UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

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

For the transition period from           to           

 

THE HOUSTON EXPLORATION COMPANY

Delaware		22-2674487
(State or Other Jurisdiction of		(IRS Employer
Incorporation or Organization)		Identification No.)
1100 Louisiana, Suite 2000
Houston, Texas		77002-5215
(Address of Principal Executive Offices)		(Zip Code)

(713) 830-6800
(Registrant’s Telephone Number, including Area Code)

		Name of Each
Title of Each Class		Exchange on Which Registered
Common Stock, $.01 par value		New York Stock Exchange
7% Senior Subordinated Notes due 2013

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes o No þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1.026 billion, based on the closing sales price of $53.05 per share of the registrant’s common stock as reported by on the New York Stock Exchange as of June 30, 2005, the last business day of the registrant’s most recently completed second fiscal quarter. As of March 1, 2006, 29,067,430 shares of common stock were outstanding.

Portions of the registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 2006 are incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

Forward-Looking Statements and Available Information			2
Part I.			3
Items 1. and 2. Business and Properties			3
Item 1A. Risk Factors			15
Item 1B. Unresolved Staff Comments			21
Item 3. Legal Proceedings			21
Item 4. Submission of Matters to a Vote of Security Holders			22
Part II.			22
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			22
Item 6. Selected Financial Data			23
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			40
Item 8. Financial Statements and Supplemental Data			42
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			42
Item 9A. Controls and Procedures			43
Item 9B. Other Information			43
Part III.			43
Item 10. Directors and Executive Officers of the Registrant			43
Item 11. Executive Compensation			43
Item 12. Security Ownership of Beneficial Owners and Management			43
Item 13. Certain Relationships and Related Transactions			43
Item 14. Principal Accounting Fees and Services			44
Part IV.			44
Item 15. Exhibits, Financial Statement Schedules			44
Signatures			45
Glossary of Natural Gas and Oil Terms			G-1
Index to Financial Statements			F-1
Restated Bylaws
Computation of ratio of earnings to fixed charges
Subsidiaries
Consent of Deloitte & Touche LLP
Consent of Netherland, Sewell & Associates
Consent of Miller and Lents
Certification of William G. Hargett pursuant to Section 302
Certification of Robert T. Ray pursuant to Section 302
Certification of William G. Hargett pursuant to Section 906
Certification of Robert T. Ray pursuant to Section 906

Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents we have incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections, statements relating to our business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties which may cause actual results to differ materially from the forward-looking statements. A detailed discussion of these and other risks and uncertainties that could cause actual results and events to differ materially from such forward-looking statements is included in Item 1A. “Risk Factors” beginning on page 15 of this Annual Report. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at http://www.houstonexploration.com as soon as reasonably practicable after we electronically file such material with, or otherwise furnish it to, the SEC.

We have adopted a Code of Business Conduct to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures. We have also adopted a Code of Ethics for Senior Financial Officers that applies to our principal executive officer, principal financial officer, principal accounting officer and controller. Our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available on the Shareholder/Financial section of our web site at www.houstonexploration.com under the heading “Corporate Governance.” We intend to promptly disclose via a Current Report on Form 8-K or via an update to our web site information about any amendment to or waiver of, these codes with respect to our executive officers and directors. Our Corporate Governance Guidelines and the charters of our Audit Committee, Nominating and Governance Committee, and Compensation and Management Development Committee are also available on the Shareholder/Financial section of our web site at www.houstonexploration.com under the heading “Corporate Governance.” In addition, a copy of our Code of Business Conduct, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines and the charters of the Committees referenced above are available in print at no cost to any stockholder who requests them by writing or telephoning us at the following address or telephone number:

The Houston Exploration Company
1100 Louisiana Street, Suite 2000
Houston, TX 77002 — 5215
Attention: Corporate Secretary
Telephone: (713) 830-6800

Information contained on or connected to our web site is not incorporated by reference into this Annual Report and should not be considered part of this report or any other filing that we make with the SEC.

In this Annual Report, unless the context requires otherwise, when we refer to “we,” “us” and “our,” we are describing The Houston Exploration Company including, through May 31, 2004, our former subsidiary Seneca-Upshur Petroleum, Inc., and subsequent to October 8, 2004, THEC, LLC and THEC, LP on a consolidated basis.

If you are not familiar with the natural gas and oil terms used in this Annual Report, please refer to the explanations of the terms under the caption “Glossary of Natural Gas and Oil Terms” included on pages G-1 through G-2.

     When we refer to “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one barrel of oil is equal to six thousand cubic feet of natural gas.

Part I.

Overview of Our Business

We are an independent natural gas and oil producer concentrating on growing reserves and production through the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and oil on behalf of KeySpan Corporation, our then parent company. KeySpan is a diversified energy provider whose principal natural gas distribution and electric generation operations are located in the Northeastern United States. In September 1996, we completed our initial public offering and sold approximately 31% of our shares to the public. Through three separate transactions, the first in February 2003 and last in November 2004, KeySpan completely divested its investment in the common stock of our company.

At December 31, 2005, we had operations in five producing regions within the United States: South Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; the Uinta and DJ Basins in the Rocky Mountains; and the Gulf of Mexico.

Our total net proved reserves as of December 31, 2005 were 861 billion cubic feet equivalent or Bcfe, with onshore reserves totaling 616 Bcfe. Our reserves are fully engineered on an annual basis by independent petroleum engineers. Approximately 64% of our proved reserves at December 31, 2005, were classified as proved developed. Our daily production during 2005 averaged 313 million cubic feet of natural gas equivalent or MMcfe and was significantly curtailed during the last four months of 2005 and into the first quarter of 2006 primarily as a result of infrastructure damage to third party pipelines and processing facilities caused by Hurricanes Katrina and Rita that hit the Louisiana and Texas coasts in August and September 2005.

In November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to shift our operating focus onshore. This strategic change will leverage our strength of developing complex, tight or low permeable natural gas reservoirs while providing flexibility to expand both in our present core areas and other tight gas basins. During 2005, our offshore assets accounted for 40% of our 2005 production and represented 245 Bcfe, or 28% of our proved reserves, at December 31, 2005.

On February 28, 2006, we entered into an agreement to sell the Texas portion of our Gulf of Mexico assets to certain partnerships affiliated with Merit Energy Company for $220 million in cash, subject to adjustment and customary closing conditions. The transaction is scheduled to close on or about March 31, 2006, with an effective date of January 1, 2006. The sale process with respect to our remaining Gulf of Mexico assets is ongoing. If a sale is not consummated, we expect to continue to operate and may consider other strategic alternatives with respect to these assets.

The Texas portion of our Gulf of Mexico assets accounted for approximately 18% of our 2005 production and represented 58.5 Bcfe, or 7% of our total proved reserves, at December 31, 2005. We expect to use the proceeds from the sale of the Texas portion of our Gulf of Mexico assets primarily to acquire longer-lived natural gas assets onshore in North America and to repay existing debt. Where possible, we plan to structure our asset reinvestment to minimize taxes on any gain realized from the sale.

Business Strategy

Our goal is to create and maximize shareholder value by growing and/or optimizing reserves, production and cash flow, while maintaining financial flexibility. To grow our business, we invest primarily in natural gas projects within areas where we are presently successful or where we believe our organization’s skill set can produce successful results. To accomplish our goal, we employ the following strategies:

	§		Balanced Growth. We pursue a balanced strategy of exploiting our existing reserves, exploring for new reserves and acquiring new properties. Typically, at least 70% of our annual capital expenditure program is dedicated to lower risk exploitation and development projects intended to generate cash flows with which we can fund future expansion opportunities. We supplement our exploitation activities by investing in exploratory prospects. We enhance our exploration and exploitation activities with acquisitions of new projects that we believe offer significant unexploited reserve potential and that conform to our investment criteria and operating philosophy.
	§		Focus on Natural Gas. Our assets are concentrated in natural gas prone areas in the United States, and our production and reserve base is primarily natural gas. As of December 31, 2005, approximately 92% of our proved reserves were natural gas and, for the year ended December 31, 2005, approximately 93% of our production was natural gas. On an equivalent unit of production basis, lease operating expense is typically lower for natural gas properties as compared to oil properties allowing a higher cash margin. While we believe that the pricing fundamentals for natural gas will remain strong for the foreseeable future, we have explored and may continue to explore opportunities to balance our asset portfolio with additional oil properties. Such activities depend on the relative pricing outlook for both natural gas and oil, acquisition opportunities, and operational considerations, including our objectives of shifting operations onshore, lowering finding and development costs, and lengthening reserve life.
	§		Concentrate on Core Areas. We focus our drilling activities on properties in relatively concentrated areas in order to more efficiently utilize our base of geological, engineering, drilling and production experience and expertise in these regions. By concentrating our operations, we believe we are able to manage a large asset base with a relatively small number of employees and to integrate additional properties at relatively low incremental costs. At December 31, 2005, approximately 89% of our reserves were located in three core areas: South Texas, the Gulf of Mexico and the Arkoma Basin. Upon completion of the pending sale of the Texas portion of our Gulf of Mexico assets, South Texas and the Arkoma Basin will comprise approximately 47% and 19%, respectively, of our reserves. In addition, through our current activities in both the Rocky Mountains and East Texas, either one or both of these regions could develop into a core area in the future. Further, we plan to seek opportunities in one or more new areas where we believe we can utilize the strengths of our existing workforce to sustain future growth.
	§		Maintain Significant Operating Control. Whenever possible, we prefer to operate our properties as it gives us more control over the nature and timing of capital expenditures and overall operating expenses. At December 31, 2005, we operated approximately 80% of our wells and our average working interest was approximately 73%.
	§		Focus on Low Costs. We seek to minimize operating costs through the concentration of assets within geographic areas where we can leverage our operating control and capture operating efficiencies. Although we expect our costs will increase in 2006, we believe that our operating structure provides us a significant competitive advantage because it maximizes our margins and cash flows. For 2005, our lease operating expense was $0.59 per Mcfe.
	§		Employ Conservative Financial Policies. We typically fund our exploitation and exploration activities out of cash flows from operations, while we have funded acquisitions with borrowings under our revolving bank credit facility and through public debt offerings. Although our debt levels have historically increased periodically in connection with acquisitions, and may increase from time to time in the future as we continue to make acquisitions, we will seek to maintain conservative debt levels. Among other things, this will provide us with flexibility to continually review and adjust our capital expenditure program during the year based on operational developments, commodity prices, service costs, acquisition opportunities and numerous other factors. In addition to bank borrowings and public debt, we may also issue common stock in connection with future acquisitions, either initially as an element of the transaction consideration or subsequently as part of a financing plan.
	§		Managing Commodity Price Risks. We have historically employed a hedging program intended to reduce our exposure to adverse commodity price fluctuations and provide more predictable cash flows that allow us to plan and fund our capital expenditure program. While the use of derivative instruments has prevented us from realizing the full benefit of upward price movements and may continue to do so in the future, we believe that price volatility is likely to continue and that we can use this volatility to our benefit by taking advantage of prices when they reach levels we believe lock in targeted rates of return on our invested capital.

Properties and Operating Areas

The table below summarizes certain data for our core operating areas for the year ended December 31, 2005:

		Activity and Balances as of or for the Year Ended December 31, 2005
		Average								Total				Percentage
		Daily				Total				Proved				Total Proved
		Production				Production				Reserves				Reserves
																		Wells Drilled
Area																		Total				Successful
		(MMcfe/d)				(MMcfe)				(MMcfe)								(Gross)				(Gross)
South Texas			134				48,983				374,163				44	%			95				82
Arkoma Basin			43				15,789				151,054				18	%			61				60
East Texas			5				1,812				61,308				7	%			16				16
Rocky Mountains			5				1,665				26,713				3	%			149				128
Other			1				372				2,986				—				—				—
Total onshore			188				68,621				616,224				72	%			321				286
Gulf of Mexico			125				45,690				244,596				28	%			15				12
Total			313				114,311				860,820				100	%			336				298

South Texas. Our South Texas properties are concentrated in the Charco, North Roleta, Haynes and South Trevino Fields of Zapata County; the Alexander, Hubbard and South Laredo Fields of Webb County; and the Northeast Thompsonville Field in Jim Hogg County. In November 2005, we spent $159.0 million to expand our South Texas operating base by acquiring 62 Bcfe of proved reserves and interests in 300 producing wells and 26,000 net acres covering the Rincon Field in Starr County, the Tijerina-Canales-Blucher Field in Jim Wells and Kleberg Counties, the Vaquillas Ranch Field in Webb County, and the San Carlos Field in Hidalgo County. These properties are expected to add significant drilling opportunities for 2006. We plan to add a seventh drilling rig early in the second quarter of 2006 at which time we expect to spud our first well in the Rincon Field.

As of December 31, 2005, our South Texas properties covered approximately 94,600 net acres and we owned interests in 872 producing wells, 764 or 88% of which we operated. Our average working interest is 84%. Well depths range from 5,000 to 17,000 feet with production from the Frio, Vicksburg and Wilcox formations. In total, our net South Texas production has more than tripled since we began operations in the area in July 1996, to an average of 134 MMcfe per day during 2005. Over the course of nine and a half years, we drilled 451 wells, of which 366 were successful, produced 342 Bcfe and added 603 Bcfe in reserves through drilling and acquisitions. South Texas accounted for 43% of our total production during 2005 and approximately 44% of our reserve base as of December 31, 2005

Gulf of Mexico. Our offshore properties are located in the shallow waters of the Outer Continental Shelf. Our key producing properties are located in the western and central Gulf of Mexico and include the Mustang Island, Matagorda Island, Galveston Island, High Island, East Cameron, West Cameron, Eugene Island and Main Pass areas. Over the last three years, our offshore operations have become less exploration-focused, as we have undertaken a number of exploration and exploitation activities aimed at maximizing production from older, previously produced fields acquired from third parties.

In November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to shift our operating focus onshore. On February 28, 2006, we announced the pending sale, subject to customary closing conditions, of the Texas portion of these assets. The sale process with respect to our remaining Gulf of Mexico assets is ongoing and if a sale is not consummated, we expect to continue to operate and may consider other strategic alternatives with respect to these assets.

As of December 31, 2005, we held interests in 136 blocks in federal and state waters, of which 78 were developed. As of December 31, 2005, we operated 45 of our developed blocks, which accounted for approximately 80% of our offshore production during 2005. We had a total of 97 producing platforms and production caissons, of which we operated 61. At December 31, 2005, we held interests in 70 blocks in offshore Texas state and federal waters, of which 33 were developed. Our Texas assets included 38 producing platforms and production caissons. During 2005, production from our Gulf of Mexico properties comprised approximately 40% of our total production, averaging 125 MMcfe per day and was significantly curtailed during the last four months of 2005 as a result of Hurricanes Katrina and Rita that hit the Louisiana and Texas Gulf coasts in August and September 2005.

Arkoma Basin. Our Arkoma Basin properties are located in two primary areas: the Chismville/Massard Field located in Logan and Sebastian Counties of Arkansas and the Wilburton and South Panola Fields located in Latimer County, Oklahoma. At December 31, 2005, we had approximately 37,200 net acres under lease and we owned working interests in 411 producing natural gas wells, 289 of which we operated. Wells average a depth of 5,500 feet and production is from the Atoka formation. Beginning in 2003, we significantly increased our developmental drilling program with the expansion of in-field drilling opportunities as a result of a series of downspacing initiatives authorized by the Arkansas Oil and Gas Commission, first in September 2002 from 640 acres per well to 160 acres per well, again in September 2003 from 160 acres to 80 acres per well, and finally in December 2004 to approximately 40 acres per well. During 2005, average daily production increased by 13% from 38 MMcfe per day during 2004 to 43 MMcfe per day during 2005. Acquisition opportunities have been scarce or limited in the Arkoma Basin during 2005 and 2004 and, as a result, our current activities are focused on the substantial number of in-field drilling opportunities within our existing acreage. During 2006, we plan to continue our in-field drilling program with three rigs drilling during the year. In addition, during the fourth quarter of 2005, we participated with a 40% working interest in a 13,000 foot exploration well that is preparing to test Atoka sands.

East Texas. During 2005, we expanded our existing operations and reserve base located in the Willow Springs Field in Gregg County, Texas through a series of three acquisitions totaling a $38.7 million where we added approximately 37.5 Bcfe in proved reserves. We purchased interests in producing properties and undeveloped acreage in the South Oak Hill Field located in Rusk County and the North Blocker Field in Harrison County. We began drilling within two months of the initial acquisition of these properties in March 2005, and successfully drilled and completed 16 of 16 new wells, adding approximately 13 Bcfe in proved reserves, and increased our average daily production from 2 MMcfe per day in January 2005 to 8 MMcfe per day in December 2005. At December 31, 2005, we had two rigs drilling and owned interests in 49 natural gas wells and three oil wells. We operated 48 of the natural gas wells and all three of the oil wells. Our average working interest in all 52 wells was 80%.

Rocky Mountains. Our Rocky Mountain properties are located in the Uinta Basin of Northeastern Utah and the DJ Basin in Eastern Colorado. At December 31, 2005, we had accumulated more than 566,000 net acres with estimated net proved reserves of 27 Bcfe. During 2005, production from our Rocky Mountain properties averaged approximately 5 MMcfe per day, net to our interests.

During 2005, we continued proving up and delineating portions of our Uinta Basin acreage where we actively began drilling during 2004. As part of this effort, we partnered with two different groups in an effort to both optimize our capital utilization and accelerate our exploration efforts in that area. We drilled or participated in the drilling of a total of 36 wells, of which 30, or 83%, were successful. As in the previous year, during 2005, we experienced delays in bringing new production on-line, primarily due to difficulties in obtaining pipeline right-of-ways. At December 31, 2005, 12 of our newly completed Uinta wells were shut-in and awaiting approvals for pipeline right-of-ways.

In the DJ Basin, we expanded our exploration efforts along the Niobrara Trend and drilled 107 wells, successfully completing 98, or 92%. We added approximately 18 Bcfe from drilling, with first production in mid-July 2005. A second gathering system was completed in January 2006. Subsequent to December 31, 2005, 30 of the 50 wells shut-in at year-end waiting connection to the gathering system commenced production, adding approximately 2.4 MMcfe per day in new production, net to our interest. For 2006, we plan to continue exploration and development programs in both the Uinta and the DJ Basins in an effort to expand the known producing areas and to test new ideas.

Other. As of December 31, 2005, “other” primarily represents interests in one field in Central Mississippi. The Oakvale Dome Field is located in Jefferson Davis County and has two producing wells, both of which are non-operated. Production averaged approximately 1 MMcfe/day during 2005. Our interests in the Oakvale Dome Field together with interests in the Wausau Field, located in Wayne County Mississippi, were acquired in October 2004 as part of our acquisition of 10 offshore blocks in the shallow waters of the Central Gulf of Mexico. We sold our interest in the Wausau Field during 2005. In addition to our interests in the Oakvale Dome Field, we have interests or rights of an immaterial nature in other prospective properties or projects with respect to which no reserves are currently associated, and may make future investments of immaterial amounts in similar such projects from time to time in the future.

Natural Gas and Oil Reserves

The following table summarizes the estimates of our historical net proved reserves as of December 31, 2005, 2004 and 2003, and the present values attributable to those reserves at those dates. For the year ended December 31, 2005, the reserve data and present values were fully engineered by independent petroleum engineering consultants Netherland, Sewell & Associates, Inc. For the years ended December 31, 2004 and 2003, reserve data and present values were fully engineered by two independent petroleum engineering firms: Netherland, Sewell & Associates, Inc. and Miller and Lents, Ltd., with each evaluating approximately 80% and 20%, respectively, of the total reserve quantities during 2004 and 75% and 25%, respectively, during 2003.

		As of December 31,
Net Proved Reserves:		2005(1)				2004				2003
		(in thousands)
Natural gas (MMcf)			793,074				749,114				709,883
Oil and natural gas liquids (MBbls)			11,291				7,335				7,481
Total (MMcfe)			860,820				793,124				754,769
Standardized measure of discounted future net cash flows (2)		$	1,967,024			$	1,440,055			$	1,504,406

In accordance with applicable requirements of the SEC, we estimate net proved reserves and future net revenues using sales prices estimated to be in effect as of the date we make the reserve estimates. Sales price estimates are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. Natural gas and oil prices have fluctuated widely in recent years and volatility is expected to continue. Future prices and costs may be materially higher or lower than prices and costs as of the date of any estimate. Price fluctuations will directly affect estimated quantities of proved reserves and future net revenues. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control.

The reserve data contained in this Annual Report represent only estimates. Reservoir engineering is a complex and 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 interpretation and judgment. As a result, estimates prepared by one engineer may vary from those prepared by another. Estimates are subject to revision based on numerous factors including reservoir performance, prices and economic conditions. In addition, results of drilling, testing and actual production subsequent to the date of estimate may justify revision of that estimate. Revisions to prior estimates may be material. Reserve estimates are often different from the quantities of natural gas and oil that we are ultimately able to recover and are highly dependent upon the accuracy of the underlying assumptions. Our estimated proved reserves have not been filed with or included in reports to any federal agency. See Item 1A. “Risk Factors — Estimates of proved reserves and future net revenues may change if the assumptions on which such estimates are based prove to be inaccurate.”

Drilling Activity

We engage in numerous drilling activities on properties presently owned by us and intend to drill or develop other properties we may acquire in the future. The following table sets forth the results of our drilling activities for the years ended December 31, 2005, 2004 and 2003. Gross wells are the sum of all wells in which we owned an interest. Net wells are the sum of our working interests in the gross wells.

		Exploratory Wells																Development Wells																Total Wells
		Successful								Dry								Successful								Dry								Successful								Dry								Total
		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
2005
South Texas			1				1.0				—				—				81				79.8				13				13.0				82				80.8				13				13.0				95				93.8
Arkoma Basin			—				—				—				—				60				36.8				1				0.8				60				36.8				1				0.8				61				37.6
East Texas			—				—				—				—				16				16.0				—				—				16				16.0				—				—				16				16.0
Rocky Mountains			128				96.4				21				15.7				—				—				—				—				128				96.4				21				15.7				149				112.1
Gulf of Mexico			5				2.4				2				1.3				7				6.1				1				0.5				12				8.5				3				1.8				15				10.3
Total areas 2005			134				99.8				23				17.0				164				138.7				15				14.3				298				238.5				38				31.3				336				269.8
2004
South Texas			—				—				1				1.0				56				54.6				19				18.0				56				54.6				20				19.0				76				73.6
Arkoma Basin			—				—				—				—				73				45.8				6				3.0				73				45.8				6				3.0				79				48.8
Rocky Mountains			26				25.4				3				2.3				2				2.0				—				—				28				27.4				3				2.3				31				29.7
Other			—				—				1				0.5				5				5.0				—				—				5				5.0				1				0.5				6				5.5
Gulf of Mexico			3				1.4				4				2.2				12				9.3				—				—				15				10.7				4				2.2				19				12.9
Total areas 2004			29				26.8				9				6.0				148				116.7				25				21.0				177				143.5				34				27.0				211				170.5
2003
South Texas			3				3.0				3				3.0				53				51.3				18				17.5				56				54.3				21				20.5				77				74.8
Arkoma Basin			—				—				1				0.4				46				28.6				4				2.5				46				28.6				5				2.9				51				31.5
Other onshore			—				—				—				—				2				2.0				—				—				2				2.0				—				—				2				2.0
Gulf of Mexico			6				2.4				8				3.6				3				2.0				—				—				9				4.4				8				3.6				17				8.0
Total areas 2003			9				5.4				12				7.0				104				83.9				22				20.0				113				89.3				34				27.0				147				116.3

As of December 31, 2005, we were drilling or participating in the drilling of 13 gross (8.86 net) wells. Of these wells, through March 1, 2006, 9 gross (7.0 net) wells have been determined to be successful, with the remaining 4 gross (1.8 net) wells still in progress as of the date of our Annual Report.

Productive Wells

The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2005. Productive wells consist of producing wells and wells capable of production, including 62 wells located in the Rocky Mountains (50 in the DJ Basin and 12 in Uinta), awaiting connections at December 31, 2005. Wells that are completed in more than one producing horizon are counted as one well. As “operator,” we are designated the party under the terms of an operating agreement that manages the day-to-day operations of the well.

		As of December 31, 2005
		Natural Gas Wells																Oil Wells																Total Wells
		Operated								Non-Operated								Operated								Non-Operated
		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
South Texas			743				707.8				108				14.9				21				12.4				—				—				872				735.1
Arkoma Basin			289				197.1				122				26.1				—				—				—				—				411				223.2
East Texas			48				38.7				1				0.4				3				2.2				—				—				52				41.3
Rocky Mountains			117				96.2				42				21.0				2				1.0				—				—				161				118.2
Other			—				—				2				1.1				—				—				—				—				2				1.1
Total onshore			1,197				1,039.8				275				63.5				26				15.6				—				—				1,498				1,118.9
Gulf of Mexico			91				71.9				54				15.4				18				14.1				6				0.9				169				102.3
Total			1,288				1,111.7				329				78.9				44				29.7				6				0.9				1,667				1,221.2

Acreage Data

The following table sets forth the approximate developed and undeveloped acreage in which we held a leasehold mineral or other interest as of December 31, 2005. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not the acreage contains proved reserves. Gulf of Mexico acreage includes leases in federal and state waters.

		As of December 31, 2005
		Undeveloped								Developed								Total Acreage
		Gross				Net				Gross				Net				Gross				Net
South Texas			14,606				12,978				107,299				81,672				121,905				94,650
Arkoma Basin			25,624				8,857				59,707				28,322				85,331				37,179
East Texas			5,547				3,488				10,746				6,670				16,293				10,158
Rocky Mountains			703,196				543,380				41,943				22,937				745,139				566,317
Other onshore			—				—				1,740				620				1,740				620
Total onshore			748,973				568,703				221,435				140,221				970,408				708,924
Gulf of Mexico			227,062				159,521				314,886				200,926				541,948				360,447
Total			976,035				728,224				536,321				341,147				1,512,356				1,069,371

Undeveloped Acreage Expirations

The table below summarizes by year and area our undeveloped acreage scheduled to expire in the next five years.

		As of December 31, 2005
		2006								2007								2008								2009								2010
		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
South Texas			3,686				3,064				5,399				5,240				1,111				1,076				—				—				—				—
Arkoma Basin			—				—				2,816				932				—				—				614				238				4,088				1,154
East Texas			—				—				3,592				2,734				60				40				—				—				—				—
Rocky Mountains			193,559				129,257				110,287				84,391				150,362				120,943				35,399				27,213				16,171				5,713
Total onshore			197,245				132,321				122,094				93,297				151,533				122,059				36,013				27,451				20,259				6,867
Gulf of Mexico			32,257				24,897				46,181				37,921				62,824				34,756				42,280				26,324				15,000				12,500
Total			229,502				157,218				168,275				131,218				214,357				156,815				78,293				53,775				35,259				19,367

Marketing and Customers

We market the majority of the natural gas and oil production from properties we operate for both our account and the account of the other working interest owners in these properties. We typically sell a substantial portion of our production under short-term (usually one-month) contracts tied to a local index. We do not have any material long-term, fixed price sales contracts. The remaining portion of our production is sold on a daily basis into local spot markets in order to accommodate fluctuations in daily production volumes. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. However, based on the current demand for natural gas and oil, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations. For a list of our purchasers that accounted for 10% or more of our natural gas and oil revenues during the preceding last three calendar years, see “Notes to Consolidated Financial Statements — Note 8 — Sales to Major Customers.”

We enter into hedging transactions with unaffiliated third parties for significant portions of our natural gas production. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

We incur gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third party transporter. We do not have any material transportation agreements and we have not contracted for firm capacity for which we would pay monthly demand charges. Our natural gas and oil are transported through third party gathering systems and pipelines.

Transportation space on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has only been infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. See the section entitled “Item 1A. Risk Factors — Our business depends on oil and natural gas transportation facilities that are owned by others.”

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to undeveloped acreage in farm-out agreements and natural gas and oil leases. Prior to the commencement of drilling operations, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typically responsible for curing any title defects at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. Prior to completing an acquisition of producing natural gas and oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion. Our natural gas and oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Competition

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of additional properties and acreage. This competition has intensified in response to rising natural gas price levels and the natural maturation of several of our key fields. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially greater capital resources than our own. Our ability to acquire additional properties and to discover new reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. See Item 1A. “Risk Factors — We face strong competition.”

Seasonal Nature of Business

Generally, but not always, the demand for natural gas increases during the winter months as a result of heating applications and decreases during the summer months. Seasonal anomalies such as mild winters or cool summers sometimes lessen this fluctuation. In addition, as the industrial use of natural gas has expanded in recent years, weather related demand and seasonal fluctuations are diminishing. However, seasonal weather conditions, such as recent severe tropical storms and hurricanes in the Gulf of Mexico and winter weather in the Rocky Mountain region can pose challenges for meeting our well drilling and production objectives.

Employees

As of December 31, 2005, we had 167 full time employees, 134 of whom are located at our headquarters in Houston, Texas and the remainder of whom are located in our South Texas, Arkansas, Denver and East Texas field offices. None of our employees are represented by a labor union or other collective bargaining arrangement. We employ the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design and well-site surveillance, permitting and environmental assessment. At our direction, independent contractors usually perform field and on-site production operation services, including pumping, maintenance, dispatching, inspection and testing.

Offices

Our corporate offices are located at 1100 Louisiana Street, Suite 2000, Houston, Texas 77002. Our telephone number is (713) 830-6800. We maintain field operations and other offices in South Texas, Arkansas, East Texas and Alabama. We currently lease approximately 114,000 square feet of office space in Houston, Texas, at 1100 Louisiana Street, where our principal offices are located. We lease approximately 2,250 square feet of office space in Denver, Colorado, at 700 17^th Street.

Regulation

The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native

American tribes are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, generally, these burdens do not appear to materially affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production. Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribes, in which we operate also regulate one or more of the following:

	§		the location of wells;
	§		the method of drilling and casing wells;
	§		the rates of production or “allowables;”
	§		the surface use and restoration of properties upon which wells are drilled; and
	§		the plugging and abandoning of wells.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Our properties located in federal waters are regulated by the Minerals Management Service and are not subject to regulation by state agencies.

We conduct our operations in the Gulf of Mexico on oil and natural gas leases that are granted by the U.S. federal government and are administered by the Minerals Management Service. The Minerals Management Service issues leases through competitive bidding. The lease contracts contain relatively standardized terms and require compliance with detailed regulations of the Minerals Management Service. For offshore operations, lessees must obtain Minerals Management Service approval for exploration plans and development and production plans prior to the commencement of the operations. In addition to permits required from other agencies, such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the Minerals Management Service prior to the commencement of drilling. In certain instances, substantial Certificates of Financial Responsibility or other acceptable assurances must be provided and maintained under the federal Oil Pollution Act of 1990.

The Minerals Management Service promulgates and enforces regulations that require offshore production facilities located on the Outer Continental Shelf to meet stringent engineering, construction, and safety specifications, that impose strong restrictions on the flaring or venting of natural gas, that prohibit the burning of liquid hydrocarbons and oil without prior authorization, and that govern the plugging and abandonment of offshore wells and removal of offshore production facilities. To cover the various obligations of lessees on the Outer Continental Shelf, the Minerals Management Service generally requires that lessees post and maintain substantial bonds or other acceptable assurances that these obligations will be met. The Outer Continental Shelf Lands Act may generally impose liabilities on us for our offshore operations conducted on federal leases for clean-up costs and damages caused by pollution resulting from our operations. Under circumstances such as conditions deemed to be a threat or harm to the environment, the Minerals Management Service may suspend or terminate any of our operations in the affected area.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC

promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the current regulatory approach will continue indefinitely into the future nor can we determine what affect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, interstate transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. In offshore Federal waters, the Outer Continental Shelf Lands Act requires every permit or other grant of authority for the transportation of oil or gas by pipeline on or across the Outer Continental Shelf to require the pipeline to provide open and nondiscriminatory access, but does not authorized FERC to create and enforce open access rules or to regulate rates for gathering on the Outer Continental Shelf. The lack of federal oversight over the rates charged for gathering on the Outer Continental Shelf affects our costs of getting the gas we produce on the Outer Continental Shelf to point-of-sale locations.

Environmental Matters and Regulation

General. Our operations are subject to and must comply with the same federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection as other companies in the oil and gas exploration and production industry. These laws and regulations may:

	§		require the acquisition of a permit before drilling commences;
	§		require the installation of expensive pollution control measures;
	§		restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
	§		limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;
	§		require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells; and
	§		impose substantial liabilities for pollution resulting from our operations.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and the federal and state agencies frequently revise the environmental laws and regulations. Any changes that result in more stringent and costly waste handling, disposal and clean-up requirements could have a significant impact on the oil and gas industry’s operating costs, including ours. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations at this time. For the year ended December 31, 2005, we did not incur any material capital expenditures for environmental control facilities. As of the date of our Annual Report, we are not aware of any environmental issues or claims that will require material expenditures during 2006 and 2007 or that will have a material impact on our financial position or results of operations.

The most significant of these environmental laws and regulations include, among others, the:

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA, affects oil and gas production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of the Resource Conservation and Recovery Act, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to recategorize certain oil and gas exploration and production wastes as “hazardous wastes.”

We believe that we are currently in substantial compliance with the requirements of the Resource Conservation and Recovery Act and related state and local laws and regulations and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under the Resource Conservation and Recovery Act.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site, or site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance. CERCLA also authorizes the EPA and affected parties to respond to threats to the public health or the environment and to seek recovery from responsible classes of persons for the costs of the response actions.

In the course of our operations, we generate wastes that may fall within CERCLA’s definition of “hazardous substances.” Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been deposited. As of the date of our report, however, we have no knowledge of having been named by the EPA or alleged by any third party as being responsible for costs and liability associated with alleged releases of any “hazardous substance” at any “superfund” site.

Oil Pollution Act. The Oil Pollution Act imposes on responsible parties strict, joint and several, and potentially unlimited liability for removal costs and other damages caused by an oil spill covered by the Oil Pollution Act and offers few defenses to such liability. The Oil Pollution Act also requires the lessee of an offshore area or a permittee whose operations take place within a covered offshore facility to establish and maintain financial responsibility of at least $35 million, which may be increased to $150 million for facilities with large worst-case spill potentials and under other circumstances, to cover liabilities related to an oil spill for which the lessee or permittee of the offshore area is statutorily responsible. Owners of multiple facilities are required to maintain financial responsibility for only the facility with the largest potential worst-case spill. We have received certification from the Minerals Management Service that due to our financial status, we are able to cover a minimum of $35 million per occurrence and because we do not have major oil producing facilities, the maximum certification of $150 million in coverage is not currently required. As such, we currently believe we are in substantial compliance with the financial responsibility provisions of the Oil Pollution Act. If we completely divest our Gulf of Mexico assets, we would no longer be subject to the provisions of the Oil Pollution Act.

Federal Water Pollution Control Act/Clean Water Act. The Federal Water Pollution Control Act or Clean Water Act and related state laws provide varying civil and criminal penalties and liabilities for the unauthorized discharge of petroleum products and other pollutants to surface waters. The federal discharge permitting program also prohibits the discharge of produced water, sand and other substances related to the oil and gas industry to coastal waters. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. We currently believe that we are in substantial compliance with all pollutant, wastewater, and stormwater discharge regulations and that we hold all necessary and valid permits, other required authorizations, and spill response plans for the discharge of such materials from our operations.

Federal Clean Air Act. The Federal Clean Air Act restricts the emission of air pollutants and affects both onshore and offshore oil and gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, EPA has developed and continues to develop more stringent regulations governing emissions of toxic air pollutants. These regulations may

increase the costs of compliance for some facilities. We currently believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations.

In 1997, numerous countries participated in an international conference under the United Nations Framework Convention on Climate Change and concluded an agreement, known as the Kyoto Protocol. The Protocol became effective February 14, 2005, and will require reductions of certain emissions that contribute to atmospheric levels of greenhouse gases. The United States has not ratified the Protocol but may in the future. Presently, it is not possible to accurately estimate the costs we could incur to comply with any laws or regulations developed to achieve such emissions reductions, but such expenditures could be substantial.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Item 1A. Risk Factors

The volatility of natural gas and oil prices may affect our financial results.

As an independent natural gas and oil producer, our revenues, operating results, profitability and future rate of growth are highly dependent on the price of, and demand for, the natural gas and oil that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Even relatively modest changes in natural gas and oil prices may significantly change our revenues, results of operations, cash flows and proved reserves.

Historically, the markets for natural gas and oil have been volatile and are likely to continue to be volatile in the future. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

	§		the domestic and foreign supply of natural gas and oil;
	§		weather conditions;
	§		the price of foreign imports;
	§		overall domestic and global economic conditions;
	§		terrorist attacks or military conflicts;
	§		political and economic conditions in oil producing countries;
	§		the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
	§		the level of demand and the price and availability of alternative fuels;
	§		speculation in the commodity futures markets;
	§		technological advances affecting energy consumption;
	§		domestic and foreign governmental regulations, including regulations imposed by Native American tribes; and
	§		approvals, proximity and capacity of natural gas and oil pipelines and other transportation facilities.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements with any certainty. Declines in natural gas and oil prices would not only reduce our revenues, but could reduce the amount of natural gas and oil we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations. Further, market prices for natural gas and oil do not necessarily move in direct relationship to each other. We are more affected by movements in the price and demand for natural gas, as approximately 92% of our total proved reserves at December 31, 2005 were natural gas.

Our ability to sell assets and replace revenues generated from any sale of our Gulf of Mexico properties depends upon market conditions and numerous uncertainties.

In November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to shift our operating focus onshore. While we have announced the pending sale of the Texas portion of our Gulf of Mexico assets and the sale process for the remaining offshore assets is ongoing, there can be no assurance that we will sell our remaining offshore assets. Although we plan to reinvest the proceeds from any sale of our Gulf of Mexico assets in onshore producing assets, there can be no assurance that we will be able to find suitable properties on attractive terms. Our operating revenues and cash flows are expected to decrease significantly following the sale of these assets and are expected to remain at lower levels until we are able to replace the lost production with production from new properties.

Our level of indebtedness may limit our financial flexibility.

As of December 31, 2005, we had long-term indebtedness of $597 million, with $422 million drawn under our revolving bank credit facility and $175 million of 7% senior subordinated notes. Our long-term indebtedness represented 46% of our total book capitalization at December 31, 2005. As of the date of this Annual Report, outstanding borrowings under our revolving bank credit facility were $407 million.

Our level of indebtedness affects our operations in several ways, including the following:

	§		a portion of our cash flows from operating activities must be used to service our debt and is therefore not available for other purposes;
	§		we may be at a competitive disadvantage as compared to similar companies that have less debt;
	§		the covenants contained in the agreements governing our outstanding debt require us to meet certain financial tests and may limit our ability to borrow additional funds, sell assets, repurchase shares of company stock, pay dividends

			and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
	§		we may not be able to easily divest or exchange our onshore assets because these assets have been mortgaged to secure borrowings under our revolving bank credit facility;
	§		additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants; and,
	§		changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing.

We may incur additional debt in order to make future acquisitions or develop our properties. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt service obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

We may be required to take writedowns if natural gas and oil prices decline.

We may be required under full cost accounting rules to write down the carrying value of our natural gas and oil properties if natural gas and oil prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results.

We utilize the full cost method of accounting for natural gas and oil exploration and development activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of our natural gas and oil properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges, calculated using prevailing prices on the last day of the period. If the net book value of our natural gas and oil properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds our ceiling limitation, SEC regulations require us to impair or “writedown” the book value of our natural gas and oil properties. Depending on the magnitude of any future impairments, a ceiling test writedown could significantly reduce our income, or produce a loss. As ceiling test computations involve the prevailing price on the last day of the quarter, it is impossible to predict the timing and magnitude of any future impairments. The book value of our proved natural gas and oil properties increased in 2005 as a function of our higher acquisition, exploration and development costs for the year and the increase in future development costs associated with reserves added during the year. To the extent our finding and development costs continue to increase as we expect, we will become more susceptible to ceiling test writedowns in low price environments.

Lower natural gas and oil prices could negatively impact our ability to borrow.

The amount of borrowings available to us under our revolving bank credit facility is determined by reference to a borrowing base. The amount of our borrowing base is established by our banks and is primarily a function of the quantity and value of our reserves. Our borrowing base is re-determined at least twice a year to take into account changes in our reserve base and prevailing commodity prices. Our current borrowing base is $600 million and is expected to be reduced upon completion of the pending sale of the Texas portion of our Gulf of Mexico assets and likely would be reduced further upon any sale of our remaining Gulf of Mexico assets. Commodity prices can affect both the value as well as the quantity of our reserves for borrowing base purposes as certain reserves may not be economic at lower price levels. Additionally, the indenture governing our 7% senior subordinated notes due 2013 conditions our ability to incur additional indebtedness on our satisfaction of tests relating to “earnings before interest, taxes and depreciation, depletion and amortization expense” and “consolidated net tangible assets” (as defined in the indenture), both of which are sensitive to commodity prices. Consequently, the amount of borrowing available to us under our revolving bank credit facility as well as our ability to incur additional indebtedness without violating the indenture governing our senior subordinated notes could be adversely affected by extended periods of low commodity prices.

Our hedging activities have resulted in financial losses and reduced our income and may continue to do so in the future.

To achieve more predictable cash flow and to reduce our exposure to downward fluctuations in the prices of natural gas, we have historically entered into hedging arrangements for a significant portion, between 70% and 80%, of our production. As

of the date of our Annual Report, we have approximately 250 MMBtu per day, or approximately 75% of our projected 2006 natural gas production hedged and less than 10%, or 30 MMBtu per day and 20 MMBtu per day, respectively, hedged for 2007 and 2008. In connection with the possible divestiture of our Gulf of Mexico assets, and after taking into account the impact of any such sale on our production levels and any acquisitions that appear imminent at the time of any such sale, we may and may be required under our revolving bank credit facility to liquidate a portion of our 2006 hedge position. Specifically, if we were to sell all of our Gulf of Mexico assets, we estimate that we would liquidate at least 70 MMBtu per day. Depending on prices in effect at the time of liquidation, we could be required to make a significant payment to settle the open contracts, which payment we would expect to finance with proceeds from the sale of any Gulf of Mexico assets and/or borrowings under our revolving bank credit facility.

The derivative instruments that we typically employ require us to make cash payments to the extent the NYMEX price exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in natural gas prices. As we typically tie our derivative instruments to NYMEX prices as opposed to the local indices where we sell our gas, our hedging strategy may not protect our cash flows if basis differentials increase between the NYMEX and local prices. Under SFAS 133, our income could be negatively affected to the extent our NYMEX-based derivative instruments are deemed ineffective in hedging price fluctuations at our sales points. Historically, our basis differential between the NYMEX price and the Houston Ship Channel index, where approximately 30% of our production is hedged, averaged not more than $0.30 per MMBtu. However, market conditions and extreme price volatility during the fourth quarter of 2005 created in the aftermath of Hurricanes Katrina and Rita, caused our average basis differential to increase to $2.40 per MMBtu, causing us to realize significantly lower sales prices for natural gas during the fourth quarter of 2005. In addition, this extreme widening of the basis differential between NYMEX and Houston Ship Channel created a loss of correlation. As a result, our hedged production allocated to the Houston Ship Channel index failed to qualify for hedge accounting. We were required to recognize the change in the fair value of these contracts during the fourth quarter of 2005 as an unrealized gain of $26.1 million ($16.9 million net of tax) in fourth quarter earnings. In future periods, our earnings could fluctuate significantly if these contracts can not be re-designated as cash flow hedges as the mark-to-market changes in the fair value at the end of each future period would be recognized in the income statement. Further, if we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction in our liquidity as was the case during the fourth quarter of 2005 when offshore production was significantly curtailed due to Hurricanes Katrina and Rita. Finally, another risk of hedging activities is that the counterparty in any derivative transaction cannot or will not perform under the hedge contract and that we will not realize the benefit of the hedge.

The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves at a faster rate than companies whose reserves have longer-life production profiles.

Our proved reserve quantities decline as they are produced. To prevent decline in our reserve base, we must conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Virtually all of our onshore production is located in prolific natural gas producing regions where completion techniques result in hyperbolic production decline profiles characterized by high initial production rates, followed by rapid intermediate production declines, and culminating in a long-term low production rate subject to a shallow decline. Likewise, our offshore production (as to which we are pursuing a sale) is generally characterized by small reservoirs with high porosity and permeability that produce at very high rates but typically deplete rapidly. Because of the high-rate production profiles of our properties, replacing produced reserves is more important for us than for companies whose reserves have longer-life production profiles. This imposes greater reinvestment risk for our company as we may not be able to continue to replace our reserves or may not be able to do so at an acceptable finding cost.

Rising finding and development costs may impair our profitability.

In order to continue to grow and to maintain our profitability, we must annually add new reserves exceeding our yearly production at a finding and development cost that yields an acceptable operating margin and depreciation, depletion and amortization rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most gas basins in North America combined with an overall increase in the demand for domestic production, the cost of finding new reserves through exploration and development operations has been increasing. As commodity prices have continued to remain strong, the costs for materials, equipment and services have increased. The acquisition market for natural gas properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values on a per unit basis are at or near record levels in certain areas, particularly in our focus areas of South Texas and the Rocky Mountain regions, and we believe these values may continue to increase in 2006. For full cost companies such as

ours, this increase in finding and development costs results in higher depreciation, depletion and amortization rates. If finding and development costs continue to increase, we and other full cost companies will be exposed to an increased likelihood of a writedown in carrying value of our natural gas and oil properties in response to falling prices, which would impair our profitability.

The success of our business depends upon our ability to find, replace, develop and acquire natural gas and oil reserves.

Without successful exploration, development or acquisition activities, our oil and gas reserves and our revenues will decline over time. In addition, we may not be able to maintain our current cost structure while continuing to operate in mature producing basins. It is becoming more difficult to find, replace and develop new reserves at historical costs. The continuing development of reserves and acquisition activities require significant expenditures. Our cash flow from operations may not be sufficient for this purpose, and we may not be able to obtain the necessary funds from other sources. In addition, as discussed above, if we are not able to replace reserves, the amount of credit available to us may decrease since the amount of borrowing capacity available under our revolving bank credit facility is based, in large part, on the estimated quantities of our proved reserves.

Estimates of proved reserves and future net revenue may change if the assumptions on which such estimates are based prove to be inaccurate.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment and the assumptions used regarding prices for oil and natural gas, production volumes, required levels of operating and capital expenditures, and quantities of recoverable natural gas and oil reserves. Natural gas and oil prices have fluctuated widely in recent years. Volatility is expected to continue and price fluctuations directly affect estimated quantities of proved reserves and future net revenues. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and these variances may be significant. Also, we make certain assumptions regarding future natural gas and oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from the assumptions used could result in the actual quantity of our reserves and future net cash flow being materially different from the estimates in our reserve reports. In addition, actual results of drilling, testing and production and changes in natural gas and oil prices after the date of the estimate may result in revisions to our reserve estimates. Revisions to prior estimates may be material. During 2005 and 2004, we incurred downward revisions of our proved reserves of 60 Bcfe and 20 Bcfe, respectively, either from proved undeveloped reserves that were determined to be depleted or otherwise not recoverable, or from production performance indicating less gas in place or smaller reservoir size than initially estimated.

We may not be able to meet our substantial capital requirements.

Our business is capital intensive. To maintain or increase our base of proved oil and gas reserves, we must invest a significant amount of cash flow from operations in property acquisitions, development and exploration activities. We are currently making and will continue to make substantial capital expenditures to find, develop, acquire and produce natural gas and oil reserves. If our revenues or borrowing base under our revolving bank credit facility decrease as a result of lower natural gas and oil prices, operating difficulties or declines in reserves, we may not be able to expend the capital necessary to undertake or complete future drilling programs or acquisition opportunities unless we raise additional funds through debt or equity financings. We may not be able to obtain such debt or equity financings, and cash generated by operations or available under our revolving bank credit facility may not be sufficient to meet our capital requirements.

Our business involves many operating risks that can cause substantial losses; insurance may not protect us against all these risks.

In our operations we may experience hazards and risks inherent in drilling for, producing and transporting natural gas and oil. These hazards and risks may result in loss of hydrocarbons, environmental pollution, personal injury claims, and other damage to our properties and third parties and include:

	§		fires;
	§		natural disasters, including tropical storms, hurricanes and other adverse weather conditions;
	§		explosions;
	§		encountering formations with abnormal pressures;

	§		encountering unusual or unexpected geological formations;
	§		blowouts;
	§		cratering;
	§		unexpected operational events;
	§		equipment malfunctions;
	§		pipeline ruptures;
	§		spills;
	§		compliance with environmental and government regulations; and
	§		title problems.

We are insured against some, but not all, of the hazards associated with our business.. Because of this practice, we may sustain losses that could be substantial due to events that are not insured or are underinsured. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse impact on our financial condition and results of operations. In addition, because as we do not carry business interruption insurance, the loss and delay of revenues resulting from curtailed production are not insured.

Our reserves, production and cash flow are highly dependent upon operations that are concentrated in a small number of areas.

During 2005, we generated approximately 97% of our production from three primary areas of operation, with 43% from South Texas, 40% from offshore Gulf of Mexico and 14% from the Arkoma Basin. As we pursue divesting our Gulf of Mexico assets, our operations could become even more geographically concentrated. The concentrated nature of our operations subjects us to the risk that a regional event could cause a significant interruption in our production or otherwise have a material affect on our profitability. This is particularly true of our offshore operations, which are susceptible to hurricanes and other tropical weather disturbances, some of which can be severe enough to cause substantial damage to facilities and production infrastructure. During 2005, we estimate that approximately 10.6 Bcfe of offshore production was either curtailed or delayed as a result of infrastructure damage to third party pipelines and processing facilities caused by Hurricanes Katrina and Rita that struck the Texas and Louisiana coasts during August and September.

Drilling natural gas and oil wells is a high risk activity and subjects us to a variety of factors that we cannot control.

Our drilling activities subject us to many risks, including the risk that we will not find commercially productive reservoirs. Drilling for natural gas and oil can be unprofitable, not only from dry wells, but also from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements and shortages or delays in the delivery of equipment and services can delay our drilling operations or result in their cancellation. The cost of drilling, completing and operating wells is often uncertain, and new wells may not be productive. As a result, we may not recover all or any portion of our investment.

The availability and cost of rigs, equipment, and personnel could adversely affect our profitability and level of operations.

Driven by attractive commodity prices, domestic drilling activity measured as a function of rig utilization has been at very high levels during the past two to three-year period. Given this extended strong demand for drilling rigs and other oil field services necessary to our operation, we experienced increased service and material costs, as well as longer lead times and reduced service availability. We anticipate that this trend will continue in 2006. If current utilization rates continue at levels seen during 2005 or increase, a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop, especially in the areas where we operate. The costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. If we do not have access to necessary oil field services at a reasonable cost, we could be forced to curtail certain operations and the profitability of those operations that we do conduct could be materially impaired.

Our business depends on oil and natural gas transportation facilities that are owned by others.

The marketability of our natural gas and oil production depends, in part, on the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these systems and related facilities could result in the shut-in of our producing wells or the delay or discontinuation of development plans for our properties. During 2005, we estimate that approximately 10.6 Bcfe of offshore production was curtailed and delayed due damage to third-party pipelines

and processing facilities as a result of damage to Gulf of Mexico infrastructure after Hurricanes Katrina and Rita that struck the Texas and Louisiana coasts during August and September of 2005. Although we have some control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Our acquisition and investment activities may be unsuccessful and costly.

The successful acquisition of producing properties requires assessment of reserves, future commodity prices, operating costs and potential environmental and other liabilities. These assessments may not be accurate. Our review of the properties we intend to acquire may not reveal all existing or potential problems nor allow us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not always perform inspections on every property or well, and structural or environmental problems may not be observable even when an inspection is undertaken. Accordingly, we may suffer the loss of one or more acquired properties due to title deficiencies or may be required to make significant expenditures to cure environmental contamination or other problems with respect to acquired properties. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are generally not entitled to contractual indemnification for environmental liabilities and we typically acquire structures on a property on an “as is” basis.

Our ability to maximize tax efficiencies with tax free asset exchange transactions following the pending sale of our Gulf of Mexico assets is uncertain.

There are numerous uncertainties surrounding our ability to reinvest the proceeds from the pending sale of the Texas portion of our Gulf of Mexico assets and any subsequent sale of the remaining portion of our offshore assets into onshore natural gas and oil assets, including our ability to structure the reinvestment in such a manner and within the required time frame such that it qualifies as a tax-free exchange under Section 1031 of the Internal Revenue Code. In the event we are not able to reinvest the proceeds from the pending sale and any subsequent sale within the time period prescribed under Section 1031, we will bear the cost of the resulting tax liability, which could be significant.

Our investments in the Rocky Mountains may not be successful.

Our future growth plans rely in part on establishing significant production and reserves in the Rocky Mountains, particularly the Uinta Basin in Utah and the DJ Basin in Colorado. To date, we lack sufficient production history from these areas to accurately estimate the likelihood that our endeavors will yield meaningful reserves and production with an acceptable rate of return. Certain of our exploration objectives in the Rocky Mountain area involve geology types and mechanical operations that differ substantially from our historic operations in South Texas and the Arkoma Basin. In addition, operations in the Rocky Mountain region present unique operational challenges, such as more acute transportation constraints, higher pricing differentials, and more extensive regulatory oversight. Increased drilling in the vicinity of our Rocky Mountain acreage has also resulted in the Bureau of Land Management (“BLM”) increasingly requiring the preparation of environmental assessments or more comprehensive environmental impact statements, as a condition to conducting operations on certain lands that the BLM administers. Any or all of these contingencies could delay or halt our drilling activities or the construction of ancillary facilities necessary for production, which would prevent us from developing our property interests in the Rocky Mountains as planned and impede our growth.

We may incur substantial costs to comply with costly and stringent environmental and other governmental laws and regulations.

Our exploration and production operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and/or the issuance of injunctions limiting or prohibiting our operations. However, environmental laws and regulations, including those that may at some time arise to address global climate change or facility security concerns, are expected to continue to have an increasingly costly and stringent impact on our operations resulting in substantial costs and liabilities in the future.

We currently own and lease, and have in the past owned or leased, numerous properties that have been used for the exploration and production of oil and natural gas for many years. Although we believe we have used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, petroleum hydrocarbons or wastes may have been disposed of or released by prior operators

of properties that we have acquired or may acquire in the future as well as by current third party operators of properties in which we have an ownership interest. Properties impacted by any such disposals or releases could be subject to costly and stringent investigatory or remedial requirements under environmental laws, some of which impose strict, joint and several liability without regard to fault or the legality of the original conduct, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, the federal Oil Pollution Act,” the federal Resource Conservation and Recovery Act and analogous state laws. Under such laws and any implementing regulations, we could be required to remediate contaminated properties and take actions to compensate for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the release of petroleum hydrocarbons or wastes into the environment.

We face strong competition.

As an independent natural gas and oil producer, we face strong competition in all aspects of our business. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas reserves. There is also competition for the rigs and related equipment and services that are necessary for us to develop and operate our natural gas and oil properties. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, field services and qualified oil and gas professionals with major and diversified energy companies and other independent operators that have financial, human and technological resources greater than ours. These companies may be able to pay more for productive natural gas and oil properties and exploratory prospects and to more successfully define, evaluate, bid for and purchase properties and prospects than our financial and human resources permit. In addition, our competitors may have an advantage due to their geographic focus and their mix of oil and natural gas reserves.

The inability of one or more of our customers to meet its obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from natural gas and oil sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

Provisions in our Charter, Agreements, Stockholder Rights Plan and Delaware Law May Inhibit a Takeover of Houston Exploration.

Under our Restated Certificate of Incorporation, our Board of Directors is authorized to issue shares of our common or preferred stock without approval of our stockholders. Issuance of these shares could make it more difficult to acquire our company without the approval of our Board of Directors as more shares would have to be acquired to gain control. We also have a stockholder rights plan, commonly known as a “poison pill,” that entitles our stockholders to acquire additional shares of our company, or a potential acquirer of our company, at a substantial discount from market value in the event of an attempted takeover without the approval of our Board. In 2005, we amended our rights plan to increase the ownership triggering threshold from 10% to 15%. The indenture governing our 7% senior subordinated notes due 2013 also contains change of control provisions that, among other things, allow the holders of the notes to require us to repurchase them at 101% of their principal amount, and a change of control constitutes a default under our revolving bank credit facility. Finally, Delaware law imposes restrictions on mergers and other business combinations between us and a holder of 15% or more of our outstanding common stock under certain circumstances. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our stockholders.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties (see Item 1. Business and Properties)

Item 3. Legal Proceedings

We currently are not a party to any material pending legal or governmental proceedings, other than ordinary and routine litigation incidental to our business. While the ultimate outcome and impact of this litigation cannot be predicted with certainty, our management believes that the resolution of any such litigation will not have a material adverse effect on our financial condition or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of our security holders during the last quarter of the fiscal year ended December 31, 2005.

Part II.

Item 5. Market for the Registrant’s Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is traded on the New York Stock Exchange under the symbol “THX.” The following table sets forth the range of high and low sales prices for each calendar quarterly period from January 1, 2004, through December 31, 2005 as reported on the New York Stock Exchange:

Year Ended December 31, 2005		High				Low
First Quarter		$	62.29			$	51.14
Second Quarter			59.40				45.60
Third Quarter			71.47				53.30
Fourth Quarter			67.83				49.86

Year Ended December 31, 2004		High				Low
First Quarter		$	45.85			$	35.79
Second Quarter			52.47				41.40
Third Quarter			59.79				48.30
Fourth Quarter			61.80				53.65

As of March 1, 2006, 29,067,430 shares of common stock were outstanding, and we had approximately 51 stockholders of record and approximately 30,000 beneficial owners.

Dividends

We have not declared or paid any cash dividends and do not anticipate declaring any dividends in the foreseeable future. We plan to retain our cash for the operation and expansion of our business, including exploration, development and acquisition activities, retirement of debt or repurchase of our common stock. In addition, our revolving bank credit facility and the indenture governing our 7% senior subordinated notes due June 15, 2013, contain restrictions on the payment of dividends to holders of common stock. For more information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Consolidated Financial Statements, Note 2 – Long-term debt.

Item 6. Selected Financial Data

The following table shows selected financial data derived from our consolidated financial statements for each of the five years in the period ended December 31, 2005. You should read these financial data in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and the related Notes.

		Years Ended December 31,
		2005				2004				2003				2002				2001
		(in thousands, except per share data)
Income Statement Data:
Revenues:
Natural gas and oil revenues		$	620,271			$	649,087			$	491,440			$	344,295			$	387,156
Other			1,272				1,352				1,312				1,086				1,353
Total revenues			621,543				650,439				492,752				345,381				388,509
Expenses:
Lease operating expense			67,796				55,925				47,072				33,976				25,291
Severance tax			18,121				11,933				15,958				9,487				11,035
Transportation expense			11,883				11,819				10,387				9,317				7,652
Asset retirement accretion expense(1)			5,278				4,902				3,668				—				—
Depreciation, depletion and amortization			295,351				265,148				197,530				171,610				128,736
Writedown in carrying value			—				—				—				—				6,170
General and administrative, net			38,378				32,899				19,542				13,077				17,110
Total operating expenses			436,807				382,626				294,157				237,467				195,994
Income from operations			184,736				267,813				198,595				107,914				192,515
Other (income) expense (2)			142				(1,058	)			(15,746	)			(9,070	)			119
Interest expense, net			16,535				9,455				8,342				7,398				2,992
Income before income taxes			168,059				259,416				205,999				109,586				189,404
Income tax provision			62,890				96,592				72,187				39,092				66,803
Income before cumulative effect of change in accounting principle		$	105,169			$	162,824			$	133,812			$	70,494			$	122,601
Cumulative effect of change in accounting principle (3)			—				—				(2,772	)			—				—
Net income		$	105,169			$	162,824			$	131,040			$	70,494			$	122,601
Earnings per share:
Basic:
Income per share before cumulative effect of change in accounting principle change		$	3.66			$	5.50			$	4.30			$	2.31			$	4.06
Cumulative effect of change in accounting principle (3)			—				—				(0.09	)			—				—
Net income per share — basic		$	3.66			$	5.50			$	4.21			$	2.31			$	4.06
Diluted:
Income per share before cumulative effect of change in accounting principle		$	3.62			$	5.44			$	4.29			$	2.28			$	4.00
Cumulative effect of change in accounting principle (3)							—				(0.09	)			—				—
Net income per share — diluted		$	3.62			$	5.44			$	4.20			$	2.28			$	4.00
Weighted average shares — basic			28,707				29,616				31,097				30,569				30,228
Weighted average shares — diluted			29,037				29,932				31,213				30,878				30,645
Ratio of earnings to fixed charges (4)			7.2	x			15.0	x			13.6	x			7.6	x			12.8	x

		Years Ended December 31,
		2005				2004				2003				2002				2001
		(in thousands)
Cash Flow Data:
Net cash provided by operating activities		$	460,509			$	527,141			$	381,969			$	243,601			$	355,311
Net cash used in investing activities			727,003				509,922				452,959				252,857				365,556
Net cash provided by (used in)financing activities			255,896				(1,211	)			55,528				17,668				9,189

		At December 31,
		2005				2004				2003				2002				2001
		(in thousands)
Balance Sheet Data:
Working capital (deficit) (5)		$	(214,525	)		$	(31,884	)		$	(36	)		$	10,550			$	34,314
Property, plant and equipment, net			2,018,340				1,548,256				1,371,129				1,022,414				938,761
Total assets			2,361,624				1,722,577				1,509,065				1,151,068				1,059,092
Long-term debt and notes			597,000				355,000				302,000				252,000				244,000
Stockholders’ equity			693,138				782,920				735,534				592,789				565,881

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist you in understanding our business and the results of operations together with our present financial condition. This section should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K.

Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. See “Forward-Looking Statements” at the beginning of this Annual Report and “Item 1A. Risk Factors” beginning on page 15 for additional discussion of some of these factors and risks.

Overview of Our Business

We are an independent natural gas and oil producer concentrating on growing reserves and production through the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and oil on behalf of KeySpan Corporation, our then parent company. KeySpan is a diversified energy provider whose principal natural gas distribution and electric generation operations are located in the Northeastern United States. In September 1996, we completed our initial public offering and sold approximately 31% of our shares to the public. Through three separate transactions, the first in February 2003 and last in November 2004, KeySpan completely divested its investment in the common stock of our company. See Note 3 — Stockholders’ Equity for a complete description of these three transactions.

At December 31, 2005, we had operations in five producing regions within the United States: South Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; the Uinta and DJ Basins in the Rocky Mountains; and the Gulf of Mexico.

Our total net proved reserves as of December 31, 2005 were 861 billion cubic feet equivalent or Bcfe, with onshore reserves totaling 616 Bcfe. Our reserves are fully engineered on an annual basis by independent petroleum engineers. Approximately 64% of our proved reserves at December 31, 2005, were classified as proved developed. Our daily production during 2005 averaged 313 million cubic feet of natural gas equivalent or MMcfe and was significantly curtailed during the last four months of 2005 and into the first quarter of 2006 primarily as a result of infrastructure damage to third party pipelines and processing facilities caused by Hurricanes Katrina and Rita that hit the Louisiana and Texas coasts in August and September 2005.

We derive our revenues from the sale of natural gas and oil that is produced from our natural gas and oil properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of natural gas is the primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we have historically utilized derivative instruments to hedge future sales prices on a significant portion of our natural gas production. During 2005, 2004 and 2003, the use of derivative instruments prevented us from realizing the full benefit of upward price movements and may continue to do so in future periods.

We operate as one segment as all of our assets are based in North American and each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information.”

In November 2005, we announced our intent to explore the sale of our Gulf of Mexico assets and to shift our operating focus onshore. At December 31, 2005, our offshore reserves totaled 245 Bcfe, or 28% of our total proved reserves. Historically, production from our offshore properties has averaged 40% to 45% of total production. Our offshore properties are located in the shallow waters of the Outer Continental Shelf. Key producing properties are located in the western and central Gulf of Mexico and include the Mustang Island, Matagorda Island, Galveston Island, High Island, East Cameron, West Cameron, Eugene Island and Main Pass areas. At December 31, 2005, we held interests in 136 blocks in federal and state waters, of which 78 were developed. We had a total of 97 producing platforms and production caissons, of which we operated 61. During 2005, offshore production averaged 125 MMcfe/day, and immediately prior to shut-ins caused by Hurricanes Katrina and Rita, averaged an estimated 155 MMcfe/day. For December 2005, offshore production averaged 123 MMcfe per day with several fields still curtailed.

On February 28, 2006, we entered into an agreement to sell the Texas portion of our Gulf of Mexico assets to certain partnerships affiliated with Merit Energy Company for $220 million in cash, subject to adjustment and customary closing conditions. The transaction is scheduled to close on or about March 31, 2006, with an effective date of January 1, 2006. We expect to use the proceeds from the sale of the Texas portion of our Gulf of Mexico assets primarily to acquire longer-lived natural gas assets onshore in North America and to repay existing debt. There can be no assurances that we will be able to find suitable properties on attractive terms. Our operating revenues and cash flows are expected to decrease following the sale of these assets and are expected to remain at lower levels until we are able to replace the lost production with production from new properties. Where possible, we plan to structure our asset reinvestment to minimize taxes on any gain realized from the sale. The sale process with respect to our remaining Gulf of Mexico assets is ongoing. If a sale is not consummated, we expect to continue to operate and may consider other strategic alternatives with respect to these remaining offshore assets. The Texas portion of our Gulf of Mexico assets accounted for approximately 18% of our 2005 production and represented 58.5 Bcfe, or 7% of our total proved reserves, at December 31, 2005. At December 31, 2005, we held interests in 70 blocks in offshore Texas state and federal waters, of which 33 were developed. Our assets included 38 producing platforms and production caissons.

The pending sale of the Texas portion of our Gulf of Mexico assets and any subsequent sale of the remaining portion of our Gulf of Mexico assets will result in the reclassification of the fair value of the derivative obligations allocated to offshore production from accumulated other comprehensive income to earnings. At December 31, 2005, the fair value of derivative obligations allocated to offshore production for years 2006, 2007 and 2008 was a liability of $182.7 million ($118.0 million net of tax) which approximates the amount deferred in accumulated other comprehensive income at the end of the period. The ultimate amount of this reclassification and possible charge against earnings will depend on the fair value of the obligations at the time that receipt of offshore production allocated to these hedges no longer appears probable. This reclassification and possible charge to earnings will not affect cash flow.

In connection with the possible divestiture of our Gulf of Mexico assets, and after taking into account the impact of any such sale on our production levels and any acquisitions that appear imminent at the time of any such sale, we may and may be required under our revolving bank credit facility to liquidate a portion of our 2006 hedge position allocated to offshore production. If we were to sell all of our Gulf of Mexico assets, we estimate that we would liquidate at least 70 MMBtu per day of hedged production. Depending on prices in effect at the time of liquidation, we could be required to make a significant payment to unwind and settle the open contracts, which payment we would expect to finance with proceeds from the sale of any Gulf of Mexico assets and/or borrowings under our revolving bank credit facility.

Recent Acquisition

As part of the plan to shift our operational focus onshore, on November 30, 2005, we completed the acquisition of certain interests in natural gas and oil producing properties and undeveloped acreage in four fields located in South Texas from Kerr-McGee Oil & Gas Onshore LP and Westport Oil and Gas Company, L.P. The net purchase price of $159.0 million was paid in cash and financed by borrowings under our revolving bank credit facility. The properties cover approximately 26,000 net acres, include approximately 300 wells and are located in the Rincon Field in Starr County, the Tijerina-Canales-Blucher Field in Jim Wells and Kleberg Counties, the Vaquillas Ranch Field in Webb County, and the San Carlos Field in Hidalgo County. At December 31, 2005, the proved reserves attributed to these properties were approximately 62 Bcfe, of which approximately 75% were natural gas. Current production from the four fields is estimated at approximately 10 MMcfe/day, net to the interests to be acquired. We operate 100% percent of the proved reserves with an average working interest of 60%.

Industry Outlook

We currently operate in North America and we believe this region is maturing and production growth is slowing or possibly declining. While new discoveries are still being made in North America, the frequency and size of these discoveries is declining as finding and developing costs are increasing. We believe domestic natural gas and oil production may be at or near its peak and can be expected to decline in the future, with the exception of relatively unexplored onshore regions such as the Rocky Mountains.

Our future success in growing our reserve base at an acceptable finding cost will depend in large part on our ability to acquire new proved reserves and unevaluated acreage which we can explore and exploit. We maintain an active acquisition program and expect to continue to devote significant resources to identifying and pursuing both tactical acquisitions that are designed to expand our operations within an existing core area as well as strategic acquisitions involving one or more new onshore regions.

We anticipate that the continued decline of the North American gas basins will lead to higher cost structures throughout our industry. We believe that the cost of finding, developing and producing new natural gas and oil reserves through exploration and development operations will rise as the industry makes fewer discoveries and such discoveries generally

will be of smaller average reserve size. In addition, the acquisition market for natural gas properties has become extremely competitive as producers vie for additional production and expanded drilling opportunities in North America. For full cost companies such as ours, increases in both acquisition and finding and development costs are expected to yield higher depreciation, depletion and amortization rates and ultimately could increase the likelihood of a writedown in the carrying value of our natural gas and oil properties if commodity prices fall substantially below current levels as we continue to add costs to our pool at higher rates with the addition of fewer new reserves to the amortization base. In addition, we expect drilling costs and lease operating expenses to continue to increase as producers are required to make operational enhancements to maintain aging fields.

Natural gas is a commodity. As such, the price that we receive for the natural gas we produce is largely a function of market supply and demand. Demand for natural gas in the United States has increased dramatically over the last ten years, as many industrial users have gradually switched to a cleaner burning and historically cheaper fuel. Demand will be impacted by general economic conditions, estimates of gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms.

Market conditions involving over or under supply of natural gas can result in substantial price volatility. Continued concerns over the United States’ ability to meet its longer-term gas needs from declining domestic supply have resulted in sustained prices above $5.00 throughout 2003, 2004 and 2005. As a direct result of the strong commodity prices during the last three-year period, we were able to generate substantial cash flows to fund our exploration and development program. However, historically, commodity prices have been very volatile, and we expect the volatility to continue in the future. In fact, the NYMEX closing price for natural gas changed from $6.123 per MMbtu for June 2005 to $13.832 per MMBtu for October and again to $7.112 per MMBtu for March 2006. As a result, we cannot accurately predict future natural gas and oil prices, and, therefore, we cannot determine what effect increases or decreases will have on our future revenues and cash flows. A substantial or extended decline in natural gas and oil prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas and oil reserves that may be economically produced and our ability to access capital markets. Our continued growth and profitability depends on the strength of natural gas prices and our ability to acquire, find and develop new reserves at economical costs.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make assumptions and prepare estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and revenues and expenses. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ. We evaluate our assumptions and estimates on a regular basis and discuss the development and disclosure process with our Audit Committee. See Note 1 — Summary of Organization and Significant Accounting Policies of Item 8 contained in this Form 10-K for a discussion of our significant accounting policies.

Proved Reserves. Our reserves are fully engineered on an annual basis by independent petroleum engineers. Our estimates of proved reserves are based on the quantities of natural gas and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond our control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2005 and 2004, we revised our proved reserves downward from prior years’ reports by approximately 60 Bcfe and 20 Bcfe, respectively, due to proved undeveloped reserves that were determined to be depleted or otherwise not recoverable, or from production performance indicating less gas in place or smaller reservoir size than initially estimated. Estimates of proved reserves are key components of our most significant financial estimates involving our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation.

Unevaluated Properties. The balance of unevaluated properties is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress, wells pending determination and related capitalized interest. These costs are initially excluded from our amortization base until the outcome of the project has been determined, or generally, until it is known whether proved reserves will or will not be assigned to the property. We assess all items in our

unevaluated property balance on a quarterly basis for possible impairment or reduction in value. We believe that substantially all of the costs included in our unevaluated property balance will be evaluated in the next four years.

Asset Retirement Obligations. Asset retirement obligations represent the estimated future abandonment costs of tangible long-lived assets such as platforms, wells, service assets, pipelines, and other facilities. We estimate the fair value of an asset’s retirement obligation in the period in which the liability is incurred, if a reasonable estimate can be made. We employ a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions, including an inflation rate, our credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third party quotes and current actual costs. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.

Derivative Instruments. Historically, our derivative contracts have qualified for hedge accounting under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Accordingly, we reflect the fair market value of our derivative instruments on our balance sheet. Fair value is accessed and measured and is estimated by obtaining independent market quotes from counterparties, as well as utilizing the Black-1976 option valuation model that is based upon underlying forward price curve data, a risk-free interest rate and estimated volatility factors. In addition, forward price curves and estimates of future volatility factors are used to access and measure the ineffectiveness of our open contracts at the end of each period. If open contracts cease to qualify for hedge accounting, the mark-to-market change in the fair value is recognized in the income statement. Loss of hedge accounting and cash flow designation will cause volatility in earnings. The fair values we report in our financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

Taxes. We are subject to income taxes at the federal level and in the states where we operate. Significant judgment is required in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows.

Stock Compensation Expense. We account for stock-based compensation in accordance with the fair value recognition provisions of SFAS 123, “Accounting for Stock-Based Compensation.” Under the fair value recognition provisions of SFAS 123, stock-based compensation cost is measured at the grant date based on the value of the award and is recognized as expense over the vesting period. We utilize the Black-Scholes option pricing model to determine the fair value of stock-based awards on the grant date which requires judgment in estimating the expected life of the option and the expected volatility of our stock. Actual results could differ significantly from these estimates and these differences could materially impact our financial position, results of operations and cash flows. See New Accounting Pronouncements below.

In addition to the critical estimates discussed above, estimates are used in accounting and computing depreciation, depletion and amortization, the full cost ceiling, accruals of operating costs and production revenues.

New Accounting Pronouncements

On December 16, 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which requires the measurement and recognition of compensation expense for all stock-based compensation payments and the current accounting under SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” For us, SFAS 123(R) is effective for our first fiscal year beginning after June 15, 2005, or January 1, 2006.

On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” using the “prospective method” as defined by the SFAS 148. As a result, we have recognized compensation expense for all stock options granted subsequent to January 1, 2003, with no expense recognized for grants made prior to 2003. With the adoption of SFAS 123(R), we will recognize compensation expense over the remaining service period for the unvested portion of all options granted during 2001 and 2002. All options granted prior to 2001 are fully vested. We adopted SFAS 123(R) on January 1, 2006, using the modified version of the prospective application. We plan to continue using the Black-Scholes option pricing model to estimate the fair value of our options on the date of grant. Based on current estimates, we expect to incur additional stock compensation expense for grants made prior to our initial adoption of SFAS 123, and not vested as of January 1, 2006 of $2.0 million ($1.5 million net of amounts capitalized) during 2006 and $0.9 million ($0.7 net of amounts capitalized) during 2007, with all prior awards being fully expensed by December 31, 2007. We do not believe the adoption of SFAS 123(R) will have a material impact on our financial statements.

In March 2005, the SEC released Staff Accounting Bulletin (“SAB”) 107 providing additional guidance in applying the provisions of SFAS 123(R), “Share-Based Payment.” SAB 107 should be applied when adopting SFAS 123(R) and addresses a wide range of issues, focusing on valuation methodologies and the selection of assumptions. In addition, SAB 107 addresses the interaction of SFAS 123(R) with existing SEC guidance.

Overview of 2005 Results

Our results for 2005 were significantly impacted by the physical damage to the Gulf of Mexico infrastructure and the resulting market uncertainties caused by Hurricane Katrina in August and Hurricane Rita in September. Rita’s path cut directly through our Gulf of Mexico operations. While our physical facilities incurred relatively minor damage, our production during the last four months of the year was significantly curtailed primarily as a result of damage to third party pipelines and processing facilities. Key projects scheduled to add significant new production during the third and fourth quarters of 2005 were further delayed. Curtailed supply throughout the Gulf of Mexico created unprecedented price movements in the natural gas markets. NYMEX prices for natural gas reached record levels which resulted in record revenues that could not be realized in earnings because a significant percentage (more than 85% during the fourth quarter of 2005 as a result of offshore curtailments) of our natural gas production was hedged well below these record prices. In addition, during the fourth quarter of 2005, the basis differential between NYMEX and the Houston Ship Channel widened from an average of $0.30 per MMBtu to an average of $2.40 per MMBtu. Because approximately 30% of our production is allocated to the Houston Ship Channel index, we realized lower sales prices. As commodity prices continued to increase from prior year levels, so did activity levels across the industry, creating an increase in the demand for materials, equipment, rigs and services. As a result, we experienced a significant increase in our finding and development costs as well as our lease operating expenses during 2005. These factors, combined with an increase in debt were the primary drivers behind results of operations, net income and cash flows during 2005. During 2005:

	§		We incurred relatively minor structural damage from Hurricanes Katrina and Rita and expect to spend a maximum of $35 million for hurricane related repairs. We anticipate these losses in excess of our deductible will be covered by insurance. As we do not carry business interruption insurance, the delay of revenues resulting from curtailed and delayed production is not covered. We estimate the curtailment of production and drilling delays resulting directly from the storms impacted operating revenues in 2005 by an estimated $132 million. Revenues are expected to be further impacted during the first quarter of 2006 as we wait for repairs to third-party pipelines and processing facilities, with restoration expected by the end of the first quarter of 2006;
	§		We announced our intent to explore the sale of our Gulf of Mexico assets and to shift our operating focus onshore. We plan to reinvest the net cash proceeds from the pending sale of the Texas portion of our Gulf of Mexico assets primarily into longer-lived natural gas assets onshore in North America and to retire debt. The pending sale of our offshore Texas assets is expected to close on or about March 31, 2006, with an effective date of January 1, 2006 (see Consolidated Financial Statements, Note 11 — Subsequent Events – Pending Sale of Texas Gulf of Mexico Assets);
	§		We generated $105.2 million in net income, a decrease of 35% from $162.8 million in 2004, primarily as a result of lower revenues caused by production curtailments and $264.5 million in net hedge losses combined with higher depreciation, depletion and amortization expense, general and administrative expense and interest expense;
	§		We produced 114 Bcfe and our average daily production rate was 313 MMcfe per day compared to 339 Mcfe/day during 2004, a decrease of 8%. We estimate that approximately 10.6 Bcfe, or approximately 30 MMcfe per day on an annualized basis, was deferred by hurricane related curtailments and delays;
	§		We increased total net proved reserves by 9% to 861 Bcfe. We added a net 184 Bcfe, which includes 144 Bcfe added through the drill bit and 100 Bcfe added through acquisitions after 60 Bcfe of downward revisions, due primarily to reservoir performance. With the total net additions of 184 Bcfe, we replaced 161% of the 114 Bcfe produced in 2005;
	§		We generated $460.5 million in net cash flows from operating activities compared to $527.1 million during 2004, a decrease of 13%;
	§		We spent $743.3 million for investments in natural gas and oil properties, an increase of 44% over 2004. Our 2005 expenditures included $197.7 million for producing property acquisitions that compares to $149.6 million spent towards acquisitions in 2004, an increase of 32%;
	§		We increased our outstanding borrowings under our revolving bank credit facility by a net $242 million, in part to fund our acquisitions and in part to fund cash requirements for the settlement of derivative contracts;
	§		We drilled 336 wells, of which 298, or 89%, were successful with 12 offshore, 16 in East Texas, 82 in South Texas, 60 in Arkoma and 128 in the Rockies;

	§		We successfully integrated the Gulf of Mexico producing properties acquired in September and October 2004 from BP Exploration & Production Inc. and Orca Energy, L.P., respectively and successfully completed key development projects at Main Pass 264 and Eugene Island 331;
	§		We drilled or participated in drilling of three offshore discoveries that were considered “deep shelf” prospects. The successful wells were drilled at West Cameron 75, West Cameron 77 and West Cameron 62. Additional exploratory successes included Galveston 210 and East Cameron 23;
	§		We expanded our onshore exploration efforts in the DJ Basin with one rig drilling throughout the year and brought on-line our first group of wells during the third quarter of 2005;
	§		We continued our exploration and exploitation efforts in the Uinta Basin with one rig drilling throughout the year and partnered with two separate groups to spread our risk and accelerate our efforts. At year-end, we had three rigs drilling on our acreage. We had a discovery north of the Natural Buttes Field and the well is producing approximately 26 Bbls per day, net to our interests, as of the date of this Annual Report;
	§		We extended our development efforts in the North Roleta Field, located in South Texas, southwest of our operations in the Charco Field, where we began to assemble acreage and drilled a discovery well in 2004. We successfully drilled and completed eight of ten wells and added approximately 17.5 MMcfe per day in production, net to our interests;
	§		We expanded our East Texas acreage through a series of three related acquisitions totaling $38.7 million and added an estimated 38 Bcfe in proved reserves. We successfully integrated these producing properties, added two drilling rigs, successfully drilled 16 development wells which added 13 Bcfe in reserves and increased average daily production in the area from 2 MMcfe per day in January 2005 to 8 MMcfe per day in December 2005 (see Note 10 — Acquisitions and Dispositions);
	§		We acquired producing properties and acreage in four South Texas fields along the Frio and Vicksburg Trends from Kerr-McGee Oil & Gas and Westport at the end of November 2005 for a net $159.0 million and added estimated proved reserves of 62 Bcfe and future exploitation opportunities. We took over operations December 1, 2005 and began to integrate the properties and optimize production rates. Daily production is averaging 10 to 12 MMcfe per day as of the date of this Annual Report. We expect to spud our first well in the Rincon Field in April 2006; (see Note 10 – Acquisitions and Dispositions);
	§		Our depletion rate for natural gas and oil properties increased from $2.30 per Mcfe during the fourth quarter of 2004 to $3.03 per MMcfe during the fourth quarter of 2005, primarily as a result of an industry wide increase in costs. We spent more during 2005 on a per Mcfe basis to find, develop or acquire new reserves and it is projected to cost more to develop our proved reserves as our future development costs increased by $330 million or 60% in 2005 from prior year end;
	§		We incurred $13.7 million in additional general and administrative expenses as a result of special charges, including $5.0 million incurred pursuant to the February 2005 renegotiation of employment agreements with five of our key executive officers, including our Chief Executive Officer, Chief Operating Officer and our then Chief Financial Officer; $4.7 million in outside professional fees attributable to the review of a corporate transaction in the second quarter and an acquisition in the third quarter, both of which were not consummated; and $4.0 million in the fourth quarter related to severance and other separation related payments made to certain former employees, including our former Chief Financial Officer;
	§		As a result of higher market prices for natural gas at December 31, 2005, the fair value of our open derivative contracts increased from a liability of $75.1 million ($48.5 million net of tax) at December 31, 2004, to a liability of $417.7 million ($269.8 million net of tax) at December 31, 2005. During 2005, we incurred a total net loss on our hedging activities of $264.5 million which compares to a total net loss of $70.1 million during 2004. Of our 2005 total net hedging loss, $116.5 million was incurred during the fourth quarter;
	§		Our Board of Directors approved a plan for discretionary stock repurchases from time to time up to $200 million of our common stock in conjunction with the possible divesture of all of our Gulf of Mexico assets and subject to market conditions, applicable legal requirements and contractual restrictions, available cash, competing reinvestment opportunities in the acquisition market for oil and gas assets and other factors; and
	§		We renegotiated our revolving bank credit facility to increase our banks’ lending commitments from $450 million to $750 million. Borrowings under the facility are secured by our onshore natural gas and oil assets as well as certain other assets. Our initial borrowing base has been set at $600 million, which is expected to decrease upon completion of the pending sale of the Texas portion of our Gulf of Mexico assets and likely would be reduced further upon any sale of the remaining portion of our Gulf of Mexico assets.

Operating and Financial Results for 2005 Compared to 2004 and Operating and Financial Results for 2004 Compared to 2003

		Year Ended December 31,																Year Ended December 31,
Summary Operating Information:		2005				2004				Variance								2004				2003				Variance
		(in thousands, except for price data)
Natural gas revenues		$	816,182			$	669,294			$	146,888				22	%		$	669,294			$	522,597			$	146,697				28	%
Oil revenues			68,631				49,938				18,693				37	%			49,938				37,201				12,737				34	%
Gain (loss) on settled derivatives			(265,236	)			(68,195	)			(197,041	)			289	%			(68,195	)			(66,408	)			(1,787	)			3	%
Unrealized gain (loss) derivatives			694				(1,950	)			2,644				-136	%			(1,950	)			(1,950	)			—				—
Operating revenues			621,543				650,439				(28,896	)			-4	%			650,439				492,752				157,687				32	%
Operating expenses			436,807				382,626				54,181				14	%			382,626				294,157				88,469				30	%
Income from operations			184,736				267,813				(83,077	)			-31	%			267,813				198,595				69,218				35	%
Net income			105,169				162,824				(57,655	)			-35	%			162,824				131,040				31,784				24	%
Production:
Natural gas (MMcf)			105,809				115,855				(10,046	)			-9	%			115,855				99,965				15,890				16	%
Oil (MBbls)			1,417				1,355				62				5	%			1,355				1,307				48				4	%
Total (MMcfe) (1)			114,311				123,985				(9,674	)			-8	%			123,985				107,807				16,178				15	%
Average daily production (MMcfe/d)			313				339				(26	)			-8	%			339				295				44				15	%
Average Sales Prices:
Natural Gas (per Mcf) unhedged		$	7.71			$	5.78			$	1.93				33	%		$	5.78			$	5.23			$	0.55				11	%
Natural Gas (per Mcf) realized (2)			5.21			$	5.19				0.02				—				5.19			$	4.57				0.62				14	%
Natural Gas (per Mcf) “all-in” (3)			5.21				5.17				0.04				1	%			5.17				4.55				0.62				14	%
Oil (per Bbl) unhedged			48.43				36.85				11.58				31	%			36.85				28.46				8.39				29	%
Oil (per Bbl) realized (2)			48.43				36.85				11.58				31	%			36.85				28.15				8.70				31	%