Business.................................................... 2 Item 2. Properties.................................................. 8 Item 3. Legal Proceedings........................................... 8 Item 4. Submission of Matters to a Vote of Security Holders......... 8 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................................... 8 Item 6. Selected Financial Data..................................... 8 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 9 Risk Factors and Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995............................. 21 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...................................................... 29 Item 8. Financial Statements and Supplementary Data................. 30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 65 Item 9A. Controls and Procedures..................................... 65 Item 9B. Other Information........................................... 67 Part III Item 10. Directors and Executive Officers of the Registrant.......... 67 Item 11. Executive Compensation...................................... 68 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................ 74 Item 13. Certain Relationships and Related Transactions.............. 74 Item 14. Principal Accountant Fees and Services...................... 75 Part IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....................................................... 75 Signatures.................................................. 79Contents

2002Table 2001 2003 (RESTATED) (RESTATED) ---- ---------- ---------- (IN MILLIONS, EXCEPT RATES) Income tax expense at the statutory federal rate of 35%.................................................... $ 76 $162 $68 Increase (decrease) State income tax, net of federal income tax benefit(1).......................................... 12 2 (3) Earnings from unconsolidated affiliates................ -- (4) (8) Other.................................................. -- 1 5 ---- ---- --- Income tax expense....................................... $ 88 $161 $62 ==== ==== === Effective tax rate....................................... 40% 35% 32% ==== ==== ===Contents

CUMULATIVETable COSTSof EXCLUDED FOR CUMULATIVE BALANCE YEARS ENDED BALANCE DECEMBER 31, DECEMBER 31, DECEMBER 31, ------------ ------------------ ------------ 2003 2003 2002 2001 2000 ------------ ---- ---- ---- ------------ Acquisition............................. $107 $ 38 $ 52 $11 $ 6 Exploration............................. 115 78 21 14 2 Development............................. 30 2 28 -- -- ---- ---- ---- --- ----- $252 $118 $101 $25 $ 8 ==== ==== ==== === =====Contents

NUMBERTable OFof SECURITIES UNDERLYING UNEXERCISED VALUE OF UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT SHARES ACQUIRED VALUE FISCAL YEAR-END(#) FISCAL YEAR-END ($)(1) ON EXERCISE REALIZED --------------------------- --------------------------- NAME (#) ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE ---- --------------- -------- ----------- ------------- ----------- ------------- Rodney D. Erskine...... -- $-- 150,417 -- $-- $-- Randy L. Bartley....... -- $-- 83,038 18,337 $-- $--Contents

DATETable EVENT REPORTED ---- -------------- February 2, 2004 Provided an update on Production segment. February 17, 2004 El Paso Corporation, our parent company, announced that it had completed its annual review of natural gas and oil reserve estimates. El Paso provided its proved reserve estimate and production update (which included ours). March 10, 2004 El Paso Corporation, our parent company, announced that it will delay the release of its fourth quarter 2003 earnings pending the completion of a review of the impact of its recently announced reserve revision. May 3, 2004 El Paso Corporation, our parent company, announced findings of an independent review of the Audit Committee of its Board of Directors concerning the revisions to its oil and natural gas reserves (including our reserves). May 28, 2004 El Paso Corporation, our parent company, issued a press release providing a progress report on its long-range plan, financial and operational information for the fourth quarter of 2003 and the first quarter of 2004, and an update on the filing of El Paso Corporation and our 2003 Form 10-K and the first quarter 2004 Form 10-Q. June 29, 2004 El Paso Corporation, our parent company, provided an update of its strategic plan for its production business, which includes our business. July 9, 2004 Announced that we entered into an agreement with the holders of a majority of our 7 3/4% senior notes providing for a waiver of our breach of the covenant to timely file our annual and quarterly reports with the SEC. August 10, 2004 Announced that we expect to file our 2003 Form 10-K before the end of the third quarter of 2004.Contents

~~NET~~ UNITED PROVED RESERVES(1) ---------------------------------------------- NATURAL 2003 GAS LIQUIDS(2) TOTAL PRODUCTION --------- ---------- --------------------- ---------- (MMCF) (MBBLS) (MMCFE) (PERCENT) (BCFE) Onshore Texas................................. 74,329 2,114 87,013 6 32 Central............................... 342,119 3,310 361,977 23 40 --------- ------ --------- --- --- Total Onshore......................... 416,448 5,424 448,990 29 72 Offshore................................ 184,707 12,012 256,779 17 114 Coal Seam............................... 835,536 -- 835,536 54 40 --------- ------ --------- --- --- Total................................. 1,436,691 17,436 1,541,305 100 226 ========= ====== ========= === ===STATES

~~NET~~ SECURITIES ~~PROVED~~AND ~~RESERVES(1)~~EXCHANGE ------------------------------------ RELATIVE NATURAL GAS LIQUIDS(2) TOTAL PERCENTAGE ----------- ---------- --------- ---------- (MMCF) (MBBLS) (MMCFE) Producing................................. 791,318 9,876 850,571 55 Non-Producing............................. 135,080 3,897 158,461 10 Undeveloped............................... 510,293 3,663 532,273 35 --------- ------ --------- --- Total proved............................ 1,436,691 17,436 1,541,305 100 ========= ====== ========= ===COMMISSION

DEVELOPED UNDEVELOPED TOTAL ------------------ --------------------- --------------------- GROSS(1) NET(2) GROSS(1) NET(2) GROSS(1) NET(2) -------- ------- --------- --------- --------- --------- Onshore............... 201 Washington,~~438 79,090 516,544 375,423 717,982 454,513 Offshore~~ D.C.~~............~~ 336,066 244,267 497,649 465,251 833,715 709,518 Coal Seam............. 244,396 175,995 1,254,971 1,032,453 1,499,367 1,208,448 ------- ------- --------- --------- --------- --------- Total............... 781,900 499,352 2,269,164 1,873,127 3,051,064 2,372,479 ======= ======= ========= ========= ========= =========20549

~~PRODUCTIVE NATURAL GAS PRODUCTIVE OIL TOTAL PRODUCTIVE NUMBER OF WELLS WELLS WELLS WELLS BEING DRILLED~~ Form 10----------------- ----------------- ----------------- ----------------- GROSS(1) NET(2) GROSS(1) NET(2) GROSS(1) NET(2) GROSS(1) NET(2) -------- ------ -------- ------ -------- ------ -------- ------ Onshore............... 641 494 1 -- 642 494 7 3 Offshore.............. 155 87 40 15 195 102 3 2 Coal Seam............. 1,708 1,274 -- -- 1,708 1,274 65 47 ----- ----- -- -- ----- ----- -- -- Total............... 2,504 1,855 41 15 2,545 1,870 75 52 ===== ===== == == ===== ===== == ==K

NET EXPLORATORY WELLS DRILLED(1) NET DEVELOPMENT WELLS DRILLED(1) --------------------------------- --------------------------------- 2002 2001 2002 2001 2003 (RESTATED) (RESTATED) 2003 (RESTATED) (RESTATED) ----- ----------- ----------- ----- ----------- ----------- Productive.................... 35 9 10 219 334 261 Dry........................... 13 6 5 -- 4 3 -- -- -- --- --- --- Total....................... 48 15 15 219 338 264 == == == === === ===


(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, 2005

or

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

For the transition period from to

~~2003~~ Commission ~~2002~~File ~~2001~~Number 333------ ------ ------ Net Production Volumes Natural gas (Bcf)........................................ 191 215 187 Oil, condensate and liquids (MMBbls)..................... 6 10 6 Total (Bcfe).......................................... 226 272 221 Natural Gas Average Sales Price (per Mcf)(1) Price including hedges(2)(3)............................. $ 3.83 $ 3.02 $ 2.57 Price excluding hedges................................... $ 5.56 $ 3.25 $ 4.33 Oil, Condensate, and Liquids Average Sales Price (per Bbl)(1) Price including hedges(2)................................ $26.67 $21.87 $21.50 Price excluding hedges................................... $28.08 $22.06 $23.19 Average Transportation Costs Natural gas (per Mcf).................................... $ 0.19 $ 0.19 $ 0.21 Oil, condensate and liquids (per Bbl).................... $ 1.23 $ 1.23 $ 0.49 Average Production Costs (per Mcfe) Average lease operating costs............................ $ 0.36 $ 0.33 $ 0.34 Average production taxes................................. 0.12 0.07 0.11 ------ ------ ------ Total production costs(4)............................. $ 0.48 $ 0.40 $ 0.45 ====== ====== ======106586

~~2002~~ El Paso 2001 2003 (RESTATED) (RESTATED) ---- ---------- ---------- (IN MILLIONS) Acquisition Costs: Proved................................................. $ 37 $ 339 $ 4 Unproved............................................... 26 16 7 Development Costs........................................ 398 695 494 Exploration & ~~Costs:~~Production Delay Rentals.......................................... 3 3 5 Seismic Acquisition and Reprocessing................... 55 33 25 Drilling............................................... 194 290 123 ---- ------ ---- Total............................................... $713 $1,376 $658 ==== ====== ====Company

~~NAME~~ (Exact ~~OFFICE~~name ~~OFFICER~~of ~~SINCE~~Registrant ~~AGE~~as ~~----~~Specified ~~------~~in ~~-------------~~Its ~~--- Lisa A. Stewart........................ President 2004 47 D. Mark Leland......................... Executive Vice President and 2004 42 Chief Financial Officer~~Charter)

YEAR ENDED DECEMBER 31, -------------------------------------------------------------------- 2002 2001 2000 1999 2003 (RESTATED)(1) (RESTATED)(1) (RESTATED)(1) (RESTATED)(1) ---- ------------- ------------- ------------- ------------- (IN MILLIONS) Operating Results Data: Operating revenues...................... $895 $849 $604 $529 $498 Depreciation, depletion and amortization......................... 379 396 260 180 142 Ceiling test charges.................... -- -- -- -- 43 Gain on long-lived assets............... -- 211 -- -- -- Earnings from unconsolidated affiliates........................... 9 7 30 11 -- Income taxes............................ 88 161 62 76 27 Income from continuing operations....... 130 303 133 152 39


Delaware		76-0659544
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

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

AS Telephone OFNumber: ~~DECEMBER 31, ---------------------------------------------------------------------- 2002 2001 2000 1999 2003~~ (~~RESTATED~~713)~~(1) (RESTATED)(1) (RESTATED)(1) (RESTATED)(1)~~ 420------ ------------- ------------- ------------- ------------- (IN MILLIONS) Financial Position Data: Total assets........................... $3,479 $3,717 $2,639 $1,902 $1,682 Total long-term debt................... 1,200 -- -- -- -- Stockholder's equity................... 1,463 2,951 2,281 1,644 1,5822600

~~2000~~ Securities ~~1999~~registered ~~-------------------~~pursuant ~~-------------------~~to ~~REPORTED RESTATED REPORTED RESTATED -------- -------- -------- --------~~ Section 12(~~IN MILLIONS~~b) ~~Income~~of ~~(loss)~~the Act: from continuing operations......... $ 140 $ 152 $ (202) $ 39 Total assets..................................... 2,358 1,902 2,174 1,682 Stockholder's equity............................. 2,147 1,644 1,895 1,582None

~~YEAR~~ Securities ~~ENDED~~registered ~~------------------~~pursuant ~~2002~~to ~~2003~~ Section 12(~~RESTATED~~g) ~~-----~~of ~~----------~~the Act: (IN MILLIONS) Cash flows from operating activities........................ $ 619 $ 774 Cash flows from investing activities........................ (634) (1,168) Cash flows from financing activities........................ (107) 550None

~~2004~~ Indicate ~~2005~~by ~~2006~~check ~~2007~~mark ~~2008~~if ~~THEREAFTER~~the ~~TOTAL~~registrant ~~----~~is ~~----~~a well-~~---~~known seasoned ~~---- ---- ---------- ------ Long-term financing obligations: Principal.................... $ -- $ -- $ -- $ -- $ -- $1~~issuer,~~200~~ ~~$1,200~~as ~~Interest.....................~~defined 93in 93Rule 405 93of 93the ~~93 419 884 Operating leases~~Securities Act............... 1 1 1 -- -- -- 3 Other contractual obligations.................. 22 14 10 9 17 33 105 ---- ---- ---- ---- ---- ------ ------ Total contractual obligations.................. $116 $108 $104 $102 $110 $1,652 $2,192 ==== ==== ==== ==== ==== ====== ====== Yes o No þ

~~QUARTER~~ Indicate ~~ENDED~~by ~~---------------------------------------------------------------------~~check ~~MARCH~~mark 31if ~~JUNE~~the 30registrant ~~SEPTEMBER~~is 30not ~~DECEMBER~~required 31to ~~TOTAL~~file reports ~~---------------~~pursuant ~~---------------~~to ~~---------------~~Section 13 ~~---------------~~or ~~--------------- VOLUME HEDGED VOLUME HEDGED VOLUME HEDGED VOLUME HEDGED VOLUME HEDGED~~ Section 15(~~BBTU~~d) ~~PRICE~~of ~~(BBTU) PRICE (BBTU) PRICE (BBTU) PRICE (BBTU) PRICE ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ 2004~~the Act................. 18,842 $3.10 18,842 $3.10 18,854 $3.14 18,855 $3.14 75,393 $3.12 2005................. 19,820 $3.15 19,832 $3.15 19,844 $3.16 19,845 $3.16 79,341 $3.16 2006................. 20,900 $3.28 20,912 $3.28 20,924 $3.28 20,925 $3.28 83,661 $3.28 2007 and beyond............................................................................. 25,200 $3.60 Yes o No þ

~~VOLUME~~ Indicate ~~HEDGED~~by check mark whether the registrant (~~BBTU~~1) has ~~PRICE~~filed all ~~------~~reports ~~-------~~required ~~June~~to ~~2004~~be -filed ~~December~~by ~~2004...................................~~Section 13 ~~1,070~~or ~~$6.33~~15(d) ~~2005........................................................~~of the ~~1,825~~Securities ~~$5.78~~Exchange ~~2006........................................................~~Act ~~1,825~~of ~~$5.28~~1934 ~~January~~during ~~2007~~the -preceding 12 months ~~May~~(or ~~2007.....................................~~for ~~755~~such ~~$5.23~~shorter ~~-----~~period 5that the registrant was required to file such reports),~~475~~ ~~=====~~and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o.

~~2002~~ Indicate ~~2001~~by ~~2003~~check ~~(RESTATED)(1)~~mark ~~(RESTATED)(1)~~if ~~-----~~disclosure ~~-------------~~of ~~-------------~~delinquent ~~(IN~~filers pursuant ~~MILLIONS)~~to ~~Operating~~Item 405 ~~revenues...................................... $ 895 $ 849 $ 604 Operating expenses...................................... (629) (402) (445)~~ of Regulation S-~~----~~K ~~-----~~is not ~~-----~~contained ~~Operating~~herein, ~~income......................................~~and ~~266~~will ~~447~~not ~~159~~be ~~Earnings~~contained, ~~from~~to ~~unconsolidated~~the ~~affiliates.................~~best 9of registrant’s 7knowledge, ~~30 Minority interest~~ in ~~consolidated~~definitive ~~subsidiaries..........~~proxy ~~(3)~~or ~~(3)~~information statements ~~(4)~~incorporated ~~Other~~by ~~income,~~reference ~~net.......................................~~in 3Part III 5 1 ----- ----- ----- EBIT.................................................. 275 456 186 Affiliated interest income.............................. 13 8 9 Interest expense........................................ (70) -- -- Income taxes............................................ (88) (161) (62) ----- ----- ----- Income from continuing operations....................... 130 303 133 Cumulative effect of ~~accounting changes, net of income taxes................................................. 1~~ this Form 10--K --or ~~-----~~any amendment ~~-----~~to this Form 10-~~---- Net income~~K.~~............................................. $ 131 $ 303 $ 133 ===== ===== =====~~ þ

~~2002~~ Indicate ~~2001~~by ~~2003~~check ~~(RESTATED)(1)~~mark ~~(RESTATED)(1)~~whether ~~--------~~the ~~-------------~~registrant ~~-------------~~is ~~(IN~~a ~~MILLIONS~~large accelerated filer, ~~EXCEPT~~an ~~VOLUMES~~accelerated ~~AND PRICES) Operating revenues: Natural gas........................................ $ 734 $ 648 $ 483 Oil~~filer, ~~condensate~~or ~~and~~a ~~liquids........................ 152 211 120 Other.............................................. 9 (10) 1~~ non-~~------- -------- -------- Total operating revenues~~accelerated filer.~~..................~~ ~~895~~See ~~849~~definition 604 Transportation and net product costs................. (50) (55) (43) -------- -------- -------- Total operating margin..................... 845 794 561 Depreciation, depletion and amortization............. (379) (396) (260) Production costs(2).................................. (109) (108) (97) General and administrative expenses, net of ~~capitalized~~“accelerated ~~cost...................................~~filer ~~(79) (49) (35) Taxes, other than production~~ and ~~income~~large accelerated ~~taxes........~~filer” (6) (5) (8) Gain on long-lived assets and other charges(3)....... (6) 211 (2) -------- -------- -------- Total operating expenses(4)................ (579) (347) (402) -------- -------- -------- Operating income................................... 266 447 159 Earnings from unconsolidated affiliates.............. 9 7 30 Minority interest in ~~consolidated subsidiaries....... (3) (3) (4) Other income, net.................................... 3 5 1~~ Rule 12b-------- -------- -------- EBIT................................................. $ 275 $ 456 $ 186 ======== ======== ======== Volumes, Prices and Costs per unit: Natural gas Volumes (MMcf).................................. 191,400 214,529 187,379 ======== ======== ======== Average realized prices including hedges ($/Mcf)(5).................................... $ 3.83 $ 3.02 $ 2~~.57~~ ~~========~~of ~~========~~the ~~========~~Exchange ~~Average realized prices excluding hedges ($/Mcf)(5)~~Act.~~................................... $ 5.56 $ 3.25 $ 4.33 ======== ======== ======== Average transportation costs~~ (~~$/Mcf)............~~Check ~~$ 0.19 $ 0.19 $ 0.21 ======== ======== ======== Oil, condensate and liquids Volumes (MBbls~~one)................................. 5,719 9,629 5,600 ======== ======== ======== Average realized prices including hedges ($/Bbl)(5).................................... $ 26.67 $ 21.87 $ 21.50 ======== ======== ======== Average realized prices excluding hedges ($/Bbl)(5).................................... $ 28.08 $ 22.06 $ 23.19 ======== ======== ======== Average transportation costs ($/Bbl)............ $ 1.23 $ 1.23 $ 0.49 ======== ======== ======== Production costs ($/Mcfe) Average lease operating costs................... $ 0.36 $ 0.33 $ 0.34 Average production taxes........................ 0.12 0.07 0.11 -------- -------- -------- Total production costs(2)..................... $ 0.48 $ 0.40 $ 0.45 ======== ======== ======== Average general and administrative costs ($/Mcfe)........................................ $ 0.35 $ 0.18 $ 0.16 ======== ======== ======== Unit of production depletion cost ($/Mcfe)......... $ 1.59 $ 1.42 $ 1.14 ======== ======== ========:

~~VARIANCE~~Large ~~---------------------------------------~~accelerated ~~PRODUCTION~~filer ~~REVENUE~~o ~~VARIANCE~~Accelerated ~~ANALYSIS~~filer ~~PRICES~~o ~~VOLUMES HEDGES TOTAL~~ Non-~~-----------------------------------~~accelerated ~~------~~filer ------- ------ ----- (IN MILLIONS) Natural gas..................................... $443 $ (75) $(282) $ 86 Oil, condensate and liquids..................... 34 (87) (6) (59) Other........................................... -- -- -- 19 ---- ----- ----- ---- Operating revenues variance................... $477 $(162) $(288) $ 46 ==== ===== ===== ====þ

~~VARIANCE~~ Indicate ~~---------------------------------~~by ~~PRODUCTION~~check ~~REVENUE~~mark ~~ANALYSIS~~whether ~~PRICES~~the ~~VOLUMES~~registrant ~~HEDGES~~is ~~TOTAL~~a ~~---------------------------~~shell ~~------ ------- ------ -----~~ company (INAs ~~MILLIONS)~~defined ~~Natural~~in ~~gas......................................... $ (232) $117 $280 $165 Oil, condensate and liquids......................... (10) 93 8 91 Other...............................................~~ Rule 12b--2 --of --the ~~(11~~Exchange Act) ~~------ ---- ---- ---- Total operating revenues~~. Yes o No þ.~~........................ $ (242) $210 $288 $245 ====== ==== ==== ====~~

10 State ~~PERCENT~~the ~~INCREASE~~aggregate 10market ~~PERCENT~~value ~~DECREASE~~of ~~-----------------------~~the ~~---------------------~~voting ~~FAIR~~and ~~VALUE FAIR VALUE (DECREASE) FAIR VALUE INCREASE~~ non-~~---------~~voting common ~~----------~~equity ~~----------~~held ~~----------~~by non-~~-------~~affiliates ~~(IN MILLIONS) Impact~~ of ~~changes~~the inregistrant: ~~commodity prices on derivative commodity instruments December 31, 2003............... $(443) $(564) $(121) $(322) $121 December 31, 2002............... $(375) $(544) $(169) $(206) $169~~None

~~PAGE~~ Indicate ~~----~~the ~~Consolidated~~number ~~Statements~~ of ~~Income................................~~shares 31outstanding ~~Consolidated Balance Sheets...................................... 32 Consolidated Statements~~ of ~~Cash~~each ~~Flows............................ 33 Consolidated Statements~~ of ~~Stockholder'~~the registrant’s ~~Equity..................~~classes ~~34 Consolidated Statements~~ of ~~Comprehensive~~common Income.................. 35 Notes to Consolidated Financial Statements....................... 36 1. Restatement of Historical Financial Statements.............. 36 2. Significant Events and Accounting Policies.................. 41 3. Acquisitions and Divestitures............................... 45 4. Income Taxes................................................ 46 5. Financial Instruments and Price Risk Management 48 Activities.................................................. 6. Propertystock, ~~Plant~~as and Equipment............................... 49 7. Debt and Other Credit Facilities............................ 49 8. Commitments and Contingencies............................... 50 9. Retirement Benefits......................................... 52 10. Supplemental Cash Flow Information.......................... 53 11. Investments in Unconsolidated Affiliates and Related Party 53 Transactions................................................ 12. Supplemental Selected Quarterly Financial Information 57 (Unaudited)................................................. 13. Supplemental Natural Gas and Oil Operations (Unaudited)..... 57 Report of ~~Independent~~the ~~Registered~~latest practicable ~~Public Accounting Firm~~date.~~......... 63 Schedule II -- Valuation and Qualifying Accounts................. 64~~

~~YEAR~~ Common ~~ENDED DECEMBER 31~~Stock, ~~------------------------------~~par ~~2002~~value ~~2001 2003 (RESTATED) (RESTATED) ---- ---------- ---------- Operating revenues Natural gas and oil sales -- third parties................~~ $~~135 $ 174 $106 Natural gas and oil sales -- affiliates................... 751 685 497 Other..................................................... 9 (10)~~ 1 per ~~---- ----- ---- 895 849 604 ---- ----- ---- Operating expenses Cost of sales~~share.~~............................................~~ 50Shares 55outstanding ~~43 Operation and maintenance................................. 167 137 113 Gain~~ on ~~long-lived assets................................. -- (211) -- Depreciation~~ March 17, ~~depletion~~2006: and amortization.................. 379 396 260 Taxes, other than income taxes............................ 33 25 29 ---- ----- ---- 629 402 445 ---- ----- ---- Operating income............................................ 266 447 159 Earnings from unconsolidated affiliates..................... 9 7 30 Minority interest in consolidated subsidiaries.............. (3) (3) (4) Other income, net........................................... 3 5 1 Affiliated interest income.................................. 13 8 9 Interest expense............................................ (70) -- -- ---- ----- ---- Income before income taxes.................................. 218 464 195 Income taxes................................................ (88) (161) (62) ---- ----- ---- Income from continuing operations........................... 130 303 133 ---- ----- ---- Cumulative effect of accounting changes, ~~net of income taxes..................................................... 1 -- -- ---- ----- ---- Net income.................................................. $131 $ 303 $133 ==== ===== ====~~000

~~DECEMBER~~ EL PASO ~~31,~~EXPLORATION ~~DECEMBER~~& PRODUCTION ~~31,~~COMPANY ~~2002~~MEETS ~~2003~~THE ~~(RESTATED)~~CONDITIONS ~~------------~~OF ------------ ASSETS Current assets Cash and cash equivalents................................. $ 34 $ 156 Accounts and notes receivable Customer, net of allowance of $6 in 2003 and $5 in 2002................................................... 66 114 Affiliates.............................................. 451 676 Other................................................... 4 4 Assets from price risk management activities.............. -- 34 Income tax receivable from affiliate...................... -- 91 Deferred income taxes..................................... 70 10 Other..................................................... 11 9 ------ ------ Total current assets.................................. 636 1,094 ------ ------ Property, plant and equipment, at cost Natural gas and oil properties Proved properties-full cost method...................... 7,074 6,737 Unevaluated costs excluded from amortization............ 252 276 Other..................................................... 123 107 ------ ------ 7,449 7,120 Less accumulated depreciation, depletion and amortization............................................ 5,141 4,855 ------ ------ Total property, plant and equipment, net.............. 2,308 2,265 ------ ------ Other assets Investments in unconsolidated affiliates.................. 6 198 Notes receivable from affiliates.......................... 295 36 Deferred income taxes..................................... 204 118 Other..................................................... 30 6 ------ ------ 535 358 ------ ------ Total assets.......................................... $3,479 $3,717 ====== ====== LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities Accounts payable Trade................................................... $ 63 $ 73 Affiliates.............................................. 7 10 Other................................................... 79 161 Liabilities from price risk management activities......... 173 9 Income tax payable to affiliate........................... 118 -- Other..................................................... 30 12 ------ ------ Total current liabilities............................. 470 265 ------ ------ Long-term debt.............................................. 1,200 -- ------ ------ Other Liabilities from price risk management activities......... 270 400 Other..................................................... 76 11 ------ ------ 346 411 ------ ------ Commitments and contingencies Minority interests of consolidated subsidiaries............. -- 90 Stockholder's equity Common stock, par value $1 per share; 1,000 shares authorized and outstanding.............................. -- -- Additional paid-in capital................................ 1,700 3,275 Retained earnings GENERAL INSTRUCTION I(~~deficit~~1)~~............................... 31~~ (~~100~~a) ~~Accumulated~~AND ~~other comprehensive loss......................~~ (~~268~~b) ~~(224)~~ TO FORM 10-~~-----~~K ~~------~~AND ~~Total~~IS THEREFORE ~~stockholder's~~FILING ~~equity............................~~THIS ~~1,463~~REPORT ~~2,951~~WITH ~~------~~A ~~------~~REDUCED ~~Total~~DISCLOSURE ~~liabilities~~FORMAT ~~and~~AS PERMITTED ~~stockholder's~~BY ~~equity............~~SUCH ~~$3,479 $3,717 ====== ======~~INSTRUCTION.

~~YEAR~~ Documents ~~ENDED~~Incorporated DECEMBER 31, --------------------------------------- 2002 2001 2003 (RESTATED)(1) (RESTATED)(1) ------- ------------- ------------- Cash flows from operating activities Net income............................................... $ 131 $ 303 $ 133 Adjustments to reconcile net income to net cash from operating activities Depreciation, depletion and amortization.............. 379 396 260 Deferred income tax expense (benefit)................. (126) 122 135 Gain on long-lived assets............................. -- (211) -- Earnings of unconsolidated affiliates, net of cash distributions....................................... (9) (14) (19) Other non-cash income items........................... 3 20 (1) Asset and liability changes Accounts receivable................................. 55 136 18 Income taxes from affiliate......................... 214 (33) (85) Accounts payable.................................... (26) 80 (99) Other asset and liability changes................... (2) (25) 13 ------- ------- ----- Net cash provided by ~~operating~~Reference: activities........ 619 774 355 ------- ------- ----- Cash flows from investing activities Capital expenditures..................................... (815) (1,290) (675) Net proceeds from the sale of assets and investments..... 501 399 20 Change in notes receivable from parent................... (326) (271) (237) Restricted cash.......................................... 6 (6) -- ------- ------- ----- Net cash used in investing activities............ (634) (1,168) (892) ------- ------- ----- Cash flows from financing activities Net proceeds from the issuance of long-term debt......... 1,169 -- -- Dividends to parent...................................... (1,276) (298) (22) Contributions from parent................................ -- 848 559 ------- ------- ----- Net cash provided by (used in) financing activities..................................... (107) 550 537 ------- ------- ----- Change in cash and cash equivalents........................ (122) 156 -- Cash and cash equivalents Beginning of period...................................... 156 -- -- ------- ------- ----- End of period............................................ $ 34 $ 156 $ -- ======= ======= =====None

~~FOR~~ EL ~~THE~~PASO ~~YEARS~~EXPLORATION ~~ENDED~~& ~~DECEMBER~~PRODUCTION 31, ---------------------------------------------------- 2002 2001 2003 (RESTATED) (RESTATED) ---------------- --------------- --------------- 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............. 3,275 2,723 2,180 Contribution from parent................. 26 848 559 Allocated tax benefit (expense) of equity plans................................. (5) 2 6 Dividends to parent...................... (1,596) (298) (22) ------- ------ ------ Balance at end of year................ 1,700 3,275 2,723 ------- ------ ------ Retained earnings (deficit): Balance at beginning of year............. (100) (403) (536) Net income............................... 131 303 133 ------- ------ ------ Balance at end of year................ 31 (100) (403) ------- ------ ------ Accumulated other comprehensive loss: Balance at beginning of year............. (224) (39) -- Other comprehensive loss................. (44) (185) (39) ------- ------ ------ Balance at end of year................ (268) (224) (39) ------- ------ ------ Total stockholder's equity................. 1,000 $ 1,463 1,000 $2,951 1,000 $2,281 ===== ======= ===== ====== ===== ======COMPANY

~~YEAR~~ TABLE ~~ENDED~~OF DECEMBER 31, ------------------------------- 2002 2001 2003 (RESTATED) (RESTATED) ----- ---------- ---------- Net income.................................................. $ 131 $ 303 $ 133 ----- ----- ----- Net gains (losses) from cash flow hedging activities: Cumulative effect of transition adjustment (net of income tax of $356)........................................... -- -- (662) Unrealized mark-to-market gains (losses) arising during period (net of income tax of $(126), $(118) and $200 in 2003, 2002 and 2001)................................... (220) (206) 386 Reclassification adjustments for changes in initial value to settlement date (net of income taxes of $101, $12 and $137 in 2003, 2002 and 2001)....................... 176 21 237 ----- ----- ----- Other comprehensive loss............................... (44) (185) (39) ----- ----- ----- Comprehensive income........................................ $ 87 $ 118 $ 94 ===== ===== =====CONTENTS

AS OF DECEMBER 31, --------------------------------------------------------------- 2002 2001 2000 ------------------- ------------------- ------------------- AS AS AS AS AS AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED -------- -------- -------- -------- -------- -------- Onshore............................ 1,075 694 1,269 739 909 648 Offshore........................... 506 325 520 329 419 270 Coal Seam.......................... 1,243 664 667 310 439 234 ----- ----- ----- ----- ----- ----- Total ............................. 2,824 1,683 2,456 1,378 1,767 1,152 ===== ===== ===== ===== ===== =====


Caption		Page

Part I
Item 1.	Business		1
Item 1A.	Risk Factors		8
	Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		8
Item 1B.	Unresolved Staff Comments		15
Item 2.	Properties		15
Item 3.	Legal Proceedings		15
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		15
Item 6.	Selected Financial Data		*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		24
Item 8.	Financial Statements and Supplementary Data		25
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		52
Item 9A.	Controls and Procedures		52
Item 9B.	Other Information		52
Part III
Item 10.	Directors and Executive Officers of the Registrant		*
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		*
Item 14.	Principal Accountant Fees and Services		53
Part IV
Item 15.	Exhibits and Financial Statement Schedules		53
	Signatures		57
Amended and Restated Certificate of Incorporation
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350

~~YEAR~~* ~~ENDED~~We ~~YEAR~~have ~~ENDED~~not ~~DECEMBER~~included ~~31,~~a ~~2002~~response ~~DECEMBER~~to ~~31,~~this ~~2001~~item ~~-------------------~~in ~~-------------------~~this ASdocument ASsince ASno ASresponse ~~REPORTED~~is ~~RESTATED~~required ~~REPORTED~~pursuant ~~RESTATED~~to ~~--------~~the ~~--------~~reduced ~~--------~~disclosure ~~--------~~format ~~(IN~~permitted ~~MILLIONS)~~by ~~INCOME~~General ~~STATEMENT:~~Instruction ~~Operating~~I ~~revenues.......................................~~to $Form ~~841 $ 849 $ 604 $ 604 Gain on long~~10-~~lived assets~~K................................ 2 211 -- -- Depreciation, depletion and amortization................. 317 396 234 260 Operating income......................................... 309 447 185 159 Earnings from unconsolidated affiliates.................. 6 7 29 30 Income taxes............................................. 112 161 71 62 Net income............................................... 213 303 149 133 BALANCE SHEET: Property, plant and equipment, net....................... $2,808 $2,265 $2,101 $1,428 Investments in unconsolidated affiliates................. 232 198 256 220 Stockholder's equity(1).................................. 3,309 2,951 2,798 2,281

~~QUARTERS~~ Below ~~ENDED~~is ~~(UNAUDITED)~~a ~~---------------------------------------------------------------~~list ~~MARCH~~of ~~31,~~terms ~~2003~~that ~~JUNE~~are ~~30,~~common ~~2003~~to ~~SEPTEMBER~~our ~~30,~~industry 2003 ------------------- ------------------- ------------------- AS AS AS AS AS AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED -------- -------- -------- -------- -------- -------- (IN MILLIONS) Depreciation, depletion and used ~~amortization......~~throughout $this 85 $112 $76 $98 $67 $86 Operating income.............................. 144 117 94 72 71 52 Earnings from unconsolidated affiliates....... 8 9 -- -- -- -- Income taxes(1)............................... 51 54 23 15 31 11 Net income(1)................................. 95 68 47 32 20 21document:

~~QUARTERS~~/d ~~ENDED~~= ~~(UNAUDITED)~~per ~~-------------------------------------------------------------------------------------~~day ~~MARCH~~Bbl ~~31,~~= ~~2002~~barrels ~~JUNE~~BBtu ~~30,~~= ~~2002~~billion ~~SEPTEMBER~~British ~~30,~~thermal ~~2002~~units ~~DECEMBER~~Bcf ~~31,~~= ~~2002~~billion ~~-------------------~~cubic ~~-------------------~~feet ~~-------------------~~Bcfe ~~-------------------~~= ASbillion AScubic ASfeet ASof ASnatural ASgas ASequivalents ASMBbls ~~REPORTED~~= ~~RESTATED~~thousand ~~REPORTED~~barrels ~~RESTATED~~Mcf ~~REPORTED~~= ~~RESTATED~~thousand ~~REPORTED~~cubic ~~RESTATED~~feet ~~--------~~Mcfe ~~--------~~= ~~--------~~thousand ~~--------~~cubic ~~--------~~feet ~~--------~~of ~~--------~~natural ~~--------~~gas ~~(IN~~equivalents ~~MILLIONS)~~MMBtu ~~Operating~~= ~~revenues.....................~~million ~~$167~~British ~~$169~~thermal ~~$218~~units ~~$220~~MMcf ~~$245~~= ~~$247~~million ~~$211~~cubic ~~$213~~feet ~~Gain~~MMcfe on= ~~long-lived~~million ~~assets..............~~cubic 2feet ~~211~~of --natural --gas --equivalents --NGL --= --natural ~~Depreciation,~~gas ~~depletion~~liquids ~~and~~TBtu ~~amortization.........................~~= 76trillion 84British 82thermal 92units 84Tcfe ~~111~~= 75trillion ~~109~~cubic ~~Operating~~feet ~~income.......................~~of 43natural ~~247~~gas 80 72 108 82 78 46 Earnings (losses) from unconsolidated affiliates........................... 6 6 (6) (5) 5 4 1 2 Income taxes........................... 15 87 31 28 33 24 33 22 Net income............................. 33 163 48 43 76 61 56 36equivalents

~~QUARTERS~~ When ~~ENDED~~we ~~(UNAUDITED)~~refer ~~-------------------------------------------------------------------------------------~~to ~~MARCH~~natural ~~31,~~gas ~~2001~~and ~~JUNE~~oil ~~30,~~in ~~2001 SEPTEMBER 30~~“equivalents,” we ~~2001~~are ~~DECEMBER~~doing ~~31,~~so ~~2001~~to ~~-------------------~~compare ~~-------------------~~quantities ~~-------------------~~of ~~-------------------~~oil ASwith ASquantities ASof natural ASgas ASor ASto ASexpress ASthese ~~REPORTED~~different ~~RESTATED~~commodities ~~REPORTED~~in ~~RESTATED~~a common ~~REPORTED~~unit. ~~RESTATED~~In ~~REPORTED~~calculating ~~RESTATED -------- -------- -------- -------- -------- -------- -------- -------- (IN MILLIONS) Depreciation~~equivalents, ~~depletion~~we ~~and~~use ~~amortization.........................~~a ~~$52~~generally recognized ~~$52~~standard ~~$53~~in ~~$52~~which ~~$62~~one ~~$70~~Bbl ~~$67~~of ~~$86~~oil ~~Operating~~is ~~income.......................~~equal 37to 36six 34Mcf of 35natural ~~55 48 59 40 Earnings from unconsolidated affiliates~~gas.~~..........................~~ 9Also, 9when 5we 5refer 3to 4cubic 12feet 12measurements, all ~~Income~~measurements ~~taxes...........................~~are 8at 8a 20pressure 21of ~~18 16 25 17 Net income~~14.~~............................~~73 39pounds 38per ~~22 23 43 38 45 34~~square inch.

~~(IN~~ When ~~MILLIONS)~~we ~~-------------~~refer ~~Net~~to ~~asset~~“us”, ~~retirement~~“we”, “our”, ~~liability~~“ours”, at“EPEP” ~~January~~or 1“the Company”, ~~2003...........~~we $are 76describing ~~Liabilities~~El Paso Exploration & ~~settled~~Production inCompany ~~2003.................................~~and/or ~~(16) Accretion expense in 2003~~our subsidiaries................................... 7 Liabilities incurred in 2003................................ 4 Changes in estimate......................................... 8 ---- Net asset retirement liability at December 31, 2003......... $ 79 ====

2002 2001 2003 (RESTATED) (RESTATED) ----- ---------- ---------- (IN MILLIONS) Current Federal............................................... $ 189 $ 39 $(64) State................................................. 25 -- (9) ----- ---- ---- 214 39 (73) ----- ---- ---- Deferred Federal............................................... (118) 119 131 State................................................. (8) 3 4 ----- ---- ---- (126) 122 135 ----- ---- ---- Total income tax expense........................... $ 88 $161 $ 62 ===== ==== ====i

2002 2003 (RESTATED) ---- ---------- (IN MILLIONS) Deferred tax assets Net operating loss carryforwards.......................... $128 $190 Property, plant and equipment............................. 38 -- U.S. tax credit carryovers................................ 23 23 Price risk management activities.......................... 162 135 Other..................................................... 17 1 ---- ---- Total deferred tax asset............................... 368 349 ---- ---- Deferred tax liabilities Property, plant and equipment............................. -- 158 Employee benefits......................................... 43 16 Merger related costs...................................... 51 47 ---- ---- Total deferred tax liability........................... 94 221 ---- ---- Net deferred tax asset...................................... $274 $128 ==== ==== PART I

~~2003~~ITEM 2002 --------------------- --------------------- CARRYING CARRYING AMOUNT FAIR VALUE AMOUNT FAIR VALUE -------- ---------- -------- ---------- (IN MILLIONS) Long-term debt.............................. $1~~,200 $1,182 $ -- $ -- Net liability from price risk management activities~~.~~..............................~~ ~~$ 443 $ 443 $375 $375~~BUSINESS

CUMULATIVE CUMULATIVE BALANCE BALANCE DECEMBER 31, DECEMBER 31, 2003 2002 ------------ ------------ (IN MILLIONS) Acquisition................................................. $107 $108 Exploration................................................. 115 108 Development................................................. 30 60 ---- ---- $252 $276 ==== ==== General

~~2003~~ We ~~2002~~are ~~2001~~a ~~----~~Delaware ~~----~~corporation formed in 1999 as a wholly-~~---~~owned direct ~~(IN~~subsidiary ~~MILLIONS)~~of ~~Interest~~El Paso ~~paid~~Corporation (El Paso). On December 31, 2005, ~~net~~El Paso made a capital contribution to us of ~~amounts~~several ~~capitalized~~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., another subsidiary of El Paso. In conjunction with this contribution, El Paso Production Holding Company changed its name to El Paso Exploration & Production Company (EPEP).~~..............~~ ~~$36~~The ~~$--~~information $in this Annual Report on Form 10--K reflects the contribution of these companies and their related operations for all periods presented.

~~YEARS~~ We ~~ENDED~~are ~~DECEMBER~~engaged 31in the exploration for, ~~---------------------~~and ~~2003(1)~~the ~~2002~~acquisition, development ~~2001~~and ~~-------~~production ~~----~~of ~~----~~natural ~~(IN~~gas, ~~MILLIONS)~~oil ~~Operating~~and ~~results~~NGL ~~data:~~in ~~Operating~~the United ~~revenues~~States.~~.......................................~~ ~~$21~~As ~~$35~~of ~~$40~~December 31, 2005, ~~Operating~~we ~~expenses~~controlled approximately 2.8 million net leasehold acres.~~......................................~~ 9During 302005, daily 22equivalent ~~Net~~natural ~~income~~gas production averaged approximately 690 MMcfe/d and our proved natural gas and oil reserves at December 31, 2005 were approximately 2.~~...............................................~~2 Tcfe, excluding 9amounts 14related 19to our unconsolidated investment in Four Star Oil & Gas Company (Four Star).

~~DECEMBER~~ Our ~~31,~~consolidated ~~2002~~operations ~~-----------------~~are ~~Financial~~divided ~~position~~into ~~data:~~the Current assets............................................ $ 7 Non-current assets........................................ 165 Current liabilities....................................... 6 Equity in net assets...................................... 166following regions:

~~YEAR~~Region ~~ENDED~~Operating ~~DECEMBER~~Areas/Basins ~~31,~~Onshore ~~-------------~~East ~~2002~~Texas ~~2001~~and ~~-----~~North ~~-----~~Louisiana ~~(IN~~Rocky ~~MILLIONS)~~Mountains ~~REVENUES~~Black ElWarrior ~~Paso~~Arkoma ~~Production~~Raton ~~Holding~~Illinois ~~Company........................~~Texas ~~$834~~Gulf ~~$531~~Coast ElSouth ~~Paso~~Texas ~~CGP~~Gulf ~~replacement~~of ~~properties........................~~Mexico 15and 73south ~~----~~Louisiana ~~----~~Gulf ~~Combined..................................................~~of ~~$849~~Mexico ~~$604 ---- ---- NET INCOME~~ (~~LOSS)(RESTATED)~~Federal Eland ~~Paso~~State ~~Production Holding Company........................ $305 $111 El Paso CGP replacement properties........................ (2~~waters) 22South ~~---- ---- Combined.................................................. $303 $133 ---- ----~~Louisiana

~~QUARTERS~~ In ~~ENDED~~addition ~~----------------------------------------------------~~to ~~MARCH~~our 31consolidated ~~JUNE~~operations, 30we ~~SEPTEMBER~~own 30a 43.1 percent ~~(RESTATED)~~interest ~~(RESTATED)~~in ~~(RESTATED)~~Four ~~DECEMBER~~Star, 31which ~~TOTAL~~was ~~----------~~acquired ~~----------~~in connection ~~------------~~with ~~-----------~~our ~~-----~~acquisition of Medicine Bow Energy Corporation (INMedicine ~~MILLIONS~~Bow) ~~2003~~in ~~Operating revenues~~August 2005.~~...........~~ ~~$303~~Four ~~$234~~Star operates ~~$199~~onshore ~~$159~~in ~~$895~~the ~~Operating~~San ~~income..............~~Juan, ~~117~~Permian, 72Hugoton 52and 25South Alabama ~~266~~Basins ~~Income~~and ~~from~~in ~~continuing~~the ~~operations~~Gulf of Mexico.~~................~~ 67During 322005, 21our proportionate 10share ~~130~~of ~~Net~~Four ~~income....................~~Star’s ~~68(1)~~daily 32equivalent ~~21(1)~~natural gas 10production ~~131~~averaged approximately 24 MMcfe/d and at December 31, 2005 proved natural gas and oil reserves, net to our interest, were 253 Bcfe.

~~QUARTERS~~ Our ~~ENDED~~business ~~-----------------------------------------------~~strategy ~~MARCH~~has 31been ~~JUNE~~to 30create ~~SEPTEMBER~~value 30through ~~DECEMBER~~our drilling 31activities ~~TOTAL~~and ~~--------~~through ~~-------~~acquisitions ~~------------~~of ~~-----------~~assets ~~----- (IN MILLIONS) 2002 (Restated) Operating revenues~~and companies.~~.............~~ $For ~~169~~2006, ~~$220~~we ~~$247~~expect ~~$213~~our $growth ~~849~~to ~~Gain~~principally onoccur through ~~long-lived~~our ~~assets.......~~drilling ~~(211) -- -- -- (211) Operating income~~activities.~~...............~~ ~~247~~However, 72we 82believe 46strategic acquisitions ~~447~~can ~~Income~~support ~~from~~our ~~continuing~~corporate ~~operations................... 163 43 61 36 303 Net income...................... 163 43 61 36 303~~objectives by:

~~2002~~• ~~2003~~Re-shaping ~~(RESTATED)~~our ~~------~~portfolio toward longer-~~---------~~lived ~~(IN~~shallower ~~MILLIONS)~~decline ~~Natural~~rate ~~gas~~reserves; ~~and~~• ~~oil~~Leveraging ~~properties:~~operational ~~Costs~~expertise ~~subject~~we toalready ~~amortization.............................~~possess ~~$7,197~~in $6key operating areas,~~844~~ ~~Costs~~geologies ~~not~~or ~~subject~~techniques; • Balancing our exposure to ~~amortization.........................~~regions, ~~252~~basins ~~276~~and ~~------~~commodities; • Achieving risk-~~-----~~adjusted ~~7,449~~returns ~~7,120~~competitive ~~Less~~with ~~accumulated~~those ~~depreciation,~~available ~~depletion~~within ~~and~~our ~~amortization...~~existing ~~5,141~~inventory; ~~4,855~~and ~~------~~• ~~------~~Increasing ~~Net~~our ~~capitalized~~reserves ~~costs(1)....................................~~more ~~$2,308~~rapidly ~~$2,265~~by ~~======~~supplementing ~~======~~drilling activities.

2002(3) 2001(3) 2003 (RESTATED) (RESTATED) ---- ------------ ------------ (IN MILLIONS) Property acquisition costs Proved properties.................................. $ 37 $ 339 $ 4 Unproved properties................................ 26 16 7 Exploration costs(1)................................. 252 326 153 Development costs(1)................................. 398 695 494 ---- ------ ---- Total costs expended 713 1,376 658 ---- ------ ---- Plus: Asset retirement obligation costs(2)........... 47 -- -- Less: Actual retirement expenditures................. (5) -- -- ---- ------ ---- Total costs incurred............................... $755 $1,376 $658 ==== ====== ====

~~NATURAL~~ Natural ~~GAS~~Gas ~~LIQUIDS(1) (BCF) (MBBLS) ----------- ---------- Net proved developed~~ and ~~undeveloped~~Oil reserves(2) January 1, 2001........................................... 1,020 21,977 Revisions of previous estimates(3)..................... (20) (629) Extensions, discoveries and other...................... 437 10,390 Sales of reserves in place............................. (28) (68) Production............................................. (187) (5,599) ----- ------ December 31, 2001......................................... 1,222 26,071 Revisions of previous estimates(3)..................... 19 1,428 Extensions, discoveries and other...................... 554 7,620 Purchases of reserves in place......................... 137 62 Sales of reserves in place............................. (171) (2,676) Production............................................. (215) (9,628) ----- ------ December 31, 2002......................................... 1,546 22,877 Revisions of previous estimates(3)..................... 2 431 Extensions, discoveries and other...................... 316 3,119 Purchases of reserves in place......................... 64 640 Sales of reserves in place(4).......................... (300) (3,912) Production............................................. (191) (5,719) ----- ------ December 31, 2003......................................... 1,437 17,436 ===== ====== Proved developed reserves December 31, 2001......................................... 933 21,580 December 31, 2002......................................... 1,063 17,014 December 31, 2003......................................... 926 13,773Properties

~~2002~~Natural 2001 2003 (RESTATED)(3) (RESTATED)(3) ----- ------------- ------------- (IN MILLIONS) Net Revenues Sales to external customers................... $ 113 $ 119 $ 68 Affiliated sales.............................. 732 675 493 ----- ----- ----- Total......................................... 845 794 561 Production costs(1)................................ (109) (108) (97) DepreciationGas, ~~depletion~~Oil and ~~amortization(2)........~~Condensate ~~(379)~~and ~~(396)~~NGL ~~(260)~~Reserves ~~Gain~~and on long-lived assets.......................... -- 209 -- ----- ----- ----- 357 499 204 Income tax expense................................. (131) (181) (73) ----- ----- ----- Results of operations from producing activities.... $ 226 $ 318 $ 131 ===== ===== =====Production

~~2002~~ The ~~2001~~tables ~~2003~~below ~~(RESTATED)~~present ~~(RESTATED)~~our ~~-------~~estimated ~~----------~~proved ~~----------~~reserves ~~(IN~~as ~~MILLIONS) Future cash inflows(1)................................ $ 8~~of December 31,~~854~~ $2005 ~~7,728~~and $our ~~3,581~~2005 ~~Future~~ production ~~costs...............................~~by ~~(2,058)~~region ~~(1,744)~~and summarizes ~~(1,055)~~our Future development costs.............................. (761) (730) (450) Future income tax expenses............................ (1,368) (1,383) (270) ------- ------- ------- Future net cash flows................................. 4,667 3,871 1,806 10% annual discount for estimated ~~timing~~proved ofreserves ~~cash~~by ~~flows...............................................~~classification ~~(1,696)~~as ~~(1,442) (555) ------- ------- ------- Standardized measure~~ of ~~discounted future net cash flows............................................... $ 2~~ December 31,~~971~~ ~~$ 2,429 $ 1,251 ======= ======= ======= Standardized measure of discounted future net cash flows, including effects of hedging activities...... $ 2,537 $ 2,105 $ 1,406 ======= ======= =======~~2005:

YEARS ENDED DECEMBER 31,(1) ------------------------------- 2002 2001 2003 (RESTATED) (RESTATED) ----- ---------- ---------- Sales and transfers of natural gas and oil produced net of production costs.......................................... $(737) $ (678) $ (464) Net changes in prices and production costs.................. 699 1,358 (2,163) Extensions, discoveries and improved recovery, less related costs..................................................... 710 1,037 448 Changes in estimated future development costs............... (7) (40) 42 Previously estimated development costs incurred during the period.................................................... 160 150 28 Revision of previous quantity estimates..................... 11 63 (26) Accretion of discount....................................... 312 135 328 Net change in income taxes.................................. 72 (587) 868 Purchases of reserves in place.............................. 168 271 -- Sale of reserves in place................................... (775) (368) (19) Change in production rates, timing and other................ (71) (163) (103) ----- ------ ------- Net change................................................ $ 542 $1,178 $(1,061) ===== ====== =======


			Net Proved Reserves⁽¹⁾

			Natural		Oil/								2005
			Gas		Condensate		NGL		Total				Production

			(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(Percent)		(MMcfe)
Reserves and Production by Region
	Onshore			1,258,329		32,007		1,207		1,457,615		67%		109,361
	Texas Gulf Coast			392,783		2,765		9,702		467,580		22%		77,014
	Gulf of Mexico and south Louisiana			179,654		8,456		1,653		240,311		11%		65,432

		Total		1,830,766		43,228		12,562		2,165,506		100%		251,807

	Unconsolidated investment in Four Star⁽²⁾⁽³⁾			192,895		3,349		6,668		252,996		100%		8,844

Reserves by Classification
	Producing			1,175,838		19,831		9,503		1,351,841		63%
	Non-Producing			228,173		8,750		1,507		289,716		13%
	Undeveloped			426,755		14,647		1,552		523,949		24%

		Total proved		1,830,766		43,228		12,562		2,165,506		100%

	Unconsolidated investment in Four Star⁽²⁾
	Producing			154,979		3,246		5,371		206,677		82%
	Non-Producing			3,105		20		28		3,395		1%
	Undeveloped			34,811		83		1,269		42,924		17%

		Total Four Star		192,895		3,349		6,668		252,996		100%

CHARGED BALANCE AT TO COSTS CHARGED BALANCE BEGINNING AND TO OTHER AT END DESCRIPTION OF PERIOD EXPENSES DEDUCTIONS ACCOUNTS OF PERIOD ----------- ---------- -------- ---------- -------- --------- 2003 Allowance for doubtful accounts........... $ 5 $ 2 $ -- $ (1) $ 6 Legal reserves............................ 8 (3) (1) -- 4 2002 Allowance for doubtful accounts........... $ 6 $ (1) $ -- $ -- $ 5 Legal reserves............................ 8 1 (1) -- 8 2001 Allowance for doubtful accounts........... $ 6 $ -- $ -- $ -- $ 6 Legal reserves............................ -- 8 -- -- 8


⁽¹⁾	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.
⁽²⁾	Our share of Four Star’s proved reserves has been estimated based on an evaluation of those reserves by El Paso’s internal reservoir engineers, and not by engineers of Four Star. An independent reservoir engineering firm, Ryder Scott Company, which was engaged by us, prepared an estimate on 86 percent of Four Star’s proved reserves. Based on the amount of Four Star’s proved reserves determined by Ryder Scott, we believe our reported reserve amounts are reasonable.
⁽³⁾	Represents our proportionate share of Four Star’s production since the acquisition date.

~~NAME~~ Consolidated ~~AGE~~reserve ~~POSITION~~information ~~----~~in ~~---~~the ~~--------~~tables ~~Lisa~~above A.is ~~Stewart~~based on our internal reserve report.~~.......................~~ 47Ryder Scott, ~~Director;~~an ~~President~~independent reservoir Dengineering firm that reports to the Audit Committee of El Paso’s Board of Directors, prepared an estimate on 91 percent of our natural gas and oil reserves. ~~Mark~~Based ~~Leland~~on the amount of proved reserves determined by Ryder Scott, we believe our reported reserve amounts are reasonable.~~........................~~ 42This information ~~Director;~~is ~~Executive~~consistent ~~Vice~~with ~~President~~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 ~~Chief~~to ~~Financial~~reflect ~~Officer~~actual experience.

LONG-TERM COMPENSATION -------------------------------------- ANNUAL COMPENSATION AWARDS PAYOUTS ---------------------------------- ----------------------- ------------ RESTRICTED SECURITIES LONG-TERM OTHER ANNUAL STOCK UNDERLYING INCENTIVE ALL OTHER SALARY BONUS COMPENSATION AWARDS OPTIONS PLAN PAYOUTS COMPENSATION NAME AND PRINCIPAL POSITION YEAR ($) ($) ($)(1) ($)(2) (#) ($) ($)(3) --------------------------- ---- -------- -------- ------------ ---------- ---------- ------------ ------------ Rodney D. Erskine(4).......... 2003 $517,504 $ -- $ -- $ -- -- $ -- $2,729,685 Former President 2002 $375,000 $ -- $ -- $ -- -- $ -- $ 40,962 2001 $321,879 $262,518 $ -- $524,963 183,750 $ -- $ 225,927 Randy L. Bartley(4)........... 2003 $332,924 $ -- $ -- $ -- -- $ -- $ 12,079 Former Acting President 2002 $240,000 $ 98,000 $36,000 $ -- -- $ -- $ 19,974 and CEO 2001 $207,084 $ 98,006 $33,000 $195,987 101,375 $ -- $ 161,551

~~AGE~~ There ~~PLUS~~are ~~SERVICE~~numerous ~~PAY~~uncertainties ~~CREDIT~~inherent ~~PERCENTAGE~~in ~~----------------~~estimating quantities ~~---------------------~~of ~~Less~~proved ~~than~~reserves, 35projecting 4%future 35rates toof production 49costs 5%and 50projecting tothe 64timing 6%of 65development expenditures, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and ~~over~~oil 7%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.

~~PAY~~ All ~~CREDIT~~estimates ~~ESTIMATED~~of ~~PERCENTAGE~~proved ~~ANNUAL~~reserves ~~NAMED~~are ~~EXECUTIVE~~determined ~~CREDITED~~according ~~SERVICE~~to ~~DURING~~the rules ~~2003~~prescribed ~~BENEFITS(1)~~by ~~---------------~~the ~~----------------~~SEC. ~~-----------~~These ~~-----------~~rules ~~Rodney~~indicate ~~Erskine(2)~~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.~~.............................~~ 10Estimates 7%are ~~$69~~subject to revision based upon a number of factors,~~194~~ ~~Randy~~including ~~Bartley(3)~~reservoir performance, prices, economic conditions and government restrictions.~~...............................~~ 25In 7%addition, results ~~$79~~of drilling,~~519~~ testing and production subsequent to the date of an estimate may justify revision of that estimate.

~~BENEFICIAL~~ In ~~OWNERSHIP~~general, ~~(EXCLUDING~~the ~~STOCK~~volume ~~PERCENT~~of ~~TITLE~~production OFfrom ~~CLASS~~natural ~~NAME~~gas OFand ~~BENEFICIAL~~oil properties ~~OWNER~~we ~~OPTIONS)(1)~~own ~~OPTIONS(2)~~declines ~~TOTAL~~as OFreserves ~~CLASS~~are ~~--------------~~depleted. ~~------------------------~~Except ~~-----------~~to the ~~----------~~extent ~~-------~~we ~~--------~~conduct ~~Common~~successful ~~Stock~~exploration ~~Lisa~~and A.development activities ~~Stewart........................~~or ~~150~~acquire additional properties containing proved reserves,~~925(3)~~ --or ~~150~~both,~~925~~ *our ~~Common~~proved ~~Stock~~reserves D.will ~~Mark~~decline ~~Leland~~as reserves are produced.~~........................~~ ~~89,727~~Recovery ~~149,375~~of ~~239,102~~proved *undeveloped ~~Common~~reserves ~~Stock~~requires significant ~~Rodney~~capital D.expenditures ~~Erskine~~and successful drilling operations.~~.....................~~ ~~104~~The reserve data assumes that we can and will make these expenditures and conduct these operations successfully,~~854(4)~~ but ~~150~~future events,~~417~~ ~~255~~including commodity price changes,~~271~~ *may ~~Common~~cause these ~~Stock~~assumptions ~~Randy~~to Lchange. ~~Bartley.......................~~In ~~--(5) 101~~addition,~~375~~ ~~101,375~~estimates *of ~~-------~~proved undeveloped ~~-------~~reserves and proved non-~~------~~producing ~~Common~~reserves ~~Stock~~are subject ~~Directors~~to ~~and~~greater ~~executive~~uncertainties ~~officers~~than asestimates of proved producing reserves. For a ~~group~~further 4discussion ~~persons~~of ~~total................~~our ~~345~~reserves,~~506~~ see ~~401~~Part II,~~167~~ ~~746~~Item 8,~~673~~ *Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.

PAGE ---- Consolidated Statements of Income......................... 31 Consolidated Balance Sheets............................... 32 Consolidated Statements of Cash Flows..................... 33 Consolidated Statements of Stockholder's Equity........... 34 Consolidated Statements of Comprehensive Income........... 35 Notes to Consolidated Financial Statements................ 36 Report of Independent Registered Public Accounting Firm... 63 2. Financial statement schedules and supplementary information required to be submitted. Schedule II -- Valuation and Qualifying accounts.......... 64 Schedules other than that listed above are omitted because they are not applicable. 3~~. Exhibit list............................................. 77~~

~~EXHIBIT~~Acreage ~~NUMBER DESCRIPTION -------- ----------- 3.A Amended~~ and Restated Certificate of Incorporation as filed with the Delaware Secretary of State on May 23, 2003 (Exhibit 3.1 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). 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. *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 7 3/4% Senior Notes due 2013. *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. 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 Services Agreement dated as of May 23, 2003, between El Paso Production Oil & Gas Company and El Paso Production Holding Company (Exhibit 10.3 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). +10.D El Paso Production Companies Long-Term Incentive Plan effective as of January 1, 2003 (Exhibit 10.AA to El Paso's 2003 First Quarter Form 10-Q). +10.D.1 Amendment No. 1 to the El Paso Production Companies Long-Term Incentive Plan effective as of June 6, 2003 (Exhibit 10.13 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). *+10.D.2 Amendment No. 2 to the El Paso Production Companies Long-Term Incentive Plan effective as of December 31, 2003. +10.E Termination of Employment Agreement between El Paso CGP Company and Rodney D. Erskine effective as of December 16, 2002 (Exhibit 10.17 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). 10.F 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.G 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).Wells

~~EXHIBIT~~ Our ~~NUMBER~~properties ~~DESCRIPTION~~are ~~--------~~separated ~~-----------~~into ~~10.H~~the ~~Intercompany State Income Tax Allocation and Payments Policy~~Onshore, ~~effective~~Texas ~~for~~Gulf ~~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.I Purchase~~ Coast and ~~Sale~~Gulf ~~Agreement~~of ~~(Red~~Mexico ~~River) by~~ and ~~among~~south ElLouisiana ~~Paso Production Company, El Paso Production GOM Inc~~regions. ~~and~~The ~~Lehman~~following tables ~~Commercial~~detail ~~Paper Inc., dated October 3, 2003~~ (~~Exhibit 10.21 to Amendment No. 2 to~~ i) our ~~Form~~interest ~~S-4~~in ~~filed~~developed ~~on November 24, 2003, Registration No. 333-106586). 10.J First Amendment to Purchase~~ and ~~Sale~~undeveloped acreage ~~Agreement~~at ~~by and among El Paso Production Company~~December 31, ~~El Paso Production GOM Inc. and Lehman Commercial Paper Inc.~~ 2005, ~~dated October 6, 2003~~ (~~Exhibit 10.22 to Amendment No. 2 to~~ ii) our ~~Form~~interest in ~~S-4~~natural ~~filed~~gas ~~on November 24, 2003, Registration No. 333-106586). 10.K Purchase~~ and ~~Sale~~oil ~~Agreement~~wells ~~(Red~~at ~~River) by and among El Paso Production Company~~December 31, 2005 ~~El Paso Production GOM Inc.~~ and ~~Ramshorn Investments, Inc., dated October 8, 2003~~ (~~Exhibit 10.23 to Amendment No. 2 to~~ iii) our ~~Form~~exploratory ~~S-4 filed on November 24, 2003, Registration No. 333-106586). 10.L Purchase Agreement dated as of May 20, 2003, between El Paso Production Holding Company, the Subsidiary Guarantors named therein~~ and ~~Credit~~development ~~Suisse~~wells ~~First~~drilled ~~Boston LLC, Citigroup Global Markets Inc., Banc of America Securities LLC, Deutsche Bank Securities Inc., Lehman Brothers Inc. and Scotia Capital (USA) Inc., (collectively,~~ during the ~~"Initial~~years ~~Purchasers") (Exhibit 1.1 to our Form S-4 filed on June 27,~~ 2003, ~~Registration~~through No2005. ~~333-106586).~~Any *21acreage ~~Subsidiaries~~in ofwhich Elour ~~Paso~~interest is ~~Production~~limited ~~Holding~~to ~~Company.~~owned *23.A Consent of Ryder Scott Company. *23.B Consent of Huddleston & Coroyalty, ~~Inc.~~overriding *31.Aroyalty ~~Certification~~and ofother similar ~~Chief~~interests ~~Executive~~is ~~Officer pursuant to sec~~excluded. 302 of the Sarbanes-Oxley Act of 2002. *31.B Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *32.A Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002. *32.B Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURE TITLE DATE --------- ----- ---- /s/ LISA A. STEWART President and Director September 30, 2004 ------------------------------------------------ (Principal Executive Officer) Lisa A. Stewart /s/ D. MARK LELAND Executive Vice President, September 30, 2004 ------------------------------------------------ Chief Financial Officer and D. Mark Leland Director (Principal Financial Officer) /s/ GENE T. WAGUESPACK Senior Vice President, September 30, 2004 ------------------------------------------------ Treasurer and Controller Gene T. Waguespack (Principal Accounting Officer)Acreage

EXHIBIT NUMBER DESCRIPTION -------- ----------- 3.A Amended and Restated Certificate of Incorporation as filed with the Delaware Secretary of State on May 23, 2003 (Exhibit 3.1 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). 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. *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 7 3/4% Senior Notes due 2013. *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. 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 Services Agreement dated as of May 23, 2003, between El Paso Production Oil & Gas Company and El Paso Production Holding Company (Exhibit 10.3 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). +10.D El Paso Production Companies Long-Term Incentive Plan effective as of January 1, 2003 (Exhibit 10.AA to El Paso's 2003 First Quarter Form 10-Q). +10.D.1 Amendment No. 1 to the El Paso Production Companies Long-Term Incentive Plan effective as of June 6, 2003 (Exhibit 10.13 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). *+10.D.2 Amendment No. 2 to the El Paso Production Companies Long-Term Incentive Plan effective as of December 31, 2003. +10.E Termination of Employment Agreement between El Paso CGP Company and Rodney D. Erskine effective as of December 16, 2002 (Exhibit 10.17 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586). 10.F 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.G 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).


		Developed				Undeveloped				Total

		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾

Onshore			867,392		518,892		1,591,543		1,216,552		2,458,935		1,735,444
Texas Gulf Coast			103,234		79,439		151,751		109,241		254,985		188,680
Gulf of Mexico and south Louisiana			530,464		362,938		540,972		494,481		1,071,436		857,419

	Total		1,501,090		961,269		2,284,266		1,820,274		3,785,356		2,781,543

~~EXHIBIT~~ Our ~~NUMBER~~net ~~DESCRIPTION~~developed ~~--------~~acreage ~~-----------~~is ~~10.H~~concentrated ~~Intercompany~~primarily ~~State~~in ~~Income~~the ~~Tax~~Gulf of ~~Allocation~~Mexico ~~and Payments Policy~~(38 percent), ~~effective~~Utah ~~for tax years beginning after January 29~~(12 percent), ~~2001~~ Texas (~~Exhibit~~ 10~~.20 to our Form S-4 filed on June 27~~ percent), ~~2003,~~Oklahoma ~~Registration No. 333-106586~~(9 percent)., ~~10.I Purchase and Sale Agreement~~ Alabama (~~Red River~~8 percent) ~~by and among El Paso Production Company~~, ElNew ~~Paso~~Mexico ~~Production~~(8 percent) ~~GOM Inc.~~ and ~~Lehman Commercial Paper Inc., dated October 3, 2003~~ Louisiana (~~Exhibit 10~~6 percent).21 toOur ~~Amendment~~net ~~No.~~undeveloped 2acreage tois ~~our~~concentrated primarily ~~Form~~in ~~S-4~~New ~~filed~~Mexico ~~on November 24~~(27 percent), ~~2003,~~the ~~Registration~~Gulf ~~No.~~of ~~333-106586~~Mexico (22 percent)~~. 10.J First Amendment to Purchase and Sale Agreement by and among El Paso Production Company~~, ElWyoming ~~Paso Production GOM Inc. and Lehman Commercial Paper Inc., dated October 6, 2003~~ (~~Exhibit~~ 10~~.22 to Amendment No. 2 to our Form S-4 filed on November 24~~ percent), ~~2003, Registration No. 333-106586). 10.K Purchase and Sale Agreement~~ Louisiana (~~Red River~~7 percent) ~~by and among El Paso Production Company~~, ElTexas ~~Paso Production GOM Inc. and Ramshorn Investments, Inc., dated October 8, 2003~~ (~~Exhibit 10.23 to Amendment No. 2 to our Form S-4 filed on November 24~~7 percent), ~~2003,~~West ~~Registration No. 333-106586~~Virginia (7 percent)~~. 10.L Purchase Agreement dated as of May 20~~, ~~2003,~~Indiana between El Paso Production Holding Company, the Subsidiary Guarantors named therein and Credit Suisse First Boston LLC, Citigroup Global Markets Inc., Banc of America Securities LLC, Deutsche Bank Securities Inc., Lehman Brothers Inc. and Scotia Capital (~~USA~~6 percent) ~~Inc.,~~and Alabama (~~collectively, the "Initial Purchasers"~~5 percent) ~~(Exhibit 1~~.1 toApproximately ~~our Form S-4 filed on June 27~~14 percent, ~~2003,~~13 percent and ~~Registration~~10 percent ~~No. 333-106586). *21 Subsidiaries~~ of Elour ~~Paso~~total ~~Production~~net ~~Holding~~undeveloped ~~Company.~~acreage *23.Ais ~~Consent~~held under ofleases ~~Ryder~~that ~~Scott~~have ~~Company.~~remaining *23.Bprimary ~~Consent~~terms ofexpiring ~~Huddleston~~in ~~& Co~~2006, 2007 ~~Inc.~~and *312008.A Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *31.B Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002. *32.A Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002. *32.B Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.


	Productive Wells


		Productive												Number of Wells
		Natural Gas				Productive Oil				Total Productive				Being Drilled at
		Wells				Wells				Wells				December 31, 2005

		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾⁽³⁾		Gross⁽¹⁾		Net⁽²⁾

Onshore			3,424		2,614		514		363		3,938		2,977		36		29
Texas Gulf Coast			831		702		—		—		831		702		—		—
Gulf of Mexico and south Louisiana			175		115		53		35		228		150		4		1

	Total		4,430		3,431		567		398		4,997		3,829		40		30


	Wells Drilled


		Net Exploratory						Net Development
		Wells Drilled⁽²⁾						Wells Drilled⁽²⁾

		2005		2004		2003		2005		2004		2003

Productive			86		13		54		279		298		272
Dry			2		10		22		4		3		1

	Total		88		23		76		283		301		273


⁽¹⁾	Gross interest reflects the total acreage or wells we participated in, regardless of our ownership interests in the acreage or wells.
⁽²⁾	Net interest is the aggregate of the fractional working interest that we have the gross acreage, gross wells, or gross drilled wells.
⁽³⁾	At December 31, 2005, we operated 3,541 of the 3,829 net productive wells.

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


	Net Production, Sales Prices, Transportation and Production Costs

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


			2005		2004		2003

Net Production Volumes
	Natural gas (MMcf)			206,714		238,009		338,762
	Oil, condensate and NGL (MBbls)			7,516		8,498		11,778
		Total (MMcfe)		251,807		288,994		409,432

Natural Gas Average Realized Sales Price ($/Mcf)⁽¹⁾
	Excluding hedges		$	7.92	$	6.02	$	5.51
	Including hedges⁽²⁾		$	5.33	$	5.09	$	4.57

Oil, Condensate, and NGL Average Realized Sales Price ($/Bbl)⁽¹⁾
	Excluding hedges		$	45.86	$	34.44	$	26.64
	Including hedges⁽²⁾		$	45.86	$	34.44	$	25.96

Average Transportation Costs
	Natural gas ($/Mcf)		$	0.20	$	0.17	$	0.18
	Oil, condensate and NGL ($/Bbl)		$	0.69	$	1.16	$	1.05

Average Production Costs ($/Mcfe)⁽³⁾
	Average lease operating costs		$	0.75	$	0.63	$	0.42
	Average production taxes			0.27		0.11		0.14

		Total production costs	$	1.02	$	0.74	$	0.56


⁽¹⁾	Prices are stated before transportation costs.
⁽²⁾	Our hedging activities are conducted with our affiliate, El Paso Marketing, L.P. (El Paso Marketing).
⁽³⁾	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).


	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:


			2005		2004		2003

			(In millions)
Acquisition Costs:
	Proved		$	643	$	33	$	10
	Unproved			143		32		35
Development Costs				503		395		668
Exploration Costs:
	Delay Rentals			3		7		6
	Seismic Acquisition and Reprocessing			7		29		56
	Drilling			133		149		405
Asset Retirement Obligations⁽¹⁾				1		30		124

		Total full cost pool expenditures		1,433		675		1,304
		Non-full cost pool expenditures		25		14		20

		Total cost incurred⁽²⁾	$	1,458	$	689	$	1,324

Acquisition of unconsolidated investment in Four Star⁽²⁾			$	769	$	—	$	—


⁽¹⁾	Includes an increase to our property, plant and equipment of approximately $113 million in 2003 associated with our adoption of Statement of Financial Accounting Standards No. 143.

⁽²⁾	Includes $179 million of additional cost associated with 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 $247 million in 2005, $156 million in 2004 and $220 million in 2003 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 natural gas and oil to third parties through El Paso Marketing at spot market prices, subject to customary adjustments. As part of our long-term business strategy, we will continue this practice. We sell our NGL at market prices under monthly or long-term contracts, subject to customary adjustments. We also engage in hedging activities with El Paso Marketing on a portion of our production to stabilize our cash flows and to reduce the risk of downward commodity price movements on sales of our production. As of December 31, 2005, we had hedged approximately 85,000 BBtu of our anticipated natural gas production in 2006 and approximately 26,000 BBtu of our anticipated natural gas production during 2007 through 2012. For a further discussion of the prices at which we have hedged our natural gas production, 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. 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, environmental and safety regulations in the jurisdictions in which we operate.

Our 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. These 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, and is incorporated herein by reference.

Employees

As of March 3, 2006 we had approximately 870 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. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and in good faith, assumed facts or bases almost always vary from the actual results, and differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, 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 statement of expectation or belief will result 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.

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;

	•	commodity processing, gathering and transportation availability;

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

	•	the availability of pipeline capacity;

	•	weather conditions;

	•	market uncertainty;

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

	•	worldwide economic conditions; and

	•	decreased demand for the use of natural gas and oil because of 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, 2005 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. Changes in natural gas and oil prices can have a significant impact on the calculation of our full cost ceiling test. A significant decline in natural gas and oil prices could result in a downward revision of our reserves and a 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 may use 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 El Paso Marketing. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:


	•	expected production is less than the amount hedged;

	•	the counterparty to the hedging contract defaults on its contractual obligations; or

	•	there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

Our hedging arrangements may also 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 gas marketing and hedging services and we 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 difficult.*

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 non-producing reserves and proved developed reserves that are early in their production life. As a result, our reserve estimates are inherently imprecise. Also, the use of a 10 percent discount factor for estimating the value of our reserves, as prescribed by the SEC, 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, eventually resulting 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, 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 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;

	•	increased competition in the search for and acquisition of reserves;

	•	significant increases in future drilling, production and development costs, including drilling rig rates and oil field services costs;

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

	•	increased federal or state regulations, including environmental regulations, that limit or restrict the ability to drill natural gas or oil wells, reduce operational flexibility, or increase capital and operating costs;

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

	•	the availability of alternative sources of energy;

	•	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 reserves.*

The natural gas and oil business is highly competitive in the search for and acquisition of reserves. We must identify and precisely locate prospective geologic structures, drill and successfully complete wells in those structures in a timely manner. Our ability to expand our leased land positions in desirable areas is impacted by intensely competitive leasing conditions. Competition for reserves and producing natural gas and oil properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us. Our competitors include the major and independent natural gas and oil companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. If we are unable to compete effectively in the acquisition and development of reserves, our future profitability may be negatively

impacted. Ultimately, our future success in the production business is dependent on our ability to 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. Each of these risks could result in damage to property, injuries to people or the shut in of existing production as damaged energy infrastructure is repaired or replaced.

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 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;

	•	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 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, future natural gas and oil prices, operating costs 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. Normally, we 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.

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, for 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 and transportation 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 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. It is not possible for us to estimate exactly the amount and timing of all future expenditures related to environmental matters because of:


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

	•	the discovery of new sites or additional information at existing sites;

	•	the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties (PRP’s); and

	•	the nature of environmental laws and regulations, including the interpretation and enforcement thereof.

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.

Our current environmental liabilities and related reserves are immaterial. However, we could be required to set aside additional amounts due to these uncertainties which could significantly impact our future consolidated results of operations, cash flows or financial position. For additional information concerning our environmental matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

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 of 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.

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 Caa1 by Moody’s Investor Service and B- by Standard & Poor’s. The ratings assigned to our senior unsecured indebtedness are currently rated B3 by Moody’s Investor Service and B by Standard & Poor’s. 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 10.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


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.

Environmental Proceedings

Air Permit Violation. In March 2003, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order and Notice of Potential Penalty to our subsidiary, El Paso Production Company, alleging that it failed to timely obtain air permits for specified oil and natural gas facilities. El Paso Production Company requested an adjudicatory hearing on the matter. Pursuant to discussions with LDEQ, we have reached an agreement to resolve the allegations for $77,287. We signed the settlement agreement on November 28, 2005, and LDEQ executed the settlement agreement on March 8, 2006. We will pay the penalty in the first quarter of 2006.


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.

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, 2004 and 2003 we declared dividends to El Paso of $199 million, $138 million and $2.3 billion, which included, $16 million, $81 million and $210 million of non-cash dividends in 2005, 2004 and 2003.


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 8.

On December 31, 2005, El Paso made a capital contribution to us of several exploration and production companies. 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

Our business consists of natural gas and oil exploration and production activities. Our operating results are driven by a variety of factors, including the ability to locate and develop economic natural gas and oil reserves, extract those reserves with minimal production costs, sell the products at attractive prices and minimize our total administrative costs.

We manage this business with the goal to create value through disciplined capital allocation, cost control, and portfolio management. Our 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 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 high-return investments. During the past two years, we have dedicated substantial resources and management effort to stabilizing and improving our business. We believe this effort has been largely successful. Our efforts have been focused on the following:


Goal or Strategy	Actions Taken	Results

Improve capital discipline and returns	Created a standard economic measure known as PVR (present value ratio) to evaluate project success. This ratio represents the present value of future after-tax cash flows discounted at 12% over total investment. Our target ratio is 1.15 which simply means that every $1.00 invested returns $1.15 on an after-tax discounted basis over the life of the project. A rigorous post-spending analysis is prepared and a monthly scorecard for each operating region is evaluated by management.	Our 2005 actual post-drill PVR was 1.19 using a $4.75/MMBtu plan price compared to our pre-drill PVR target of 1.23. Our post drill PVR was 2.11 using 2005 realized prices with the year-end strip prices thereafter.
Improve portfolio management	Allocated a greater percentage of capital expenditures to onshore exploration and development opportunities. Acquired Medicine Bow to expand our presence in the Rockies and east Texas and GMT Energy Corporation (GMT) to expand our presence in east Texas. Divested certain high cost offshore and onshore properties with high abandonment liabilities and only 25 Bcfe of proved reserves. Implemented a consistent risk analysis process and reduced capital exposure to deep drilling. Utilized comprehensive mapping with life-of-property exploitation plans.	Our Onshore region reserves increased from 61 percent of our total reserves at year end 2004 to 67 percent of our total reserves at year end 2005. Our unconventional coal seam reserves comprise approximately one third of our total reserve base. These longer-life reserves form a stable production base and should make our business more predictable. The Medicine Bow acquisition accelerated the changes in our portfolio since over 80 percent of the proved reserves overlap with our core onshore areas.
Improve our production mix	Increased our onshore production through drilling activities and our acquisition program, including the acquisition of our equity investment in Four Star.	From 2004 to 2005, total onshore production grew as a percentage of total production. A substantial portion of the increase was organic growth as opposed to acquisitions.


Goal or Strategy	Actions Taken	Results

Grow our reserves base	Created a balanced acquisition and drilling program that focused on increasing long life reserves while converting proved undeveloped reserves (PUD) to producing developed reserves.	During 2005, we produced 252 Bcfe (excluding our equity share of Four Star production of 9 Bcfe) while our drilling and acquisition programs generated net additions of 450 Bcfe (excluding our equity share of Four Star of 262 Bcfe). We also increased our reserves over production ratio from 6.8 years to 8.6 years. In 2005, we developed 29 percent of our total 2004 year-end PUD reserves.
Build an inventory of attractive lower risk drilling prospects	Improved our ability to grow by creating a regional structure that leverages a strong acreage position in key producing basins. Utilized detailed mapping and reservoir analysis and a standardized risk measurement system to identify drilling and workover or recompletion opportunities. Completed $1.1 billion of acquisitions that complement our existing core operations.	Identified 620 wells to be drilled in 2006 with 2,590 more in future years at a $5.50/MMBtu price forecast for natural gas that generates a PVR of 1.15 or greater. Created a balanced inventory along the entire risk spectrum with low risk development prospects coupled with high potential offshore exploration opportunities.

Significant Operational Factors Affecting the Year Ended December 31, 2005


	•	Higher realized prices. We benefited from a strong commodity pricing environment in 2005. Realized natural gas prices, which include the impact of our hedges, increased 5 percent while oil, condensate and NGL prices increased 33 percent compared to 2004.

	•	Average daily production of 690 MMcfe/d (excluding 24 MMcfe/d from our equity investment in Four Star). Our average daily equivalent production decreased from 2004 primarily due to several hurricanes in the Gulf of Mexico, which caused us to shut in significant volumes in our Gulf of Mexico and south Louisiana region. We have continued to increase production volumes in our Onshore region as a result of our successful drilling and acquisition programs. However, production volumes in our Gulf of Mexico and south Louisiana region, adjusted for the impact of hurricanes, and Texas Gulf Coast region continued to gradually decrease as drilling programs and overall lower capital spending in those areas have not been sufficient to offset the historically steep production decline rates in these regions.

	•	Impact of hurricanes on production volumes. The Gulf Coast hurricanes negatively impacted our annual production by approximately 12 Bcfe or 34 MMcfe/d during 2005. Prior to Hurricane Katrina in late August 2005, our production from the Gulf of Mexico was about 205 MMcfe/d. A substantial portion of our shut-in production from Hurricane Katrina was brought back online during September 2005 to a level of about 170 MMcfe/d just prior to Hurricane Rita. We continue to experience substantial shut-in volumes from Hurricane Rita; however Gulf of Mexico production levels have returned to approximately 130 MMcfe/d at December 31, 2005 and currently remain at that level. We expect the majority of the remaining operated Gulf of Mexico production to come back online during the first half of 2006. Also impacted were our onshore Texas Gulf Coast and Arklatex areas, where damage from Hurricane Rita initially impacted approximately 60 MMcfe/d of production. However, production was restored within a few days of the event.

	•	Drilling results. In 2005, we participated in drilling a total of 483 gross wells with a 99 percent success rate and a PVR of 1.19 based on a plan price of $4.75/MMBtu. Our drilling results by region were as follows:


	•	Onshore region. We experienced a 99 percent success rate on 454 gross wells drilled during 2005, resulting in production growth in the Rockies, Raton, north Louisiana and Arkoma operating areas.


	•	Texas Gulf Coast region. We experienced significant improvement in the second half of the year achieving a 89 percent success rate on 18 gross wells drilled during 2005. New Wilcox production was established from exploration at the Renger Field in Lavaca County, Texas. In addition, the shallow Vicksburg development program in Starr and Hidalgo Counties, Texas provided consistent results adding production on existing base properties.

	•	Gulf of Mexico and south Louisiana region. Overall, we experienced a 73 percent success rate on 11 gross wells drilled during 2005. During the year, we announced our participation in two deep shelf discovery wells at West Cameron Blocks 75 and 62 in the Gulf of Mexico. These projects are expected to come on line during the first quarter of 2006 and produce 20 MMcfe/d or higher, net to our interest. We also participated in a third discovery in 2005 through a 25 percent working interest in a well drilled at Long Point in Vermillion Parish, Louisiana, which tested at over 40 MMcfe/d and is expected to come on line during the second quarter 2006.

Outlook for 2006

For 2006, we also expect:


	•	Capital expenditures of approximately $900 million excluding acquisitions;

	•	Average daily production volumes for the year of approximately 730 MMcfe/d to 755 MMcfe/d, which excludes approximately 70 MMcfe/d from our equity interest in Four Star;

	•	Average cash operating costs of approximately $1.67/Mcfe to $1.74/Mcfe for the year;

	•	Unit of production depletion rate of $2.32/Mcfe in the first quarter of 2006. This compares to $2.27/Mcfe in the fourth quarter of 2005. The increase is expected due to higher finding and development costs and the costs of acquired reserves and;

	•	Significant industry-wide increases in drilling and oilfield service costs that will require constant monitoring of capital spending programs and a mitigation effort designed to manage and improve field efficiency.

Production Hedge Position

As part of our overall strategy, we hedge our natural gas and oil production to stabilize cash flows, reduce the risk of downward commodity price movements on our sales and to protect the economic assumptions associated with our capital investment programs. We have historically engaged in hedging activities with El Paso Marketing, primarily through natural gas and oil swaps. Because only a portion of our expected production is hedged, this strategy only partially reduces our exposure to downward movements in commodity prices. As a result, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period.

During 2005, we experienced a significant decrease in the fair value of our hedging derivatives. These fair value decreases were generally deferred in our accumulated other comprehensive income and will be recognized in our income at the time the production volumes to which they relate are sold. As of December 31, 2005, the fair value of our hedging derivative positions was a liability of $732 million. The deferred amount in accumulated other comprehensive income will be recognized in income upon the settlement of our derivative commodity instruments, but will be substantially offset by the impact of the corresponding change in the price to be received when the hedged natural gas production is sold. This will result in a realized price that is approximately equal to the hedge price if settled as originally anticipated.

comprehensive income that will be recognized in earnings as our original hedged transactions settle through 2006. In conjunction with these transactions, we entered into a service agreement with El Paso that provides for a reimbursement of 2.5 cents per MMBtu for our expected administrative costs associated with these transactions.

Natural Gas

Below are the hedging positions on our anticipated natural gas production as of December 31, 2005:


	Quarter Ended

	March 31				June 30				September 30				December 31				Total

	Volume		Hedged Price		Volume		Hedged Price		Volume		Hedged Price		Volume		Hedged Price		Volume		Hedged Price
	(BBtu)		(per MMBtu)		(BBtu)		(per MMBtu)		(BBtu)		(per MMBtu)		(BBtu)		(per MMBtu)		(BBtu)		(per MMBtu)

2006		21,349	$	3.32		21,367	$	3.32		21,385	$	3.33		21,385	$	3.33		85,486	$	3.32
2007		1,579	$	3.79		1,447	$	3.64		1,155	$	3.35		1,155	$	3.35		5,336	$	3.56
2008		1,142	$	3.35		1,142	$	3.35		1,155	$	3.49		1,155	$	3.49		4,594	$	3.42
2009 through 2012																		16,026	$	3.74

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. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, such as the cumulative effect of accounting changes, (ii) income taxes and (iii) interest, which includes interest expense and affiliated interest expense. Our business consists of consolidated operations as well as investments in unconsolidated affiliates. We exclude interest from this measure so that our investors may evaluate our operating results independently from our financing methods or capital structure. We believe the discussion of our results of operations based on EBIT is useful to our investors because it allows them to more effectively evaluate the operating performance of both our consolidated business and our unconsolidated investments using the same performance measure analyzed internally by our management. 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:


		2005			2004

		(In millions)
Operating revenues		$	1,489		$	1,527
Operating expenses			(1,101	)		(1,026	)

	Operating income		388			501
Other income, net			24			1

	EBIT		412			502
Affiliated interest expense			(60	)		(28	)
Interest expense			(88	)		(76	)
Income taxes			(90	)		(144	)

Net income		$	174		$	254

Operating Results

Below are our operating results and an analysis of these results for the years ended December 31:


			2005			2004

			(In millions, except
			volumes and prices)
Operating revenues:
	Natural gas		$	1,102		$	1,211
	Oil, condensate and NGL			345			293
	Other			42			23

		Total operating revenues		1,489			1,527
Transportation and net product costs⁽¹⁾				(62	)		(60	)

	Total operating margin			1,427			1,467
Operating expenses:
	Depreciation, depletion and amortization			(598	)		(568	)
	Production costs⁽²⁾			(256	)		(215	)
	General and administrative expenses			(176	)		(161	)
	Other			(9	)		(22	)

		Total operating expenses⁽¹⁾		(1,039	)		(966	)

	Operating income			388			501
	Other income⁽³⁾			24			1

EBIT			$	412		$	502


								Percent
				2005		2004		Variance

Consolidated volumes, prices and costs per unit:
	Natural gas
		Volumes (MMcf)			206,714		238,009		(13	)%
		Average realized prices including hedges ($/Mcf)⁽⁴⁾		$	5.33	$	5.09		5	%
		Average realized prices excluding hedges ($/Mcf)⁽⁴⁾		$	7.92	$	6.02		32	%
		Average transportation costs ($/Mcf)		$	0.20	$	0.17		18	%
	Oil, condensate and NGL
		Volumes (MBbls)			7,516		8,498		(12	)%
		Average realized prices ($/Bbl)⁽⁴⁾		$	45.86	$	34.44		33	%
		Average transportation costs ($/Bbl)		$	0.69	$	1.16		(41	)%
	Total equivalent volumes (MMcfe)				251,807		288,994		(13	)%
	Production costs ($/Mcfe)
		Average lease operating costs		$	0.75	$	0.63		19	%
		Average production taxes			0.27		0.11		145	%

			Total production costs⁽²⁾	$	1.02	$	0.74		38	%

	Average general and administrative expenses ($/Mcfe)			$	0.70	$	0.56		25	%
	Unit of production depletion cost ($/Mcfe)			$	2.20	$	1.81		22	%
Unconsolidated affiliate volumes (Four Star)⁽³⁾
	Natural Gas (MMcf)				6,689
	Oil, condensate and NGL (MBbls)				359
	Total equivalent volumes (MMcfe)				8,844


⁽¹⁾	Transportation and net product costs are included in operating expenses on our consolidated statements of income.
⁽²⁾	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).
⁽³⁾	Includes equity earnings and/or volumes for our investment in Four Star. Our equity interest in Four Star was acquired in connection with our acquisition of Medicine Bow in August 2005.
⁽⁴⁾	Prices are stated before transportation costs.


	Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Our EBIT for 2005 decreased $90 million as compared to 2004. The table below lists the significant drivers of the variance in our operating results in 2005 as compared to 2004:


			Variance

			Operating			Operating
			Revenue			Expense			Other			EBIT

			Favorable/(Unfavorable)
			(In millions)
Natural Gas Revenue
	Higher prices in 2005		$	394		$	—		$	—		$	394
	Impact of hedges			(315	)		—			—			(315	)
	Lower volumes in 2005			(188	)		—			—			(188	)
Oil, Condensate and NGL Revenue
	Higher realized prices in 2005			86			—			—			86
	Lower production volumes in 2005			(34	)		—			—			(34	)
Depreciation, Depletion and Amortization Expense
	Higher depletion rate in 2005			—			(99	)		—			(99	)
	Lower production volumes in 2005			—			67			—			67
Production Costs
	Higher lease operating costs in 2005			—			(8	)		—			(8	)
	Higher production taxes in 2005			—			(33	)		—			(33	)
General and administrative expenses				—			(15	)		—			(15	)
Other
	Earnings from investment in Four Star			—			—			19			19
	Other			19			15			2	⁽¹⁾		36

		Total Variances	$	(38	)	$	(73	)	$	21		$	(90	)


⁽¹⁾	Consists primarily of changes in transportation costs and other income.


	Operating Revenues

During 2005, we continued to benefit from a strong commodity pricing environment for natural gas and oil, condensate and NGL. However, losses in our hedging program for the year ended December 31, 2005 were $535 million compared to $220 million for the same period in 2004. Additionally, we experienced a 13 percent decrease in production volumes versus the same period in 2004. Although our production volumes benefited from the acquisitions in 2005, our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions experienced declines in year over year production due to normal declines and a lower capital spending program in these areas over the last several years. In addition, the Gulf of Mexico and south Louisiana region was impacted by the hurricanes discussed previously, while the Texas Gulf Coast region was impacted by mechanical well failures. In addition to these factors, our other operating revenues increased primarily due to a year-over-year increase in revenues from processing plants which are reflected in our results due to the contribution of these facilities to us by El Paso.


	Operating Expenses

Depreciation, depletion, and amortization expense. During 2005, we experienced higher depletion rates compared to 2004 as a result of higher finding and development costs and the cost of acquired reserves which resulted in higher depreciation, depletion and amortization expense. However, during 2005, the impact of lower production volumes discussed above partially offset the impact of our higher depletion rates.

Production costs. We continued to experience higher costs in 2005 due to the implementation of programs in the first half of 2005 to improve production in the Texas Gulf Coast and Gulf of Mexico and south Louisiana regions, higher salt water disposal costs, utility expenses, and marine transportation costs.

Production taxes were also higher as the result of higher commodity prices in 2005 and higher tax credits taken in 2004 on high cost natural gas wells.

General and administrative expenses. Our general and administrative expenses were higher in 2005 than in 2004, primarily due to an increase in payroll related benefits for our employees and higher legal and insurance costs.

Other. Other operating expenses decreased primarily due to employee severance expenses of $3 million in 2005 compared to $13 million in 2004.

Other Income

Other income increased in 2005 due to our acquisition of a 43.1 percent interest in Four Star in conjunction with our Medicine Bow acquisition in August 2005.

Affiliated Interest Expense

Affiliated interest expense for the twelve months ended December 31, 2005, was $32 million higher than the same period in 2004 due primarily to higher short-term interest rates in 2005. The average advance balance for the twelve months of 2005 increased to $1.3 billion from $1.2 billion in 2004. The average short-term interest rates for the twelve month period increased to 4.2% in 2005 from 2.4% in 2004. For a discussion of the cash management program, see Item 8, Financial Statements and Supplementary Data, Note 10.

Interest Expense

Interest expense for the year ended December 31, 2005 increased $12 million compared to 2004 due primarily to entering into our $500 million revolving credit facility in August 2005 in conjunction with our Medicine Bow acquisition.

Income Taxes


	Year Ended
	December 31,

	2005			2004

	(In millions,
	except for rates)
Income taxes	$	90		$	144
Effective tax rate		34	%		36	%

Our effective tax rates for each period differed from the federal statutory rate of 35 percent. See Part II, Item 8, Financial Statements and Supplementary Data, Note 3, for a reconciliation of the statutory rate to the effective rates.

Liquidity

Our primary sources of liquidity are cash generated from operations, advances from El Paso through its cash management program, our $500 million revolving credit facility (see Part II, Item 8, Financial Statements and Supplementary Data, Note 6) and capital contributions from El Paso. 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. Borrowings from El Paso under the cash management program are reflected as financing activities and advances to El Paso are reflected as investing activities in our statement of cash flows. As of December 31, 2005 and December 31, 2004, we had borrowed $125 million and $975 million from El Paso which is classified as a current note payable to affiliate on our balance sheet. At the end of 2005, El Paso made a non-cash contribution of approximately $1.3 billion to us in conjunction with our reorganization which reduced our affiliated payables under the cash management program.

In August 2005, we utilized cash on hand, advances from El Paso under the cash management program of $257 million, a $41 million capital contribution from El Paso and proceeds of $495 million, net of issuance costs from a new $500 million revolving credit facility (see further discussion in Part II, Item 8, Financial Statements, Note 6) to fund our Medicine Bow acquisition.

El Paso has stated its intent to provide us funds to repay amounts borrowed under our $500 million revolving credit facility in connection with the Medicine Bow acquisition through an issuance of El Paso common equity but is under no obligation to do so. If these amounts are repaid, the credit facility will be available to us to fund acquisitions or for other general corporate purposes. Based on our expected capital spending program, and forecasted operating cash flow using current projections of amounts of hedged production and commodity price levels, El Paso may be required to fund a portion of our capital expenditures, working capital and debt service needs through the cash management program.

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.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2005, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. Based on our assessment of those standards, we do not believe there are any that could have a material impact on us.


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 approved by the Audit Committee of El Paso’s Board of Directors. This Committee operates independently from us.

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, 2005	$	(732	)	$	(833	)	$	(101	)	$	(631	)	$	101
December 31, 2004	$	(482	)	$	(619	)	$	(137	)	$	(345	)	$	137

Currently, we hedge our natural gas production with El Paso Marketing. As a result, we are not required to provide collateral for our derivative positions.

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, 2005								December 31, 2004

	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	$	1,257	$	1,200	$	1,262
Long-term debt — average variable rate of 6.14%	$	500		—	$	500	$	500	$	—	$	—

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

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


			Page

Report of Independent Registered Public Accounting Firm				26
Consolidated Statements of Income				27
Consolidated Balance Sheets				28
Consolidated Statements of Cash Flows				29
Consolidated Statements of Stockholder’s Equity				30
Consolidated Statements of Comprehensive Income				31
Notes to Consolidated Financial Statements				32
	1. Basis of Presentation and Summary of Significant Accounting Policies			32
	2. Acquisitions and Divestitures			36
	3. Income Taxes			37
	4. Financial Instruments and Price Risk Management Activities			38
	5. Property, Plant and Equipment			40
	6. Debt and Available Credit Facilities			40
	7. Commitments and Contingencies			41
	8. Retirement Benefits			43
	9. Supplemental Cash Flow Information			43
	10. Investments in and Earnings from Unconsolidated Affiliates and Related Party Transactions			43
Supplemental Financial Information
		Supplemental Selected Quarterly Financial Information (Unaudited)		46
		Supplemental Natural Gas and Oil Operations (Unaudited)		46
Financial Statement Schedule
		Schedule II — Valuation and Qualifying Accounts		51

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 financial statements listed in the Index appearing under Item 15(a)1 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 2004, and the results of their operations and their cash flows for each of the three 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 listed in the Index appearing under Item 15(a)2 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 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, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003.

As discussed in Note 1 to the consolidated financial statements, on December 31, 2005 El Paso Corporation contributed the domestic exploration and production businesses owned by one of El Paso Corporation’s subsidiaries to El Paso Exploration & Production Company. The contribution was 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/ PricewaterhouseCoopers LLP

Houston, Texas

March 15, 2006

EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)


			Year Ended December 31,

			2005			2004			2003

Operating revenues
	Natural gas and oil sales
		Third parties	$	708		$	551		$	242
		Affiliates		739			953			1,612
	Other			42			23			10

				1,489			1,527			1,864
Operating expenses
	Cost of sales			62			60			87
	Operation and maintenance			368			365			345
	Depreciation, depletion and amortization			598			568			629
	Taxes, other than income taxes			73			33			63

				1,101			1,026			1,124

Operating income				388			501			740
Earnings from unconsolidated affiliates				19			—			5
Other income				5			1			4
Affiliated interest expense				(60	)		(28	)		(61	)
Interest expense				(88	)		(76	)		(42	)

Income before income taxes				264			398			646
Income taxes				(90	)		(144	)		(244	)

Income before cumulative effect of accounting change				174			254			402
Cumulative effect of accounting change, net of income taxes				—			—			(7	)

Net income			$	174		$	254		$	395

See accompanying notes.

EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)


				December 31,			December 31,
				2005			2004

ASSETS
Current assets
	Cash and cash equivalents			$	46		$	127
	Accounts receivable
		Customer, net of allowance of $10 in 2005 and $12 in 2004			53			50
		Affiliates			355			178
		Other			81			60
	Deferred income taxes				221			94
	Other				69			35

			Total current assets		825			544

Property, plant and equipment, at cost
	Natural gas and oil properties
		Proved properties-full cost method			14,762			14,075
		Unevaluated costs excluded from amortization			384			308
	Other				141			162

					15,287			14,545
	Less accumulated depreciation, depletion and amortization				10,809			10,887

			Total property, plant and equipment, net		4,478			3,658

Other assets
	Investments in unconsolidated affiliates				761			6
	Deferred income taxes				38			217
	Other				30			60

					829			283

			Total assets	$	6,132		$	4,485


LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
	Accounts payable
		Trade		$	97		$	84
		Affiliates			32			2
		Other			167			145
	Notes payable to affiliate				125			975
	Liabilities from price risk management activities				621			210
	Other				73			62

			Total current liabilities		1,115			1,478

Long-term debt					1,700			1,200

Other
	Liabilities from price risk management activities				111			272
	Deferred income taxes				305			6
	Asset retirement obligation				158			227
	Other				53			25

					627			530

Commitments and contingencies
Stockholder’s equity
	Common stock, par value $1 per share; 1,000 shares authorized and outstanding				—			—
	Additional paid-in capital				3,410			1,993
	Retained earnings				(276	)		(450	)
	Accumulated other comprehensive loss				(444	)		(266	)

			Total stockholder’s equity		2,690			1,277

			Total liabilities and stockholder’s equity	$	6,132		$	4,485

See accompanying notes.

EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


					Year Ended December 31,

					2005			2004			2003

Cash flows from operating activities
	Net income				$	174		$	254		$	395
	Adjustments to reconcile net income to net cash from operating activities
		Depreciation, depletion and amortization				598			568			629
		Cumulative effect of accounting change				—			—			7
		Deferred income tax expense (benefit)				94			166			(107	)
		Earnings from unconsolidated affiliates, adjusted for cash distributions				15			—			—
		Other non-cash items				—			8			5
		Asset and liability changes
			Accounts receivable			(179	)		(23	)		138
			Accounts payable			30			(15	)		(37	)
			Affiliate income taxes			(9	)		(190	)		380
			Other asset changes			14			(18	)		—
			Other liability changes			(65	)		(52	)		35

				Net cash provided by operating activities		672			698			1,445

Cash flows from investing activities
	Capital expenditures					(800	)		(677	)		(1,335	)
	Net proceeds from the sale of assets					10			(9	)		654
	Cash paid for acquisitions, net of cash acquired					(1,025	)		—			—
	Change in note receivable from affiliate					—			215			93
	Change in restricted cash					—			—			44

				Net cash used in investing activities		(1,815	)		(471	)		(544	)

Cash flows from financing activities
	Net proceeds from the issuance of long-term debt					495			—			1,169
	Dividends to parent					(183	)		(57	)		(2,098	)
	Contributions from parent					263			145			—
	Change in note payable with affiliate					487			(230	)		(88	)

				Net cash provided by (used in) financing activities		1,062			(142	)		(1,017	)

Change in cash and cash equivalents						(81	)		85			(116	)
Cash and cash equivalents
	Beginning of period					127			42			158

	End of period				$	46		$	127		$	42

See accompanying notes.

EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In millions, except share amounts)


			For the Years Ended December 31,

			2005					2004					2003

			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					1,993					1,940					3,227
	Contribution from parent					1,616					190					1,026
	Allocated tax benefit (expense) of equity plans					—					1					(5	)
	Dividends to parent					(199	)				(138	)				(2,308	)

		Balance at end of year				3,410					1,993					1,940

Retained earnings (deficit):
	Balance at beginning of year					(450	)				(704	)				(1,099	)
	Net income					174					254					395

		Balance at end of year				(276	)				(450	)				(704	)

Accumulated other comprehensive loss:
	Balance at beginning of year					(266	)				(241	)				(222	)
	Other comprehensive loss					(178	)				(25	)				(19	)

		Balance at end of year				(444	)				(266	)				(241	)

Total stockholder’s equity				1,000	$	2,690			1,000	$	1,277			1,000	$	995

See accompanying notes.

EL PASO EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)


			Year Ended December 31,

			2005			2004			2003

Net income			$	174		$	254		$	395

Net gains (losses) from cash flow hedging activities:
	Unrealized mark-to-market losses arising during period (net of income taxes of $275, $100 and $132 in 2005, 2004 and 2003)			(483	)		(173	)		(230	)
	Reclassification adjustments for changes in initial value to settlement date (net of income taxes of $176, $85 and $121 in 2005, 2004 and 2003)			305			148			211

		Other comprehensive loss		(178	)		(25	)		(19	)

Comprehensive income (loss)			$	(4	)	$	229		$	376

See accompanying notes.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Basis of Presentation and Summary of Significant Accounting Policies


	Basis of Presentation

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. The contribution was part of El Paso’s ongoing simplification of its business structure which included combining its domestic exploration and production activities under one reporting entity. We accounted for this contribution 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. Concurrent with this contribution, we also changed our name from El Paso Production Holding Company to El Paso Exploration & Production Company.

The domestic 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 and were combined with our historical properties to form a single combined full cost pool. Accordingly, we have reflected the impact of combining these properties into one 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 10 for the effect of these dividends on total stockholder’s equity).

Our consolidated financial statements include the accounts of all majority-owned and controlled subsidiaries after the elimination of all significant intercompany accounts and transactions.


	Principles of Consolidation

We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of an 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 whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control, the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. We use the cost method of accounting where we are unable to exert significant influence over the entity.


	Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.


	Allowance for Doubtful Accounts

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.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	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. 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 in our ceiling test calculations 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. Specifically, we transfer costs to the amortizable base when properties are determined to have proved reserves. In addition, 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 using end of period spot prices discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, net of related income tax effects. If the ceiling is not greater than or equal to the total capitalized costs, we are required to write-down our capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. 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 15 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 the passage of title using the sales method, net of any royalty interests or other profit interests in the produced product. 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

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 separately from our liability any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties including insurance coverage. When recovery is assured after an evaluation of their creditworthiness or solvency, 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 an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.


	Price Risk Management Activities

We engage in hedging activities on our natural gas and oil production to obtain more determinable cash flows and to mitigate the risk of downward price movements on sales of these commodities. We do this through swaps with El Paso Marketing. Our derivatives are designated as accounting hedges and impact our revenues or expenses based on the timing of the transactions that they hedge and are reflected in our balance sheet at their fair value as assets and liabilities from price risk management activities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date (see Note 4). Cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows, and any receivables and payables resulting from these settlements are reported as affiliate receivables or payables on our balance sheet.


	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.

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

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which requires that we record a liability for retirement and removal costs of long-lived assets used in our business when the timing and/or amount of the settlement of those costs are relatively certain. On December 31, 2005, we adopted the provisions of FASB Financial Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, which requires that we record a liability for those retirement and removal costs in which the timing and/or amount of the settlement of the costs are uncertain. The adoption of FIN No. 47 had no impact on us.

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. These obligations include those where we have plans to or otherwise will be legally required to replace, remove or retire the associated 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 remaining 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. In the first quarter of 2003, we recorded a charge as a cumulative effect of accounting change, net of income taxes of $4 million, of approximately $7 million related to our adoption of SFAS No. 143.

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, a projected inflation rate of 2.5 percent and the estimated timing and amount of settling our obligations, which are based on internal models and external quotes.

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 year ended December 31, were as follows:


	2005			2004

	(In millions)
Net asset retirement liability at January 1,	$	254		$	212
Liabilities settled⁽¹⁾		(87	)		(33	)
Accretion expense		26			23
Liabilities incurred		9			23
Changes in estimate		(12	)		29

Net asset retirement liability at December 31,	$	190		$	254


⁽¹⁾	Increase is due primarily to the sale of natural gas and oil properties.

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.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


2.	Acquisitions and Divestitures


	Acquisitions

In August 2005, we completed the acquisition of Medicine Bow, a privately held energy company, for total cash consideration of approximately $853 million. 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 are reflected as earnings from unconsolidated affiliates in our financial statements (see Note 10).

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 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	$	1,528	$	1,577
Net income		184		243


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

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

In 2003, we sold natural gas and oil properties located in Oklahoma, Texas, New Mexico, Louisiana and offshore Gulf of Mexico for approximately $673 million and we did not recognize a gain or loss on the reserves sold. We completed these sales as part of El Paso’s plan to improve its liquidity and respond to changing market conditions.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


3.	Income Taxes

Income Tax Expense. The following table reflects the components of income taxes included in income before cumulative effect of accounting change for each of the three years ended December 31:


			2005			2004			2003

			(In millions)
Current
	Federal		$	(6	)	$	(23	)	$	308
	State			2			1			43

				(4	)		(22	)		351

Deferred
	Federal			72			157			(89	)
	State			22			9			(18	)

				94			166			(107	)

		Total income tax expense	$	90		$	144		$	244

Effective Tax Rate Reconciliation. Our income taxes, included in income before cumulative effect of accounting change, 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:


		2005			2004			2003

		(In millions, except rates)
Income tax expense at the statutory federal rate of 35%		$	92		$	139		$	226
Increase (decrease)
	State income tax, net of federal income tax benefit		16			6			16
	Earnings from unconsolidated affiliates where we anticipate receiving dividends		(11	)		—			—
	Other		(7	)		(1	)		2

Income tax expense		$	90		$	144		$	244

Effective tax rate			34	%		36	%		38	%

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


			2005			2004

			(In millions)
Deferred tax liabilities
	Property, plant and equipment		$	276		$	15
	Employee benefits			27			39
	Investment in unconsolidated subsidiaries			214			—
	Other			60			59

		Total deferred tax liability	$	577		$	113

Deferred tax assets
	Net operating loss and tax credit carryforwards		$	245		$	208
	Price risk management activities			274			184
	Other			12			24

		Total deferred tax asset	$	531		$	416

Net deferred tax asset (liability)			$	(46	)	$	303

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, 2005:


	Amount		Expiration Year

	(In millions)
U.S. federal net operating loss	$	550		2009-2024
State net operating loss	$	320		2007-2023

We also have alternative minimum tax carryforwards of approximately $25 million, which are carried forward indefinitely and capital loss carryforwards of $9 million for which the carryover period will end in 2008. 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.


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:


	2005						2004

	Carrying			Fair			Carrying
	Amount			Value			Amount			Fair Value

	(In millions)
Long-term debt	$	1,700		$	1,757		$	1,200		$	1,262
Net liabilities from price risk management activities	$	(732	)	$	(732	)	$	(482	)	$	(482	)

As of December 31, 2005 and 2004, 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.

Our derivative contracts are recorded in our financial statements at fair value. We estimate the fair value of those derivatives using commodity prices provided by Platts Research and Consulting, our independent pricing source. We use this pricing data to estimate the value of settlements in future periods based on the

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

contractual settlement quantities and dates. Finally, we discount these estimated settlement values using a LIBOR curve for the majority of our derivative contracts.

We have used derivative financial instruments to hedge the cash flow impact of our market risk exposures on our forecasted transactions related to our natural gas production. A majority of our commodity sales are at spot market prices. We may use futures, forward contracts and swaps to limit our exposure to fluctuations in the commodity markets with the objective of realizing a fixed cash flow stream from these activities. When we enter into the derivative contract, we designate the derivative as a cash flow hedge. 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 affiliated operating revenues when the hedged transactions occur. The ineffective portion of a cash flow hedge’s change in value is recognized immediately in earnings as a component of operating revenues in our income statement.

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 asset, liability, firm commitment or forecasted transaction. We regularly also 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 decide to discontinue the hedging relationship.

As of December 31, 2005 and 2004, the value of cash flow hedges included in accumulated other comprehensive income was a net unrealized loss of $444 million and $266 million, net of income taxes. We estimate that unrealized losses of $391 million, net of income taxes, will be reclassified from accumulated other comprehensive income during 2006. 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 7 years; however, most of our cash flow hedges expire within the next 12 months.

For the years ended December 31, 2005, 2004 and 2003, we recognized a net loss of $6 million, $1 million and $6 million, net of income taxes, related to the ineffective portion of all cash flow hedges.

In December 2004, we replaced our existing hedges on approximately 154 TBtu of natural gas with new hedge transactions at the same volume and over the same time period. The combination of our original hedges and the new transactions did not change the average price at which we are hedged and will not have an impact on our future realized prices. As a result, these transactions will have the same impact on our accumulated other comprehensive income balances, cash flows and income statement as our original derivative positions that existed prior to December 1, 2004. However these transactions “locked in” a loss in accumulated other comprehensive income that will be recognized in earnings. These contracts had a fair value loss of $520 million, net of income taxes of $192 million, at that time, and are being reclassified to income as the original hedged transactions settle through 2006. As of December 31, 2005, the net amount remaining in accumulated other comprehensive income related to these derivative contracts was $155 million.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Property, Plant and Equipment

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, 2005, pending determination of proved reserves (in millions):


	Cumulative		Costs Excluded						Cumulative
	Balance⁽¹⁾		for Years Ended⁽¹⁾						Balance
			December 31
	December 31,								December 31,
	2005		2005		2004		2003		2002

Acquisition	$	326	$	215	$	41	$	23	$	47
Exploration		57		20		9		24		4
Development		1		—		—		—		1

	$	384	$	235	$	50	$	47	$	52


⁽¹⁾	Includes capitalized interest of $19 million, $7 million, and less than $1 million for the years ended December 31, 2005, 2004, and 2003.

Projects presently excluded from amortization are in various stages of evaluation. The majority of these costs are expected to be included in the amortization calculation in the years 2006 through 2008. Our total amortization expense per Mcfe was $2.37, $1.96 and $1.54 in 2005, 2004, and 2003. Included in our depreciation, depletion and amortization expense is accretion expense of $0.10/Mcfe, $0.08/Mcfe and $0.06/Mcfe for 2005, 2004 and 2003 attributable to SFAS No. 143, which we adopted in January 2003.

During 2005, 2004 and 2003, our weighted average unit of production depletion rate on our natural gas and oil properties per Mcfe was $2.20, $1.81 and $1.44.


6.	Debt and Available Credit Facilities

Our long-term debt and available credit facilities consisted of the following at December 31, 2005:

Description

Interest Rate

Term⁽¹⁾

Amount Outstanding

(Millions)

$1.2 billion senior notes

7.75%

June 1, 2013

1,200

$500 million credit facility

LIBOR plus 1.875%

August 30, 2010

500

$400 million revolving borrowing base credit agreement

Varies

May 2006

—

Total

1,700


⁽¹⁾	We have the ability to call $1.7 billion of our debt in 2006 or thereafter. However, we do not currently have the intent to call this debt.

$1.2 billion senior notes. Our 7.75 percent senior unsecured 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, and our subsidiaries, other than the subsidiary guarantors, are minor. 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.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$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. 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 not be less than 2.0 to 1.0, our debt to EBITDA ratio not to be greater than 4.5 to 1.0 until September 30, 2006 and 4.0 to 1.0 thereafter and our collateral coverage ratio (as defined in the facility) must be greater than 1.5 to 1.0. In addition, we have a $25 million cross-acceleration provision.

$400 million credit facility. In November 2005, El Paso and one of our subsidiaries entered into this revolving borrowing base credit agreement which is collateralized by the natural gas and oil properties of our subsidiary. While no amounts have been drawn under this credit facility, the borrowing availability is $300 million and will mature in May 2006.


7.	Commitments and Contingencies


	Legal Proceedings and Other Contingencies

Grynberg. In 1997, a number of El Paso entities, including our subsidiary, El Paso Production Company, were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, 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, which deprived the U.S. Government of royalties due to the alleged mismeasurement. The plaintiff in this case seeks royalties along with interest expenses and punitive damages. The plaintiff also seeks injunctive relief with regard to future gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). Motions to dismiss were argued before a representative appointed by the court. In May 2005, the representative issued its recommendation, which if adopted by the district court judge, will result in the dismissal on jurisdictional grounds of our subsidiaries. If the district court judge adopts the representative’s recommendations, an appeal by the plaintiff of the district court’s order is likely. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

Will Price (formerly Quinque). A number of El Paso entities, including our subsidiary, El Paso Production Company, are named as defendants in Will Price et al v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek to recover royalties that they contend they should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and postjudgment interest, punitive damages, treble damages, attorneys’ fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs’ motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied on April 10, 2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado and removes claims as to heating content. A second class action petition has since been filed as to the heating content claims. Motions for class certification have been briefed and argued in both proceedings, and the parties are awaiting the court’s ruling. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 will 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. Although El Paso and its Audit Committee had also received federal grand jury subpoenas for documents with regard to these reserve revisions, in June 2005, we were informed that the U.S. Attorney’s office closed this investigation and will not pursue prosecution at this time.

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 legal proceedings and other contingent matters, we evaluate the merits of the case, our exposure, 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 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. As of December 31, 2005, we had approximately $22 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, 2005, we had accrued approximately $5 million for related environmental remediation costs, of which less than $1 million is related to our one Superfund site. Liability at our Superfund site 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 PRP’s has been considered, where appropriate, in estimating our liabilities.

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, 2005, the annual minimum lease payments under non-cancelable future operating lease commitments were less than $1 million for each of the years 2006 and 2010. 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, 2005 and approximately $6 million and $4 million for the years ended December 31, 2004 and 2003.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Other Commercial Commitments

At December 31, 2005, we have various commercial commitments totaling $257 million, primarily related to commitments associated with our drilling activities. Our annual obligations under these arrangements are $174 million in 2006, $20 million in 2007, $17 million in 2008, $12 million for each of the years 2009 and 2010 and $22 million in total thereafter.


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 the related costs to its affiliates.


	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.	Supplemental Cash Flow Information

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


10.	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 interest 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 unconsolidated affiliates on our income statement net of the excess purchase price amortization. In 2005 we received dividends of $34 million from Four Star. At December 31, 2005, our investment in Four Star was greater than our equity in the net assets of this investment by $669 million, a portion of which related to Four Star’s unevaluated properties. 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. In 2005, we recorded $20 million 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 since the date of acquisition and the financial position of Four Star at December 31, 2005.

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		In millions

Operating results data:
	Operating revenues	$	81
	Operating expenses		20
	Net income		39
Financial position data:
	Current assets		64
	Non-current assets		101
	Other current liabilities		51
	Other non-current liabilities		29
	Equity in net assets		85

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, 2005 and 2004. We recognized equity earnings of less than $1 million for each of the years ended December 31, 2005, 2004 and 2003 from this unconsolidated affiliate.

Related Party Transactions

Cash Management Program. Subject to limitations in our indenture, 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, 2005 and 2004, we had a note payable to El Paso of approximately $125 million and $975 million on our balance sheet which is classified as a current note payable to affiliate primarily based on the anticipated repayment to El Paso of amounts owed under the cash management program. Our note payable under this program decreased at the end of 2005 upon the contribution of amounts by El Paso described below. The interest rate under the cash management program was 5.0% at December 31, 2005 and 2.0% at December 31, 2004.

Red River Financing (Red River). During 1999, El Paso formed various companies for the purpose of generating funds to invest in capital projects and other assets. In March 2003, El Paso obtained a $1.2 billion bridge loan and loaned the proceeds to several of our subsidiaries which subsequently made dividends of this amount back to El Paso who used the funds to retire their net balance under the Red River financing arrangement. In May 2003, we issued $1.2 billion of senior notes and used the proceeds to repay our obligation to El Paso in conjunction with this arrangement. For the year ended December 31, 2003, we recorded interest expense of $23 million related to this arrangement.

Also in 2003, we made dividends to El Paso of $206 million under the Red River financing arrangement including a $150 million non-cash dividend to El Paso of demand notes established under this financing arrangement.

Capital Contributions. In 2005 and 2004, El Paso contributed $1.5 billion and $0.2 billion to us primarily in conjunction with our reorganization and in 2005 also contributed approximately $0.1 billion to us to partially fund acquisitions, including Medicine Bow. In 2003, El Paso contributed approximately $1.0 billion to us which partially reduced our payables outstanding under our cash management program. Of the total contributions, approximately $1.3 billion, less than $0.1 billion, and $1 billion were non-cash in 2005, 2004 and 2003.

Dividends. During 2005, 2004 and 2003, we made dividends to our parent of approximately $0.2 billion, $0.1 billion and $2.3 billion. In 2005 and 2004, these amounts primarily related to settlements under derivative contracts between us and El Paso affiliates. In 2003, our dividends primarily included $0.2 billion related to these contracts and approximately $1.9 billion made in conjunction with El Paso financing arrangements, including Red River. Of total 2003 dividends, approximately $0.2 billion were non-cash.

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

EL PASO EXPLORATION & PRODUCTION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 periods ended December 31:


	2005		2004		2003

	(In millions)
Operating revenues	$	741	$	953	$	1,613
Operating expenses from affiliates		122		135		142
Reimbursements of operating expenses charged to affiliates		18		18		—


	•	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. On January 1, 2006, El Paso adopted SFAS No. 123(R), Share-Based Payment, which requires that companies measure all employee stock-based compensation awards at fair value on the date they are granted to employees and recognize compensation costs in its financial statements over the requisite service period. As a result, beginning in 2006, we will record additional expenses for all stock-based compensation awards (including stock options) granted directly to our employees as well as our allocable share of El Paso’s corporate stock-based compensation expense.

		At December 31, 2005 and 2004, we had accounts payable to our affiliates of approximately $32 million and $2 million. We also have a service agreement with El Paso that provides for a reimbursement of 2.5 cents per MMBtu in 2005 and 2006 for our expected administrative costs associated with hedging transactions we entered into in December 2004.

	•	El Paso Marketing. We sell our natural gas primarily to El Paso Marketing at spot market prices. At December 31, 2005 and 2004, substantially all of our affiliated accounts receivable of $355 million and $178 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 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, 2005 and December 31, 2004, we had contractual deposits of $6 million with El Paso’s regulated interstate pipelines.

Taxes. Additionally, 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 federal income tax receivables of $40 million and $14 million in other current assets at December 31, 2005 and 2004, on our balance sheet. In addition, we have $32 million of federal income taxes receivables in other non-current assets at December 31, 2004. We also have state income taxes payable of $8 million and $22 million at December 31, 2005 and 2004, included in other current liabilities 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.

Under El Paso’s tax accrual policy, we are allocated the tax effects associated with our employees’ nonqualified disposition of El Paso stock under an employee stock purchase plan, the exercise of stock options and the vesting of restricted stock, as well as dividends on restricted stock. These tax effects are included in additional paid-in capital in our balance sheets.

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter, is summarized below:


		Quarters Ended

		March 31		June 30		September 30		December 31		Total

		(In millions)
2005
	Operating revenues	$	348	$	380	$	390	$	371	$	1,489
	Operating income		94		108		111		75		388
	Income before cumulative effect of accounting change		45		49		51		29		174
	Net income		45		49		51		29		174


		Quarters Ended

		March 31		June 30		September 30		December 31		Total

		(In millions)
2004
	Operating revenues	$	401	$	389	$	347	$	390	$	1,527
	Operating income		145		149		102		105		501
	Income before cumulative effect of accounting change		66		81		50		57		254
	Net income		66		81		50		57		254

Supplemental Natural Gas and Oil Operations (Unaudited)

We are engaged in the exploration for, and the acquisition, development and production of natural gas, oil, condensate and natural gas liquids. We primarily operate in Alabama, Utah, Louisiana, New Mexico, Oklahoma, Texas and the Gulf of Mexico.

Capitalized costs relating to natural gas and oil producing activities and related accumulated depreciation, depletion and amortization were as follows at December 31:


		2005		2004

		(In millions)
Natural gas and oil properties:
	Costs subject to amortization	$	14,903	$	14,237
	Costs not subject to amortization		384		308

			15,287		14,545
Less accumulated depreciation, depletion and amortization			10,809		10,887

Net capitalized costs		$	4,478	$	3,658

FAS 143 abandonment liability		$	190	$	254

Costs incurred in natural gas and oil producing activities, whether capitalized or expensed, were as follows for each of the years ended December 31:


			2005		2004		2003

			(In millions)
Property acquisition costs
	Proved properties		$	643	$	33	$	10
	Unproved properties			143		32		35
Exploration costs				143		185		467
Development costs				503		395		668

	Costs expended			1,432		645		1,180
Asset retirement obligation costs⁽¹⁾				1		30		124

		Total costs incurred⁽²⁾	$	1,433	$	675	$	1,304

Acquisition of unconsolidated investment in Four Star⁽²⁾			$	769	$	—	$	—


⁽¹⁾	Includes an increase to our property, plant and equipment of approximately $113 million in 2003 associated with our adoption of Statement of Financial Accounting Standard No. 143.

⁽²⁾	Includes $179 million of additional cost associated with deferred income tax adjustments related to the acquisitions of full-cost pool properties and of $217 million related to the acquisition of our unconsolidated investment in Four Star.

The table above includes capitalized internal costs incurred in connection with acquisition, development and exploration of natural gas and oil reserves of $41 million, $40 million and $53 million and capitalized interest of $25 million, $20 million and $17 million for the years ended December 31, 2005, 2004 and 2003.

In our January 1, 2006 reserve report, the amounts estimated to be spent in 2006, 2007 and 2008 to develop our booked proved undeveloped reserves are $277 million, $288 million and $193 million.

Net quantities of proved developed and undeveloped reserves of natural gas, oil and condensate and NGL, and changes in these reserves at December 31, 2005, are presented below. Information in these tables is based on our internal reserve report. Ryder Scott, an independent reservoir engineering firm, prepared a reserve estimate of our natural gas and oil reserves for 91 percent of our properties. Based on the amount of proved reserves determined by Ryder Scott, we believe these reported reserve amounts are reasonable. This information 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 was retained by and reports to the Audit Committee of El Paso’s Board of Directors.


						Oil &
			Natural Gas			Condensate			NGL
			(Bcf)			(MBbls)			(MBbls)

Net proved developed and undeveloped reserves⁽¹⁾
	January 1, 2003			2,488			38,354			21,607
		Revisions of previous estimates		(24	)		895			(2,717	)
		Extensions, discoveries and other		405			5,000			1,795
		Purchases of reserves in place		2			5			27
		Sales of reserves in place		(471	)		(4,328	)		(504	)
		Production		(339	)		(7,555	)		(4,223	)

	December 31, 2003			2,061			32,371			15,985
		Revisions of previous estimates		(172	)		(999	)		724
		Extensions, discoveries and other		79			2,214			58
		Purchases of reserves in place		15			—			—
		Sales of reserves in place		(21	)		(1,276	)		(47	)
		Production		(238	)		(4,979	)		(3,519	)


						Oil &
			Natural Gas			Condensate			NGL
			(Bcf)			(MBbls)			(MBbls)

	December 31, 2004			1,724			27,331			13,201
		Revisions of previous estimates		(43	)		260			1,148
		Extensions, discoveries and other		183			8,145			169
		Purchase of reserves in place		192			13,338			772
		Sales of reserves in place		(18	)		(969	)		(89	)
		Production		(207	)		(4,877	)		(2,639	)

	December 31,2005			1,831			43,228			12,562

Proved developed reserves
	December 31, 2003			1,428			22,821			14,088
	December 31, 2004			1,287			19,641			11,943
	December 31, 2005			1,404			28,581			11,010
Unconsolidated Investment in Four Star⁽²⁾
	December 31, 2005
	Net proved developed and undeveloped reserves			193			3,349			6,668
	Proved developed reserves			158			3,266			5,399


⁽¹⁾	Net proved reserves exclude royalties and interests owned by others and reflects contractual arrangements and royalty obligations in effect at the time of the estimate.
⁽²⁾	Our unconsolidated share of Four Star’s proved reserves has been estimated based on an evaluation of those reserves by El Paso’s internal reservoir engineers, and not by engineers of Four Star. An independent reservoir engineering firm, Ryder Scott, which was engaged by us, prepared an estimate on 86 percent of Four Star’s proved reserves. Based on the amount of proved reserves determined by Ryder Scott, we believe these reported reserve amounts are reasonable.

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 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, 2005.

We maintain an agreement with a subsidiary of Nabors Industries in which we sold interests in 23 wells. As the wells were developed, Nabors paid 20 percent of the drilling and development costs in exchange for 20 percent of the net profits of the wells sold. As each well commenced, Nabors received an overriding royalty interest in the form of a net profits interest in the well, under which they are entitled to receive 20 percent of the aggregate net profits of all wells until they recover 117.5 percent of their aggregate investment. Upon recovery, the net profits interest converts to a proportionately reduced 2 percent overriding royalty interest in

the wells for the remainder of the well’s productive life. We do not guarantee a return or the recovery of Nabor’s costs.

Results of operations from producing activities by fiscal year were as follows at December 31:


		2005			2004			2003

		(In millions)
Revenues
	Affiliated sales	$	741		$	953		$	1,613
	Sales to external customers		748			574			251

	Total		1,489			1,527			1,864
Transportation and net product costs			(62	)		(60	)		(87	)
Production costs⁽¹⁾			(256	)		(215	)		(231	)
Depreciation, depletion and amortization			(598	)		(568	)		(629	)

			573			684			917
Income tax expense			(204	)		(248	)		(346	)

Results of operations from producing activities		$	369		$	436		$	571

Equity earnings from unconsolidated investment in Four Star		$	19		$	—		$	—


⁽¹⁾	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves at December 31 follows:


	2005			2004			2003

	(In millions)
Future cash inflows⁽¹⁾	$	18,175		$	11,895		$	13,302
Future production costs		(3,968	)		(3,585	)		(3,025	)
Future development costs		(1,335	)		(1,234	)		(1,325	)
Future income tax expenses		(3,160	)		(1,184	)		(1,695	)

Future net cash flows		9,712			5,892			7,257
10% annual discount for estimated timing of cash flows		(3,660	)		(2,004	)		(2,449	)

Standardized measure of discounted future net cash flows	$	6,052		$	3,888		$	4,808

Standardized measure of discounted future net cash flows, including effects of hedging activities	$	5,573		$	3,547		$	4,367

Unconsolidated investment in Four Star
Standardized measure of discounted future net cash flows	$	617		$	—		$	—


⁽¹⁾	Excludes $760 million, $524 million and $739 million of future net cash outflows attributable to open hedging positions as of December 31, 2005, 2004 and 2003.

For the calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using year-end 2005 prices of $10.08 per MMBtu for natural gas and $61.04 per barrel of oil at December 31, 2005. After adjustments for transportation and other charges, net price were $8.33 per Mcf of gas, $57.42 per barrel of oil and $36.61 per barrel of NGL at December 31, 2005. 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.

We do not rely upon the standardized measure when making investment and operating decisions. These decisions are based on various factors including probable and proved reserves, different price and cost assumptions, actual economic conditions, capital availability, and corporate investment criteria.

The following are the principal sources of change in the standardized measure of discounted future net cash flows:


		Years Ended December 31,⁽¹⁾

		2005			2004			2003

		(In millions)
Sales and transfers of natural gas and oil produced net of production costs		$	(1,432	)	$	(1,444	)	$	(1,829	)
Net changes in prices and production costs			2,738			(62	)		1,586
Extensions, discoveries and improved recovery, less related costs			772			208			975
Changes in estimated future development costs			17			4			(16	)
Previously estimated development costs incurred during the period			247			156			220
Revision of previous quantity estimates			(140	)		(457	)		(94	)
Accretion of discount			436			555			526
Net change in income taxes			(1,007	)		278			205
Purchases of reserves in place			956			27			5
Sale of reserves in place			(83	)		(75	)		(1,229	)
Change in production rates, timing and other			(340	)		(110	)		150

	Net change	$	2,164		$	(920	)	$	499


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

SCHEDULE II

EL PASO EXPLORATION & PRODUCTION COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2005, 2004 and 2003

(In millions)


				Charged
		Balance at		to Costs					Charged			Balance
		Beginning		and					to Other			at End
Description		of Period		Expenses		Deductions			Accounts			of Period

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
2003
	Allowance for doubtful accounts	$	11	$	4	$	—		$	(1	)	$	14
	Legal reserves and other contingencies		19		2		(1	)		—			20
	Environmental reserves		4		—		—			1			5


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

None.


ITEM 9A.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2005, 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 SEC reports we file or submit under the Exchange Act is accurate, complete and timely.

Based on the results of this evaluation, our President and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2005.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting that has materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the fourth quarter of 2005.


ITEM 9B.	OTHER INFORMATION

None.

PART III

Item 10, “Directors and Executive Officers of the Registrant;” 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,” 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, 2005 and 2004 of $1,201,000 and $1,252,000 were for professional services rendered by 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, 2005 and 2004.

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

	Report of Independent Registered Public Accounting Firm		26
	Consolidated Statements of Income		27
	Consolidated Balance Sheets		28
	Consolidated Statements of Cash Flows		29
	Consolidated Statements of Stockholder’s Equity		30
	Consolidated Statements of Comprehensive Income		31
	Notes to Consolidated Financial Statements		32
2. Financial statement schedules and supplementary information required to be submitted.
	Schedule II — Valuation and Qualifying accounts		51
	Schedules other than that listed above are omitted because they are not applicable.
3. Exhibit list			54

EL PASO EXPLORATION & PRODUCTION COMPANY

EXHIBIT LIST

December 31, 2005

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.
	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).
	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	El Paso Production Companies Long-Term Incentive Plan effective as of January 1, 2003 (Exhibit 10.AA to El Paso’s 2003 First Quarter Form 10-Q).
	+10	.C.1	Amendment No. 1 to the El Paso Production Companies Long-Term Incentive Plan effective as of June 6, 2003 (Exhibit 10.13 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).


Exhibit
Number			Description

	+10	.C.2	Amendment No. 2 to the El Paso Production Companies Long-Term Incentive Plan effective as of December 31, 2003 (Exhibit 10.D.2 to our 2003 Form 10-K).
	10	.D	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	.E	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	.F	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	.G	Purchase and Sale Agreement (Red River) by and among El Paso Production Company, El Paso Production GOM Inc. and Lehman Commercial Paper Inc., dated October 3, 2003 (Exhibit 10.21 to Amendment No. 2 to our Form S-4 filed on November 24, 2003, Registration No. 333-106586).
	10	.H	First Amendment to Purchase and Sale Agreement by and among El Paso Production Company, El Paso Production GOM Inc. and Lehman Commercial Paper Inc., dated October 6, 2003 (Exhibit 10.22 to Amendment No. 2 to our Form S-4 filed on November 24, 2003, Registration No. 333-106586).
	10	.I	Purchase and Sale Agreement (Red River) by and among El Paso Production Company, El Paso Production GOM Inc. and Ramshorn Investments, Inc., dated October 8, 2003 (Exhibit 10.23 to Amendment No. 2 to our Form S-4 filed on November 24, 2003, Registration No. 333-106586).
	10	.J	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	.K	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	.L	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).
	10	.M	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).
	10	.N	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.


Exhibit
Number			Description

	*31	.A	Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*31	.B	Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*32	.A	Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
	*32	.B	Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.

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 our consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, El Paso Exploration & Production Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 17th day of March 2006.


	El Paso Exploration & Production Company


	By:	/s/ LISA A. STEWART



	Lisa A. Stewart
	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/ LISA A. STEWART Lisa A. Stewart	President and Director (Principal Executive Officer)	March 17, 2006

/s/ GENE T. WAGUESPACK Gene T. Waguespack	Senior Vice President, Chief Financial Officer, Treasurer and Controller (Principal Accounting and Financial Officer)	March 17, 2006

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.
	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).
	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	El Paso Production Companies Long-Term Incentive Plan effective as of January 1, 2003 (Exhibit 10.AA to El Paso’s 2003 First Quarter Form 10-Q).
	+10	.C.1	Amendment No. 1 to the El Paso Production Companies Long-Term Incentive Plan effective as of June 6, 2003 (Exhibit 10.13 to our Form S-4 filed on June 27, 2003, Registration No. 333-106586).
	+10	.C.2	Amendment No. 2 to the El Paso Production Companies Long-Term Incentive Plan effective as of December 31, 2003 (Exhibit 10.D.2 to our 2003 Form 10-K).
	10	.D	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).


Exhibit
Number			Description

	10	.E	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	.F	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	.G	Purchase and Sale Agreement (Red River) by and among El Paso Production Company, El Paso Production GOM Inc. and Lehman Commercial Paper Inc., dated October 3, 2003 (Exhibit 10.21 to Amendment No. 2 to our Form S-4 filed on November 24, 2003, Registration No. 333-106586).
	10	.H	First Amendment to Purchase and Sale Agreement by and among El Paso Production Company, El Paso Production GOM Inc. and Lehman Commercial Paper Inc., dated October 6, 2003 (Exhibit 10.22 to Amendment No. 2 to our Form S-4 filed on November 24, 2003, Registration No. 333-106586).
	10	.I	Purchase and Sale Agreement (Red River) by and among El Paso Production Company, El Paso Production GOM Inc. and Ramshorn Investments, Inc., dated October 8, 2003 (Exhibit 10.23 to Amendment No. 2 to our Form S-4 filed on November 24, 2003, Registration No. 333-106586).
	10	.J	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	.K	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	.L	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).
	10	.M	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).
	10	.N	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.
	*31	.A	Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*31	.B	Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*32	.A	Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
	*32	.B	Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.

(In millions)

Interest paid, net of amounts capitalized

Income tax payments