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, 2006

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

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, $0.01 par value Series A Junior Participating Preferred Stock, $0.01 par value		New York Stock Exchange New York Stock Exchange

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 þ No o

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 common stock held by non-affiliates of the registrant was approximately $1.710 billion, based on the closing sales price of $61.19 per share of the registrant’s common stock as reported by on the New York Stock Exchange as of June 30, 2006, the last business day of the registrant’s most recently completed second fiscal quarter. As of February 28, 2007, 28,155,996 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held May 22, 2007 are incorporated by reference into Part III of this Form 10-K. If such Proxy Statement is not filed within 120 days after December 31, 2006, the Part III information will be filed as part of an amendment to this Form 10-K not later than the end of such 120-day period, pursuant to General Instruction G(3).

 

 

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			14
Item 1B. Unresolved Staff Comments			21
Item 3. Legal Proceedings			22
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			24
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			47
Item 8. Financial Statements and Supplemental Data			49
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			49
Item 9A. Controls and Procedures			49
Item 9B. Other Information			49
Part III.			50
Item 10. Directors and Executive Officers of the Registrant			50
Item 11. Executive Compensation			50
Item 12. Security Ownership of Beneficial Owners and Management			50
Item 13. Certain Relationships and Related Transactions			50
Item 14. Principal Accounting Fees and Services			51
Part IV.			51
Item 15. Exhibits, Financial Statement Schedules			51
Signatures			57
Glossary of Natural Gas and Oil Terms			G-1
Index to Financial Statements			F-1
First Amendment to Change of Control Plan
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 CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO 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, as amended, (the “Exchange Act”). These forward-looking statements generally may be identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “would,” “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 14 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 web site at http://www.houstonexploration.com as soon as reasonably practicable after we electronically file such material with, or otherwise furnish it to, the Securities and Exchange Commission (“SEC”).

On January 7, 2007, we announced that we had entered into a definitive agreement and plan of merger with Forest Oil Corporation pursuant to which Forest will acquire all of the outstanding shares of Houston Exploration for a combination of cash and Forest common stock. On February 8, 2007, Forest filed a registration statement on Form S-4 with the SEC, including a preliminary joint proxy statement / prospectus with respect to the merger. Investors are urged to carefully read the information contained in the materials regarding the proposed transaction once the registration statement is declared effective and the joint proxy statement is mailed to stockholders. Investors may obtain a copy of the joint proxy statement / prospectus, free of charge, at the SEC’s web site at www.sec.gov.

We have adopted an Ethical Business Conduct Policy Statement to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures. We also have 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 Ethical Business Conduct Policy Statement 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 any amendment to or waiver of these codes with respect to our executive officers and directors. Waiver information disclosed via the web site will remain on the web site for at least 12 months after the initial disclosure of a waiver. 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, copies of our Ethical Business Conduct Policy Statement, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines and the charters of the Committees referenced above are available 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” beginning on page G-1.

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.

Items 1. and 2. Business and Properties

Overview of Our Business and Pending Merger

We are an independent natural gas and oil producer engaged in 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 wholly-owned subsidiary of our then parent company, KeySpan Corporation. We completed our initial public offering in September 1996. Through three separate transactions, the last of which occurred in November 2004, KeySpan completely divested of its ownership in the common stock of our company. As of December 31, 2006, our operations were concentrated in four producing regions within the United States: South Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; and the Uinta and DJ Basins of the Rocky Mountains.

Our total net proved reserves as of December 31, 2006 were 699 billion cubic feet equivalent, or Bcfe. All of our reserves are estimated on an annual basis by independent petroleum engineers. Approximately 67% of our proved reserves at December 31, 2006, were classified as proved developed. During 2006, we produced 88.2 Bcfe. Production volumes during 2006 were significantly impacted by the sale of substantially all of our Gulf of Mexico assets during the first and second quarters of 2006 and continued curtailments of certain of these offshore fields prior to their sale, 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 a strategic plan to restructure the company by pursuing the sale of our Gulf of Mexico assets, shifting our operating focus primarily onshore and repurchasing up to $200 million of our outstanding common stock. On March 31, 2006, we completed the sale of the Texas portion of our Gulf of Mexico assets and on June 1, 2006, we completed the sale of substantially all of our Louisiana Gulf of Mexico assets. The divestiture of these assets had a significant impact on our operating results for the year ended December 31, 2006 and on the comparability of those results to prior years.

On June 12, 2006, we received an unsolicited proposal from JANA Partners LLC, a hedge fund, to acquire our company for $62 per share, subject to due diligence and negotiation of required documentation. According to its public filings, JANA Partners beneficially owned approximately 12.3% of our outstanding common stock as of the date of the proposal. On June 26, 2006, we announced our Board of Directors’ determination that the unsolicited proposal made by JANA Partners was not in the best interest of our shareholders and that Lehman Brothers Inc. had been engaged to assist us in exploring a broad range of strategic alternatives to further enhance shareholder value. In connection with our review of strategic alternatives, Lehman assisted our Board in soliciting third party indications of interest for proposed business combination transactions with Houston Exploration. During the solicitation and review period, forward natural gas prices declined significantly. Further details regarding the strategic alternatives review process will be available in the joint proxy statement / prospectus, and the registration statement on Form S-4 of which it is a part, to be mailed to our stockholders and referred to herein under the caption “Available Information.”

On January 7, 2007, we announced the conclusion to the strategic alternatives review process with our entry into an agreement and plan of merger with Forest Oil Corporation. Under the merger agreement, Forest will acquire all of the outstanding shares of Houston Exploration for a combination of cash and Forest common stock.

Under the terms of the merger agreement, our shareholders will receive total consideration equal to 0.84 shares of Forest common stock and $26.25 in cash for each outstanding share of Houston Exploration common stock, or an aggregate of an estimated 23.6 million shares of Forest common stock and cash of $740 million. Based on the closing price of Forest common stock on January 5, 2007, the last trading day prior to announcement of the transaction, this represents $52.47 per share of merger consideration to be received by Houston Exploration shareholders. The actual value of the merger consideration to be received by our shareholders will depend on the average closing price of Forest common stock for the ten trading days ending three calendar days prior to the effective date of the merger, and the amount of cash and stock consideration will be determined by shareholder elections, subject to proration and an equalization formula. It is anticipated that the stock portion of the consideration will be tax free to Houston Exploration shareholders.

The Boards of Directors of Houston Exploration and Forest each unanimously approved the proposed merger. The merger is subject customary terms and conditions, including the approval of both Houston Exploration and Forest shareholders, and is expected to be completed in the second quarter of 2007. Upon completion of the transaction, it is anticipated that Forest shareholders would own approximately 73% of the combined company, and Houston Exploration shareholders would own approximately 27%.

Concurrently with the execution of the merger agreement, funds affiliated with JANA Partners entered into a voting agreement with Forest pursuant to which the JANA funds agreed, during the term of the voting agreement, to vote their shares of our common stock in favor of the merger with Forest and the adoption of the merger agreement and against any transaction that would impede or delay the merger with Forest, and granted to Forest a proxy to vote their shares at any stockholder meeting convened to consider such matters. As of January 7, 2007, the JANA funds beneficially owned approximately 14.7% of our total issued and outstanding shares of our common stock. The voting agreement will terminate in certain instances, including an adverse recommendation change (as defined in the merger agreement) by our Board of Directors or any material amendment to the merger agreement that is adverse to us or our stockholders.

On February 8, 2007, Forest filed a registration statement on Form S-4 with the SEC, including a preliminary joint proxy statement / prospectus with respect to the merger. Also on February 8, 2007, the companies received notice of early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvement Act with respect to the proposed transaction.

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, pending the merger, we employ the following strategies:

	•		Pursue Balanced Growth. We pursue a balanced strategy of exploiting our existing reserves, exploring for new reserves and acquiring new properties. Typically, a substantial portion 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. However, the merger agreement contains significant restrictions on our operations pending completion of the merger, including restrictions, among others, on our ability to make capital expenditures, including acquisitions, enter into hedging arrangements and take other specific actions without Forest’s approval.
	•		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, 2006, approximately 96% of our proved reserves were natural gas and, for the year ended December 31, 2006, approximately 94% 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, thereby allowing a higher cash margin.
	•		Concentrated Operations. We focus our operations in four 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, 2006, approximately 99% of our reserves were located in four geographic areas: South Texas, the Arkoma Basin, East Texas and the Rocky Mountains.
	•		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, 2006, we operated approximately 80% of our wells, and our average working interest was approximately 77%.
	•		Minimize 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. We believe that our operating structure provides us with a competitive advantage because it maximizes our margins and cash flows. For 2006, our onshore lease operating expense was $0.63 per Mcfe.
	•		Employ Conservative Financial Policies. We typically have funded 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, 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 (subject to the restrictions in the merger agreement) based on operational developments, commodity prices, service costs, acquisition opportunities and numerous other factors.

Manage Commodity Price Risks. We have historically entered into derivative instruments which were intended to reduce our exposure to adverse commodity price fluctuations and provide more predictable cash flows that allow us to better 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 (subject to the restrictions in the merger agreement) by locking in prices when they reach levels we determine to be acceptable.

Properties and Operating Areas

The table below summarizes certain data for our core operating areas for the year ended December 31, 2006:

Activity and Balances as of or for the Year Ended December 31, 2006
		Average												Percentage
		Daily				Total				Proved				Total Proved				Wells Drilled
Area		Production				Production				Reserves				Reserves				Total				Successful
		(MMcfe/d)				(MMcfe)				(MMcfe)								(Gross)				(Gross)
South Texas			143				52,317				356,023				51	%			100				90
Arkoma Basin			40				14,465				190,384				27	%			72				71
East Texas			12				4,420				86,086				12	%			28				28
Rocky Mountains			8				2,961				62,062				10	%			160				138
Other			1				244				2,563				—				—				—
Total onshore			204				74,407				697,118				100	%			360				327
Gulf of Mexico			38				13,749				2,210				—				3				2
Total			242				88,156				699,328				100	%			363				329

South Texas. Our South Texas properties are concentrated in the Charco, North Roleta, Haynes and South Trevino Fields of Zapata County; the Alexander, Hubbard, South Laredo and Vaquillas Ranch Fields of Webb County; the Northeast Thompsonville Field in Jim Hogg County, the Rincon Field in Starr County, the Tijerina-Canales-Blucher Field in Jim Wells and Kleberg Counties, and the San Carlos Field in Hidalgo County.

As of December 31, 2006, our South Texas properties covered approximately 83,000 net acres and we owned interests in 955 producing wells, 840 (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. During 2006, production from our South Texas properties averaged 143 MMcfe per day and accounted for 59% of our total production. At December 31, 2006, estimated net proved reserves totaled approximately 356 Bcfe, which accounted for approximately 51% of our reserve base at year-end 2006.

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, 2006, we had approximately 39,000 net acres under lease and we owned working interests in 483 producing natural gas wells, 350 (72%) of which we operated. Our average working interest is 56%. Wells average a depth of 5,500 feet, and production is from the Atoka formation. During 2006, production averaged 40 MMcfe per day. Acquisition opportunities have been scarce or limited in the Arkoma Basin during the most recent three-year period, and as a result, our current activities are primarily focused on the substantial number of in-field drilling opportunities within our existing acreage. At December 31, 2006, estimated net proved reserves totaled approximately 190 Bcfe, which accounted for approximately 27% of our reserve base at year-end 2006.

East Texas. Our East Texas properties are concentrated in the Willow Springs Field located in Gregg County, the North Blocker Field in Harrison County and the South Oak Hill Field in Rusk County, Texas. In 2006, we continued the expansion of our East Texas operating base initiated during 2005 with the acquisition of producing properties and acreage in the Willow Springs Field, adding approximately 16.2 Bcfe of net proved reserves for $21.3 million. As of December 31, 2006, our East Texas properties covered approximately 17,000 net acres, and we owned interests in 107 producing wells, 101 (94%) of which we operated. Our average working interest is 87%. During 2006, production averaged approximately 12 MMcfe per day. At December 31, 2006, estimated net proved reserves totaled approximately 86 Bcfe, which accounted for approximately 12% of our reserve base at year-end 2006.

Rocky Mountains. Our Rocky Mountain properties are primarily located in the Uinta Basin of Northeastern Utah and the DJ Basin in Eastern Colorado. At December 31, 2006, we had accumulated approximately 739,000 net acres with estimated net proved reserves of 62 Bcfe, an increase of approximately 35 Bcfe or nearly 130% from net proved reserves of approximately 27 Bcfe at the end of 2005. During 2006, production from our Rocky Mountain properties averaged approximately 8 MMcfe per day, net to our interests. At December 31, 2006, we had interests in 214 wells, all of which are operated by us, along the Niobrara Trend of the DJ Basin, with an average working interest of 100%; 107 wells in the Uinta Basin, with an average working interest of 56%, of which 13 (12%) are operated by us; and one exploratory well, with a working interest of 50% and operated by us, in the Williston Basin of northwestern North Dakota.

Gulf of Mexico. During the first and second quarters of 2006, we completed the sale of substantially all of our Gulf of Mexico assets. The sale transactions did not include 18 Louisiana offshore blocks retained by us. Of these 18 blocks, four expired subsequent to the sales transactions, two were drilled during 2006, resulting in two successful exploratory wells,

and 12 remain classified as undeveloped at the end of 2006. During 2006, we participated in drilling three offshore exploratory wells: Eugene Island 357 No. 1 was unsuccessful; West Cameron 39 No. A2 was successfully completed and brought on-line in late June 2006; and West Cameron 132 No. 1 was successfully drilled during the third quarter of 2006, with initial production projected during the first half of 2007. During December 2006, production from our remaining offshore wells averaged approximately 1 MMcfe per day.

Other. As of December 31, 2006, our “other” operating areas primarily consist of 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 per day during 2006. 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 in the future.

Natural Gas and Oil Reserves

The following table summarizes the estimates of our historical net proved reserves as of December 31, 2006, 2005 and 2004, and the present values attributable to those reserves at those dates. For the years ended December 31, 2006 and 2005, all of the reserve data and present values were estimated by independent petroleum engineering consultants Netherland, Sewell & Associates, Inc. For the year ended December 31, 2004, all of the reserve data and present values were estimated by two independent petroleum engineering firms: Netherland, Sewell & Associates, Inc. and Miller and Lents, Ltd., with these firms evaluating approximately 80% and 20%, respectively, of the total reserve quantities.

		As of December 31,
Net Proved Reserves:		2006(1)				2005(1)				2004(1)
		(in thousands)
Natural gas (MMcf)			671,636				793,074				749,114
Oil and natural gas liquids (MBbls)			4,615				11,291				7,335
Total (MMcfe)			699,328				860,820				793,124
Net present value of future cash flows, before income taxes(2)(4)		$	1,002,692			$	2,877,420			$	2,071,976
Future income taxes, discounted at 10%			(265,466	)			(910,396	)			(631,921	)
Standardized measure of discounted future net cash flows (3)(4)		$	737,226			$	1,967,024			$	1,440,055

Proved natural gas and oil reserves are the estimated quantities of natural gas, crude oil and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 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 drilling activities on our properties. The following table sets forth the results of our drilling activities for the years ended December 31, 2006, 2005 and 2004. 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
2006
South Texas			1				1.0				—				—				89				76.1				10				8.6				90				77.1				10				8.6				100				85.7
Arkoma Basin			3				1.2				—				—				68				44.5				1				0.3				71				45.7				1				0.3				72				46.0
East Texas			—				—				—				—				28				26.2				—				—				28				26.2				—				—				28				26.2
Rocky Mountains			18				8.8				6				3.2				120				95.0				16				13.8				138				103.8				22				17.0				160				120.8
Gulf of Mexico			2				0.5				1				0.2				—				—				—				—				2				0.5				1				0.2				3				0.7
Total			24				11.5				7				3.4				305				241.8				27				22.7				329				253.3				34				26.1				363				279.4
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			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			29				26.8				9				6.0				148				116.7				25				21.0				177				143.5				34				27.0				211				170.5

As of December 31, 2006, we were drilling or participating in the drilling of 29 gross (18.8 net) wells. Of these wells, through February 28, 2007, 18 gross (12.0 net) wells have been determined to be successful; 4 gross (3.3 net) wells were dry; and the remaining 7 gross (3.5 net) wells were still in progress as of the date of this Annual Report.

Productive Wells

The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2006. Productive wells consist of producing wells and wells capable of production, including 39 wells located in the Rocky Mountains (32 in the DJ Basin, six in Uinta and one in North Dakota) awaiting connections at December 31, 2006. Wells that are completed in more than one producing horizon are counted as one well. Where we are “operator,” we are responsible for managing the day-to-day operations of the well.

		As of December 31, 2006
		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			827				779.8				115				17.2				13				7.7				—				—				955				804.7
Arkoma Basin			350				240.3				133				29.1				—				—				—				—				483				269.4
East Texas			98				89.3				5				0.8				3				2.1				1				0.4				107				92.6
Rocky Mountains			228				227.5				92				45.4				—				—				2				1.0				322				273.9
Other			—				—				2				1.1				—				—				—				—				2				1.1
Total onshore			1,503				1,336.9				347				93.6				16				9.8				3				1.4				1,869				1,441.7
Gulf of Mexico			—				—				2				0.5				—				—				—				—				2				0.5
Total			1,503				1,336.9				349				94.1				16				9.8				3				1.4				1,871				1,442.2

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, 2006. 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, 2006
		Undeveloped								Developed								Total Acreage
		Gross				Net				Gross				Net				Gross				Net
South Texas			9,066				8,649				98,892				74,206				107,958				82,855
Arkoma Basin			27,181				10,216				47,239				28,619				74,420				38,835
East Texas			4,849				2,984				15,941				13,816				20,790				16,800
Rocky Mountains			906,621				687,032				78,914				51,668				985,535				738,700
Other onshore			—				—				1,740				620				1,740				620
Total onshore			947,717				708,881				242,726				168,929				1,190,443				877,810
Gulf of Mexico			56,998				31,936				7,500				750				64,498				32,686
Total			1,004,715				740,817				250,226				169,679				1,254,941				910,496

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, 2006
		2007								2008								2009								2010								2011
		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
South Texas			2,593				2,545				1,238				1,161				3,528				3,457				—				—				—				—
Arkoma Basin			2,816				932				—				—				614				238				4,088				1,154				15,754				6,994
East Texas			2,799				2,172				126				126				191				169				—				—				—				—
Rocky Mountains			66,529				56,971				317,773				181,999				36,012				28,117				15,719				7,145				132,708				120,326
Total onshore			74,737				62,620				319,137				183,286				40,345				31,981				19,807				8,299				148,462				127,320
Gulf of Mexico			5,000				2,500				11,998				4,437				25,000				12,500				15,000				12,500				—				—
Total			79,737				65,120				331,135				187,723				65,345				44,481				34,807				20,799				148,462				127,320

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 price 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 or results of operations. For a list of purchasers that accounted for 10% or more of our natural gas and oil revenues during the preceding last three calendar years, see Consolidated Financial Statements, Note 8 — Sales to Major Customers.

Historically, we have entered into derivative contracts with counterparties who are participants in our bank credit facility, as well as 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 occasionally is 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 those 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 title opinions. 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, demand for natural gas increases during the winter months as a result of heating applications and decreases during the summer and early fall. Seasonal anomalies such as mild winters or cool summers sometimes lessen these fluctuations. 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 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, 2006, we had 160 full time employees, 125 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. As of December 31, 2006, we had approximately 18 contract employees.

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 Colorado. 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 also 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 tribe jurisdictions, 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 in the future, nor can we determine what effect, 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 is sufficiently competitive. In state waters and onshore, gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states. In offshore Federal waters, the Outer Continental Shelf Lands Act provides that every permit or other grant of authority for the transportation of oil or gas by pipeline on or across the Outer Continental Shelf must require the pipeline to provide open and nondiscriminatory access, but does not authorize 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, 2006, we did not incur any material capital expenditures for environmental control facilities. As of the date of this Annual Report, we are not aware of any environmental issues or claims that will require material expenditures during 2007 and 2008 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

We are subject to significant business uncertainties and contractual restrictions while our merger with Forest Oil Corporation is pending.

Uncertainty about the effect of the proposed merger with Forest Oil Corporation on employees, suppliers and partners may have an adverse effect on us and our business. These uncertainties may impair our ability to attract, retain and motivate key personnel until the merger is consummated, and could cause persons that deal with us to defer decisions concerning their business relationship with us, or to seek to change their existing business relationships with us. Employee retention may be particularly challenging while the merger is pending, as employees may experience uncertainty about their future employment. In addition, the merger agreement significantly restricts our business operations while the merger is pending, including our ability to make capital expenditures, pursue acquisitions, borrow money other than in the ordinary course of our business, enter into hedging arrangements and take other specified actions without Forest’s approval. These restrictions could prevent or delay us from pursuing attractive business or market opportunities that may arise prior to the completion of the merger.

The failure to complete the merger could negatively impact our stock price, future business and financial results.

Although the board of directors has unanimously recommended that our stockholders adopt and approve the merger agreement, and Forest’s board of directors has unanimously recommended that its shareholders approve the issuance of additional shares of Forest common stock in the merger, we cannot assure you that the merger and the merger agreement will be approved by our stockholders or that the issuance of additional shares of Forest common stock in the merger will be approved by Forest’s shareholders, or that other conditions to the completion of the merger will be satisfied. If the merger is not completed, we will be subject to numerous risks, including the following:

	§		We may be required to pay a termination fee of $55 million if the merger agreement is terminated under certain circumstances and we enter into an alternative transaction;
	§		The current market price of our common stock may reflect a market assumption that the merger will occur, and a failure to complete the merger could result in a decline in the market price of our common stock;
	§		We are obligated to pay certain costs relating to the merger (such as legal and financial advisory fees) whether or not the merger is completed, and we may be required to pay a $5 million fee to Forest to cover its expenses if the merger is not consummated for certain reasons;
	§		There may be substantial disruption to our business and our management and employees have been and will continue to be distracted from day-to-day operations because matters related to the merger (including integration planning) require substantial commitments of time and resources, which could otherwise have been devoted to other activities and business opportunities that could have been beneficial to us and our stockholders;
	•		Our business could be adversely affected if we are unable to retain key employees or attract qualified replacements; and
	§		We would continue to face the risks that we currently face as an independent company.

We are subject to an ongoing shareholder lawsuit, which could result in an injunction preventing consummation of the merger or significant monetary damages.

Houston Exploration’s directors and Forest are defendants in a shareholder lawsuit brought in Houston, Texas by the City of Monroe Employees’ Retirement System. The plaintiff asserts, on behalf of an uncertified class of our stockholders, that the Houston Exploration directors breached their fiduciary duties by not pursing an unsolicited proposal made on June 12, 2006 by JANA Partners LLP to purchase the outstanding shares of Houston Exploration common stock for $62 per share. The plaintiff also seeks to enjoin the merger, asserting that our directors’ decision to enter into the merger with Forest constitutes a breach of fiduciary duties, because, the plaintiff alleges, the merger consideration is inadequate. This lawsuit is at an early stage and subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, based on the current status of the litigation, we cannot currently predict the manner and timing of the resolution of the lawsuit, the likelihood of the issuance of an injunction preventing the consummation of the merger, or an estimate of a range of possible losses or any minimum loss that could result in the event of an adverse verdict in the lawsuit. Although our insurance policies should provide coverage for the claims against our directors, the policies may not be sufficient to cover all costs and liabilities associated with the lawsuit. We believe this lawsuit is without merit, and we

intend to vigorously defend against it. Although it is too soon to predict the outcome of this lawsuit or the time to resolution, we do not believe that it will have a material adverse effect on our financial position, results of operations or cash flows.

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:

	§		weather conditions;
	§		the price of foreign imports;
	§		overall domestic and global economic conditions;
	§		terrorist attacks or military conflicts;
	§		political conditions, economic stability, and armed conflicts in oil producing regions;
	§		the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
	§		the level of consumer 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 96% of our total proved reserves at December 31, 2006 were natural gas.

Our ability to replace revenues generated from the sale of substantially all of our Gulf of Mexico properties depends upon market conditions, restrictions under the pending merger agreement and numerous uncertainties.

During 2006, we completed the sale of substantially all of our Gulf of Mexico assets. Although we may reinvest the proceeds from the sale of our Gulf of Mexico assets in onshore producing assets, we cannot assure you that we will be able to find suitable properties on attractive terms or that, if found, we would be permitted under the merger agreement to acquire such properties. Our operating revenues and cash flows decreased 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. The merger agreement significantly restricts our business operations while the merger is pending, including our ability to make capital expenditures, pursue acquisitions, borrow money other than in the ordinary course of business, enter into hedging arrangements and take other specified actions without Forest’s approval. These restrictions could prevent us from pursuing attractive business or market opportunities that may arise prior to completion of the merger.

A significant increase in our level of indebtedness may limit our financial flexibility.

As of December 31, 2006, we had long-term indebtedness of $175 million, all of which was our 7% senior subordinated notes, as we had no outstanding borrowings under our bank credit facility. Our long-term indebtedness represented 15.2% of our total book capitalization at December 31, 2006. As of the date of this Annual Report, we had no outstanding borrowings under our bank credit facility.

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 assets because they have been mortgaged to secure borrowings under our revolving bank credit facility;
	§		any 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.

Subject to the restrictions in the merger agreement, 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 would 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 historical and expected future financial performance.

We may be required to take significant 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, capital expenditures that do not generate equivalent or greater value in proved reserves, increases in our estimated future operating, development or abandonment 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, if applicable, calculated using market prices in effect as of the balance sheet date, as adjusted for “basis” or location differentials and held constant over the life of the reserves (“net wellhead prices”). 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 “write down” 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. A ceiling test writedown would not impact cash flow from operating activities, but it would reduce shareholders’ equity. The risk of a required ceiling test writedown of the book value of natural gas and oil properties increases when natural gas and oil prices are low or volatile. 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.

In calculating our ceiling test at December 31, 2006, we estimated that, using an average net wellhead price of $4.94 per Mcf, the carrying value of our full cost pool exceeded the ceiling limitation by approximately $582.8 million ($376.5 million net of tax). However, since December 31, 2006, the market price for natural gas increased such that, using an average net wellhead price of $6.63 per Mcf on February 20, 2007, a writedown of $19.0 million ($12.3 million net of tax) in the carrying value of our natural gas and oil assets was required. As a result, and pursuant to full cost accounting rules, we recorded a non-cash charge and reduction to earnings in the fourth quarter of 2006.

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

The amount of borrowings available to us under our 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 $500 million which is expected to remain in effect until the next scheduled redetermination on April 1, 2007. 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 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 significant financial losses and may continue to do so in the future.

In an effort 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 derivative contracts covering a significant portion of our production. During 2006, 2005 and 2004, we incurred losses from hedging activities of $64.5 million, $264.5 million and $70.1 million, respectively. These losses included realized losses on contracts settled during the each of the respective periods of $69.2 million ($44.2 million net of tax), $265.2 million ($171.3 million net of tax) and $68.2 million ($44.1 million, net of tax). As of the date of this Annual Report, we have approximately 41% of our estimated 2007 production hedged and approximately 42% of our estimated 2008 production hedged during the months of January and February, with contracts covering approximately 8% of estimated production during the remaining 10 months of 2008.

By the end of the first quarter of 2006, all of our open derivative contracts ceased to qualify for hedge accounting. As a result, our earnings after that date became more volatile, as mark-to-market accounting was required, and all subsequent changes in the fair market value of open contracts have been and will be recognized as an increase or reduction to natural gas and oil revenues. At December 31, 2006, an unrealized loss of $18.5 million, net of tax, remains deferred in accumulated other comprehensive income relating to prior hedge accounting. This loss represents the fixed value of our remaining open derivative contracts deferred in accumulated other comprehensive income at the time they ceased to qualify for hedge accounting. All remaining deferred losses will be reclassified and recognized in future earnings at the time when sale of the related forecasted natural gas production occurs. Over the next 12-month period, we expect to reclassify from accumulated other comprehensive income to earnings a loss of $11.1 million, net of tax, with $7.4 million to be recognized thereafter.

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. 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. During the last three-year period, commodity prices have remained higher than historical levels, resulting in higher costs for materials, equipment and services. 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 of our focus areas, particularly South Texas, the Rocky Mountain regions and East Texas, and we believe these values may continue to increase in 2007. 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, especially if prices do not increase accordingly, which would impair our profitability. During the fourth quarter of 2006, we

incurred a writedown in the carrying value of our natural gas and oil properties of $19.0 million ($12.3 million net of tax), due in part to the cumulative effect of higher finding and development costs in recent years.

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 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 may 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 2006, 2005 and 2004, we incurred downward revisions of our proved reserves of 31 Bcfe, 60 Bcfe and 20 Bcfe, respectively, either from proved undeveloped reserves that were determined to be depleted or otherwise not recoverable, reserves that were uneconomical due to prices at the end of the applicable period, or production performance indicating less gas in place or smaller reservoir size than initially estimated. We cannot assure you that we will not face similar downward revisions in the future.

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 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 2006, and subsequent to the sale of substantially all of our Gulf of Mexico assets, we generated over 99% of our onshore production from four primary areas of operation. 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 operations along the Texas Gulf Coast, 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.

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 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 as long as commodity prices remain at attractive levels. If current utilization rates continue at levels seen during 2006 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. 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.

Any 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.

We could lose certain leasehold rights if we do not drill all the wells that are necessary to hold our acreage, especially in the Rocky Mountains, before the initial lease terms expire.

Our future growth plans rely in part on establishing significant production and reserves in the Rocky Mountains, which as of December 31, 2006, represented approximately 10% of our total proved reserves. At December 31, 2006, approximately 96% of our total onshore undeveloped acreage is located in the Rockies, of which 45% will expire within the next three-year period. We also have undeveloped acreage offshore Louisiana. We may have difficulty drilling all of the wells that are necessary to hold this acreage before the initial lease terms expire, which could result in the loss of certain leasehold rights.

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 within a single industry may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

Item 1B. Unresolved Staff Comments

None.

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

Item 3. Legal Proceedings

See Consolidated Financial Statements, Note 9 – Commitments and Contingencies – Legal Proceedings, incorporated herein by reference, for a discussion of the material legal proceedings to which were are a party.

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, 2006.

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 intraday sales prices for each calendar quarterly period from January 1, 2005, through December 31, 2006 as reported on the New York Stock Exchange:

Year Ended December 31, 2006		High				Low
First Quarter		$	62.56			$	48.13
Second Quarter			62.50				49.75
Third Quarter			66.21				54.36
Fourth Quarter			57.75				51.60

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

As of February 28, 2007, 28,155,996 shares of common stock were outstanding, and we had approximately 64 stockholders of record and approximately 8,250 beneficial owners.

The following Corporate Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing. The performance graph compares the performance of our common stock to the S&P 500 Index and to a peer group established by the Compensation Committee of our Board of Directors. This peer group is comprised of ten other independent oil and gas exploration and production companies with a similar mix of operations and includes Cabot Oil & Gas Corp., Cimarex Energy Company, Forest Oil Corporation, Newfield Exploration Company, Noble Energy Inc., Plains Exploration & Production Company, Pogo Producing Company, Southwest Energy Company, Stone Energy Corp., and XTO Energy Inc. The graph below matches the cumulative five-year total return of holders of our common stock with the cumulative total returns of the S&P 500 Index, and our peer group. The graph assumes that the value of the investment in our common stock and each index (including reinvestment of dividends) was $100 at December 31, 2001 and tracks the return on the investment through December 31, 2006.

Comparison of Five Year Cumulative Total Return* Among
The Houston Exploration Company, the S&P 500 Index and our Peer Group

• Assumes $100 invested on December 31, 2001 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.

		December 31,
		2001				2002				2003				2004				2005				2006
The Houston Exploration Company		$	100.00			$	91.13			$	108.76			$	167.69			$	157.24			$	154.20
S&P 500		$	100.00			$	77.90			$	100.24			$	111.15			$	116.61			$	135.03
Peer Group		$	100.00			$	114.49			$	152.85			$	210.69			$	325.88			$	348.57

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. In addition, our bank credit facility, the indenture governing our 7% senior subordinated notes due June 15, 2013, and our merger agreement with Forest all 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 and Notes and Note 3 – Stockholders’ Equity – Stockholder Rights Plan.

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, 2006. 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,
		2006				2005				2004				2003				2002
		(in thousands, except per share data and ratios)
Income Statement Data:
Revenues:
Natural gas and oil revenues		$	529,586			$	620,271			$	649,087			$	491,440			$	344,295
Other			2,011				1,272				1,352				1,312				1,086
Total revenues			531,597				621,543				650,439				492,752				345,381
Expenses:
Lease operating expense			63,959				67,796				55,925				47,072				33,976
Severance tax			18,102				18,121				11,933				15,958				9,487
Transportation expense			10,636				11,883				11,819				10,387				9,317
Asset retirement accretion expense(1)			3,373				5,278				4,902				3,668				—
Depreciation, depletion and amortization			253,666				295,351				265,148				197,530				171,610
Writedown in carrying value			19,000				—				—				—				—
General and administrative, net			36,013				38,378				32,899				19,542				13,077
Total operating expenses			404,749				436,807				382,626				294,157				237,467
Income from operations			126,848				184,736				267,813				198,595				107,914
Other (income) expense(2)			(13,495	)			142				(1,058	)			(15,746	)			(9,070	)
Interest expense, net			25,206				16,535				9,455				8,342				7,398
Income before income taxes			115,137				168,059				259,416				205,999				109,586
Income tax provision			47,354				62,890				96,592				72,187				39,092
Income before cumulative effect of change in accounting principle		$	67,783			$	105,169			$	162,824			$	133,812			$	70,494
Cumulative effect of change in accounting principle(3)			—				—				—				(2,772	)			—
Net income		$	67,783			$	105,169			$	162,824			$	131,040			$	70,494
Earnings per share:
Basic:
Income per share before cumulative effect of change in accounting principle change		$	2.37			$	3.66			$	5.50			$	4.30			$	2.31
Cumulative effect of change in accounting principle(3)			—				—				—				(0.09	)			—
Net income per share – basic		$	2.37			$	3.66			$	5.50			$	4.21			$	2.31
Diluted:
Income per share before cumulative effect of change in accounting principle		$	2.36			$	3.62			$	5.44			$	4.29			$	2.28
Cumulative effect of change in accounting principle(3)			—				—				—				(0.09	)			—
Net income per share – diluted		$	2.36			$	3.62			$	5.44			$	4.20			$	2.28
Weighted average shares – basic			28,543				28,707				29,616				31,097				30,569
Weighted average shares – diluted			28,693				29,037				29,932				31,213				30,878
Ratio of earnings to fixed charges(4)			4.7x				7.2x				15.0x				13.6x				7.6x

		Years Ended December 31,
		2006				2005				2004				2003				2002
		(in thousands)
Cash Flow Data:
Net cash provided by operating activities		$	416,189			$	460,509			$	527,141			$	381,969			$	243,601
Net cash provided by (used) in investing activities(5)			105,007				(727,003	)			(509,922	)			(452,959	)			(252,857	)
Net cash provided by (used in) financing activities(6)			(475,225	)			255,896				(1,211	)			55,528				17,668

		At December 31,
		2006				2005				2004				2003				2002
		(in thousands)
Balance Sheet Data:
Working capital (deficit)(7)		$	247			$	(214,525	)		$	(31,884	)		$	(36	)		$	10,550
Property, plant and equipment, net(8)			1,591,332				2,018,340				1,548,256				1,371,129				1,022,414
Total assets(8)			1,771,726				2,361,624				1,722,577				1,509,065				1,151,068
Long-term debt and notes(9)			175,000				597,000				355,000				302,000				252,000
Stockholders’ equity			964,604				693,138				782,920				735,534				592,789

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 engaged in 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 wholly-owned subsidiary of our then parent company, KeySpan Corporation. We completed our initial public offering in September 1996. Through three separate transactions, the last of which occurred in November 2004, KeySpan completely divested of its ownership in the common stock of our company. As of December 31, 2006, our operations were concentrated in four producing regions within the United States: South Texas; the Arkoma Basin of Arkansas and Oklahoma; East Texas; and the Uinta and DJ Basins of the Rocky Mountains.

During the first half of 2006, we completed the sale of substantially all of our Gulf of Mexico assets. The sale of these offshore properties was part of our strategic plan announced in November 2005 to shift our operating focus primarily onshore. The sale of our Gulf of Mexico assets had a significant impact on our operating results for the year ended December 31, 2006 and on the comparability of those results year-over-year.

Our total net proved reserves as of December 31, 2006 were 699 Bcfe. All of our reserves are estimated on an annual basis by independent petroleum engineers. Approximately 67% of our proved reserves at December 31, 2006 were classified as proved developed. During 2006, we produced 88.2 Bcfe of natural gas equivalents. Production volumes during 2006 were significantly impacted by the sale of substantially all of our Gulf of Mexico assets during the first and second quarters of 2006 and continued curtailments of certain of these offshore fields prior to their sale, 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. Because natural gas accounts for approximately 94% of our production, 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. Our use of derivative instruments prevented us from realizing the full benefit of the strong natural gas price environment during 2006 and in each of the preceding three years, and may continue to do so in future periods. Our natural gas revenues may experience significant volatility in future periods as all of our open derivative contracts ceased to qualify for hedge accounting during the first quarter of 2006. In addition, all derivative contracts entered into subsequent to December 31, 2006 are expected to be accounted for using mark-to-market accounting. See Consolidated Financial Statements, Note 1 — Summary of Organization and Significant Accounting Policies – Derivative Instruments and Hedging Activities.

Segment reporting is not applicable for us, as all of our assets are based in North America, and each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in SFAS 131, “Disclosures about Segments of an Enterprise and Related Information.”

Strategic Restructuring Plan

In November 2005, we announced our strategic restructuring plan, the primary purpose of which was to enhance shareholder value by becoming a pure onshore operator.

During 2006, we completed significant steps toward our original restructuring objectives, including the sale of substantially all of our Gulf of Mexico assets for net cash proceeds of $721.6 million, as described in more detail below; the repurchase and retirement of 1,176,500 shares, or approximately 4% of our outstanding common stock, for approximately $61.6 million; and the liquidation and settlement of a portion of our open derivative contracts for natural gas for approximately $15.2 million.

On June 12, 2006, we received an unsolicited proposal from JANA Partners LLC, a hedge fund, to acquire our company for $62 per share, subject to due diligence and negotiation of required documentation. According to its public filings, JANA

Partners beneficially owned approximately 12.3% of our outstanding common stock as of the date of the proposal. On June 26, 2006, we announced our Board of Directors’ determination that the unsolicited proposal made by JANA Partners was not in the best interest of our shareholders and that Lehman Brothers Inc. had been engaged to assist us in exploring a broad range of strategic alternatives to further enhance shareholder value. In connection with our review of strategic alternatives, Lehman assisted our Board in soliciting third party indications of interest for proposed business combination transactions with Houston Exploration. During the solicitation and review period, forward natural gas prices declined significantly.

Pending Merger with Forest Oil Corporation

On January 7, 2007, we announced the conclusion to the strategic alternatives review process with our entry into an agreement and plan of merger with Forest Oil Corporation. Under the merger agreement, Forest will acquire all of the outstanding shares of Houston Exploration for a combination of cash and Forest common stock.

Under the terms of the merger agreement, our shareholders will receive total consideration equal to 0.84 shares of Forest common stock and $26.25 in cash for each outstanding share of Houston Exploration common stock, or an aggregate of an estimated 23.6 million shares of Forest common stock and cash of $740 million. Based on the closing price of Forest common stock on January 5, 2007, the last trading day prior to announcement of the transaction, this represents $52.47 per share of merger consideration to be received by Houston Exploration shareholders. The actual value of the merger consideration to be received by our shareholders will depend on the average closing price of Forest common stock for the ten trading days ending three calendar days prior to the effective date of the merger, and the amount of cash and stock consideration will be determined by shareholder elections, subject to proration and an equalization formula. It is anticipated that the stock portion of the consideration will be tax free to Houston Exploration shareholders.

The Boards of Directors of Houston Exploration and Forest each unanimously approved the proposed merger. The merger is subject customary terms and conditions, including the approval of both Houston Exploration and Forest shareholders, and is expected to be completed in the second quarter of 2007. Upon completion of the transaction, it is anticipated that Forest shareholders would own approximately 73% of the combined company, and Houston Exploration shareholders would own approximately 27%.

Concurrently with the execution of the merger agreement, funds affiliated with JANA Partners entered into a voting agreement with Forest pursuant to which the JANA funds agreed, during the term of the voting agreement, to vote their shares of our common stock in favor of the merger with Forest and the adoption of the merger agreement and against any transaction that would impede or delay the merger with Forest, and granted to Forest a proxy to vote their shares at any stockholder meeting convened to consider such matters. As of January 7, 2007, the JANA funds beneficially owned approximately 14.7% of our total issued and outstanding shares of our common stock. The voting agreement will terminate in certain instances, including an adverse recommendation change (as defined in the merger agreement) by our Board of Directors or any material amendment to the merger agreement that is adverse to us or our stockholders.

On February 8, 2007, Forest filed a registration statement on Form S-4 with the SEC, including a preliminary joint proxy statement / prospectus with respect to the merger. Also on February 8, 2007, the companies received notice of early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvement Act with respect to the proposed transaction.

Disposition of Gulf of Mexico Assets

On March 31, 2006, we completed the sale of the Texas portion of our Gulf of Mexico assets. The $220 million gross sale price was initially adjusted by $29.2 million for various customary closing items, including the preliminary adjustment for operations related to the properties after January 1, 2006, the effective date of the transaction. Of the $190.8 million in net cash proceeds, approximately $140.1 million was received for assets sold to various partnerships affiliated with Merit Energy Company. In addition, approximately $43.1 million and $7.6 million were received from Hydro Gulf of Mexico, L.L.C. and Nippon Oil Exploration U.S.A. Ltd., respectively, pursuant to the exercise of their preferential purchase rights. We used $158 million of the net cash proceeds received from the sale of these assets to repay and reduce outstanding borrowings under our revolving credit facility; deposited in escrow $9.5 million of the proceeds with a qualified intermediary for potential reinvestment in like-kind exchange transactions under Section 1031 of the Internal Revenue Code; and used substantially all of the $23.3 million balance for working capital purposes. During the third quarter of 2006, $7.6 million of funds escrowed in connection with the sale of the Texas portion of our offshore assets, representing that portion of the escrowed funds that had not been reinvested within the 180-day time period under Section 1031, was released from escrow and reclassified as cash. In accordance with full cost accounting, no book gain or loss was recognized on the sale. The net proceeds of $190.8 million were recorded as a reduction to the full cost pool.

On June 1, 2006, we completed the sale of substantially all of our Louisiana Gulf of Mexico assets for a gross sale price of $590 million. The sale of a substantial majority of these assets to various partnerships affiliated with Merit Energy

Company was completed on May 31, 2006 pursuant to a purchase and sale agreement dated April 7, 2006, and the sale of certain working interests to Nippon Oil Exploration U.S.A. Ltd. and Chevron USA Inc. was completed on June 1, 2006 pursuant to the exercise of preferential purchase rights. The aggregate net cash proceeds received from the sale of these assets totaled approximately $530.8 million after customary initial closing adjustments, including the preliminary adjustment for operations related to the properties after January 1, 2006, the effective date of the transactions. Of the total net proceeds, approximately $510.2 million was received for assets acquired by the Merit affiliates, and approximately $16.6 million and $4.0 million was received from Nippon Oil Exploration U.S.A. Ltd. and Chevron USA Inc., respectively.

Of the $530.8 million in net cash proceeds received from the sale of the Louisiana portion of our Gulf of Mexico assets, $314.2 million was deposited in escrow directly with qualified intermediaries for potential reinvestment in like-kind exchange transactions under Section 1031 of the Internal Revenue Code, and substantially all of the $216.6 million balance, associated with properties sold outside the like-kind exchange arrangement,, was used to reduce outstanding borrowings under our revolving credit facility. In accordance with full cost accounting, no book gain or loss was recognized on the sale. The net proceeds of $530.8 million were recorded as a reduction to the full cost pool.

The sale of certain of our Gulf of Mexico properties accelerated the payment of a net profits interest to the predecessor owner of properties acquired by us in October 2003. On August 1, 2006, we paid approximately $21.0 million in connection with the net profits interest, which we funded with borrowings under our bank credit facility.

The sale transactions did not include 18 Louisiana offshore blocks, which we retained. Of these 18 blocks, four expired subsequent to the sales transactions, two were drilled during 2006, resulting in two successful exploratory wells, and 12 remain classified as undeveloped at the end of 2006.

In connection with the June 1, 2006 completion of the divestiture of substantially all our Gulf of Mexico assets, we were required under our bank credit facility to liquidate a portion of our 2006 derivative instruments. In order to comply with this requirement, in June 2006, we liquidated and settled open derivative contracts representing 60,000 MMBtu per day of hedged production for each of the months July through December 2006. The cost to liquidate and settle these contracts was approximately $14.3 million. In addition, on August 4, 2006, we liquidated and settled open derivative contracts representing 20,000 MMBtu per day of hedged production for each of the months September and October 2006. The cost to liquidate and settle these contracts was approximately $0.9 million.

On November 27, 2006, $314.1 million of previously escrowed funds relating to the sale of the Louisiana offshore assets, representing that portion of the escrowed funds that had not been reinvested within the 180-day period under Section 1031, was released from escrow and reclassified as cash. Upon release of the cash from escrow, we used $190 million to repay all outstanding borrowings under our bank credit facility and used the balance of approximately $124 million for working capital purposes. This included an estimated payment for federal income taxes for the fourth quarter of 2006 of $34.0 million, which estimated tax payment included the recognition of a taxable gain on the sale our Gulf of Mexico assets of approximately $264 million.

Acquisitions

On April 25, 2006, we completed the acquisition of certain interests in natural gas and oil producing properties and acreage in the Willow Springs Field of Gregg County, located in East Texas, from Samson Lone Star Limited Partnership. The $22 million cash purchase price was reduced to $21.3 million for various customary closing items, including an adjustment for operations related to the properties after the effective date of the transaction, January 1, 2006. The properties cover approximately 4,237 gross (3,579 net) acres, are adjacent to our existing operations in the Willow Springs Field and include interests in 28 producing wells with an average working interest of 80%. Based on internal estimates, total proved reserves associated with the interests acquired were 16.2 Bcfe as of January 1, 2006. The acquisition was funded with cash on hand of $19.1 million and borrowings under our revolving credit facility of $2.2 million.

On December 13, 2006, we acquired a 100% working interest in 10 producing wells in Webb County, Texas, from Legend Natural Gas II, LP. The $4.3 million purchase price was paid with cash on hand. The acquired properties cover approximately 3,000 acres and are located in close proximity to our producing assets in the South Laredo Field. Based on internal estimates, total proved reserves associated with the interests acquired were approximately 1.8 Bcfe.

On December 14, 2006, we completed the acquisition of certain interests in natural gas and oil producing properties, together with developed and undeveloped acreage, located along the Niobrara trend in the DJ Basin of Eastern Colorado and Western Nebraska, from Santos TOG Corp. (formerly known as Tipperary Oil & Gas Corporation). The net purchase price of $21.4 million was paid with cash on hand. The acquired properties and acreage cover approximately 145,000 net acres and include interests in approximately 305 wells. The majority of the interests acquired were incremental working interests ranging between 20% and 25% in wells operated by us. Based on internal estimates, total proved reserves

associated with the interests acquired were approximately 14.2 Bcfe as of November 1, 2006, and daily production averaged 1 Mcfe per day, net to the interests acquired.

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 Consolidated Financial Statements, Note 1 — Summary of Organization and Significant Accounting Policies for a discussion of our significant accounting policies.

Proved Reserves. All of our reserves are estimated 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, 2006, 2005 and 2004, we revised our proved reserves downward from prior years’ reports by approximately 31 Bcfe, 60 Bcfe and 20 Bcfe, respectively, due to proved undeveloped reserves that were determined to be depleted or otherwise not recoverable, uneconomical due to market prices at the end of the applicable period, 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 and wells pending determination, together with capitalized interest costs for these projects. 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 classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. We assess our properties on an individual basis or as a group if properties are individually insignificant. Our assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. We estimate that substantially all of our costs classified as unproved as of the balance sheet date will be evaluated and transferred within a four-year period.

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.

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. Our derivative instruments are not held for trading purposes. Historically, all of our derivative contracts qualified for hedge accounting at inception of the contract and were designated as cash flow hedges. Under SFAS 133, the fair market value of open derivative contracts is reflected on the balance sheet as either an asset or liability. If derivative instruments qualify for

hedge accounting, changes in the fair value are deferred in accumulated other comprehensive income until the period the sale of the related production occurs. Under SFAS 133, we are required to assess the effectiveness of all our derivative contracts at inception and at least every three months. If open contracts cease to qualify for hedge accounting, as was the case during the first quarter of 2006, mark-to-market accounting is utilized and changes in the fair value of open contracts are recognized in the income statement. Loss of hedge accounting may cause volatility in earnings. Fair value is assessed, and measured and estimated by obtaining independent market quotes from counterparties, as well as utilizing Black’s (1976) option valuation model 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 assess and measure the effectiveness of our open contracts at the end of each period. 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(R), “Share-Based Payment.” Under the fair value recognition provisions of SFAS 123(R), 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.

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.

Recent Accounting Pronouncements

During 2006, we adopted SFAS 123(R), “Share-Based Payment,” using the “modified prospective method” as defined by SFAS 123(R); SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans;” and the SEC Staff Accounting Bulletin No.108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). The adoption of these new pronouncements did not have a material impact on our financial statements. In addition, see Consolidated Financial Statements, Note 1 – Summary of Organization and Significant Accounting Policies – Recent Accounting Pronouncements for discussions of SFAS 157, “Fair Value Measurements” and Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement 109” (“FIN 48”). We are currently evaluating the impact of adopting SFAS 157 and FIN 48 and do not expect their adoption will have a material impact on our results of operations or financial position.

Overview of 2006 Results

During 2006, we successfully implemented our plan to restructure our business to become a pure onshore operator with the completion of the sale of substantially all of our Gulf of Mexico properties. The completion of the sale of our Texas offshore properties on March 31, 2006 and our Louisiana offshore properties on June 1, 2006 had a significant impact on our 2006 operating results. Reserves, production volumes, revenues, operating expenses and cash flows were all lower during 2006 than prior-year levels and are expected to remain lower unless reserves and production from the properties sold are replaced in full.

While total company reserves, production, net operating revenues and cash flows declined as a direct result of the sale of our offshore assets, our total onshore reserves increased 13% year-over-year to 697 Bcfe. Our primary source of onshore reserve additions during 2006 was through the drill bit. Our acquisition activity during 2006 was significantly less than in the prior three-year period, as we added just 32 Bcfe from acquisitions during 2006 compared to a total of 293 Bcfe added from acquisitions from 2003 through 2005. Our plan for reinvestment of the proceeds from the sale of our offshore assets included a balanced approach and despite having a large pool of cash available for reinvestment in onshore natural gas and oil assets, we were unable to fully utilize the sales proceeds to acquire producing properties and take full advantage of the

tax benefits provided by like-kind reinvestment, as the acquisition market for attractive, well-priced onshore properties was extremely competitive.

With the shift in focus to onshore operations during 2006 and the expansion of our onshore capital exploration and development drilling program, we were able to increase onshore production by 8% year-over-year. This increase was realized despite third party pipeline capacity constraints that continued throughout the year in the Rockies and that were experienced throughout the second half of the year in East Texas and Arkoma, as the supply of natural gas in these regions increased primarily due to industry-wide expansion of drilling within these areas.

Natural gas prices declined sharply during the third quarter and into the fourth quarter of 2006 from the record highs set during the third and fourth quarters of 2005 after Hurricanes Katrina and Rita and reached lows not seen since November 2002 due, in part, to historically high levels of U.S. natural gas storage. As a result of this decline in gas prices, our cash losses on the settlement of derivative contracts narrowed considerably from the first and second quarters of 2006 and from the third and fourth quarters of 2005. Along with this decline in natural gas prices, we began to see some stabilization in rig rates and other service costs during the second half of the year. Despite this, our depreciation, depletion and amortization rate increased year-over-year primarily as a result of higher onshore finding and development costs during 2006 and an increase in estimated future development costs. In addition, due to the cumulative effect of higher finding and development costs during recent years, combined with higher estimated future operating and development costs at year-end 2006, we were required under full cost accounting rules to write down or impair the carrying value of our natural gas and oil properties by $19.0 million ($12.3 million net of tax) during the fourth quarter of 2006. See Consolidated Financial Statements, Note 1 — Summary of Organization and Significant Accounting Policies — Natural Gas and Oil Properties, for further discussion of full cost accounting.

Net cash proceeds of $721.6 million from the sale of our offshore assets were ultimately used to repay all of our outstanding borrowings under our bank credit facility, with the balance used for working capital purposes, including the funding of our 2006 capital expenditure program. Throughout 2006, we borrowed under our bank credit facility to fund exploration and development activities, several smaller producing property acquisitions, a significant net profits payment that was triggered by the sale of certain offshore fields, cash settlements of derivative contracts, including the liquidation of a portion of our open contracts that was required under our bank credit facility after completion of the sale of our offshore assets, and repurchases of our common stock. We were unable to fully reinvest the $323.7 million initially escrowed for like-kind exchange transactions under Section 1031 prior to expiration of the qualified reinvestment period in November 2006, and the remaining funds were released. However, upon the release of the escrowed funds, we were able to repay all accumulated bank borrowings then outstanding and fund our 2006 federal income tax obligation incurred in connection with taxable gain recognized on the sale our offshore assets, leaving us with approximately $54 million in cash and $175 million in long-term debt under our senior subordinated notes at December 31, 2006.

These factors were the primary drivers behind results of operations, net income and cash flows during 2006. During 2006:

	§		We generated $67.8 million in net income, a decrease of 36% from $105.2 million in 2005;
	§		We produced 88 Bcfe compared to 114 Bcfe produced in 2005, and our average daily production rate was 242 MMcfe per day compared to 313 Mcfe/day during 2005, a decrease of 23%;
	§		Our net proved reserves totaled 699 Bcfe at year-end 2006, a decrease of 19% from 861 Bcfe at year-end 2005. We sold offshore assets representing 234 Bcfe and we added a net 161 Bcfe, which included 160 Bcfe added through the drill bit plus 32 Bcfe added through acquisitions less 31 Bcfe in downward revisions due primarily to quantities becoming uneconomic at the lower market prices in effect at December 31, 2006. With the total net additions of 161 Bcfe, we replaced 183% of the 88 Bcfe produced in 2006;
	§		We generated net cash proceeds from the sale of substantially all of our Gulf of Mexico assets of $721.6 million. Initially, we used $374 million to repay bank debt, escrowed $323.7 million with qualified intermediaries for potential reinvestment in like-kind exchange transactions under Section 1031 of the Internal Revenue Code and used the balance or, approximately $23.9 million, for working capital purposes;
	§		Effective June 1, 2006, and following the completion of the sale of our Gulf of Mexico assets, the borrowing base on our bank credit facility was reduced from $600 million to $500 million, where it remained at December 31, 2006;
	§		During the third and fourth quarters, we withdrew previously escrowed funds from the sale of our Gulf of Mexico assets, of which $2.2 million was reinvested in qualified natural gas and oil assets and the balance, or $321.5 million, was released from escrow due to the expiration of the 180-day qualified reinvestment periods;
	§		Upon release of the remaining escrowed funds in November, we repaid all outstanding borrowings under our bank credit facility, thereby reducing total bank borrowings by a net $422 million during the year;

	§		Following the release of the escrowed funds for which qualified reinvestments in natural gas and oil properties were not achieved, we recognized a taxable gain on the sale of our Gulf of Mexico assets of $264 million and utilized all of our net operating loss carryforwards to partially offset the taxable gain. As a result, in November, we made a cash payment for estimated federal income taxes for 2006 of $34.0 million;
	§		We generated $416.2 million in net cash flows from operating activities compared to $460.5 million during 2005, a decrease of 10%;
	§		We spent $612.8 million under our 2006 capital program for investments in natural gas and oil properties, a decrease of 18% from 2005. Our 2006 expenditures included $64.7 million for producing property acquisitions compared to $197.7 million spent on acquisitions in 2005, a decrease of 67%;
	§		We drilled 363 wells, of which 329, or 91%, were successful with 2 offshore, 28 in East Texas, 71 in Arkoma, 90 in South Texas and 138 in the Rockies;
	§		In South Texas, we integrated the producing properties acquired in November 2005 from Kerr-McGee, acquired a 3D seismic survey covering approximately 1,000 square miles in the Vicksburg trend, and began our drilling program on the acquired properties during April 2006, successfully completing 36 wells within the Rincon, Tijerina-Canales-Blucher and Vaquillas Ranch Fields by year end. In December, we acquired a 100% working interest in ten producing wells located in Webb County, Texas, from Legend Natural Gas, for $4.3 million, with estimated proved reserves of 1.8 Bcfe;
	§		In Arkoma, we continued to expand our developmental drilling program and implemented successful recompletion and compression programs designed to improve operating efficiencies and minimize production downtime. In addition, we participated with a 40% working interest in eight successful wells, adding approximately 20 new locations for future drilling, in the new Rich Mountain Field located in close proximity to our Chismville Field in Logan County, Arkansas;
	§		In East Texas, we continued the expansion of our operating base begun in 2005 and focused our drilling efforts on properties acquired in 2005. In April 2006, we acquired additional producing properties and acreage adjacent to our Willow Springs Field with an estimated 16.2 Bcfe of proved reserves as of January 1, 2006, from Samson Lone Star Limited Partnership for a net purchase price of $21.3 million;
	§		In the Rocky Mountains, we completed and began processing a 150 square mile 3D seismic survey in the DJ Basin and successfully drilled and completed 100 new wells within the Niobrara Trend. During the first quarter of 2006, we initiated the second phase of our DJ Basin gathering system, bringing on-line more than 50 wells drilled during 2005. For the year, we added a net 24 Bcfe through the drill bit, which includes downward revisions of 4 Bcfe, primarily as a result of price economics. Average daily production increased approximately 60% to 8 MMcfe per day. In December, we acquired incremental working interests and interests in new producing properties and undeveloped acreage located in the DJ Basin with an estimated 14.2 Bcfe of proved reserves as of November 1, 2006, from Santos TOG Corp. for a net purchase price of $21.4 million;
	§		During May and June, we repurchased 1,176,500 shares, or approximately 4%, of our outstanding common stock, in the open market for approximately $61.6 million. These repurchases were funded with cash on hand and borrowings under our bank credit facility;
	§		During June, we paid $14.3 million to liquidate and settle derivative contracts covering 60,000 MMBtu per day for each of the months July through December 2006, reducing our volume hedged from 250,000 MMBtu per day to 190,000 MMBtu per day as required by our bank credit facility in connection with our Gulf of Mexico sale. In addition, during August, we paid $0.9 million to liquidate and settle derivative contracts covering 20,000 MMBtu per day for each of the months September and October 2006, for a total of $15.2 million paid to liquidate derivative contracts during 2006;
	§		As a result of the settlement and liquidation of derivative contracts during 2006, combined with significantly lower market prices for natural gas and fewer open contracts covering 2007 and 2008 production volumes at year-end 2006, the fair market value of our open derivatives contracts decreased from a liability of $417.7 million ($269.8 million net of tax) at December 31, 2005 to a liability of $27.4 million ($17.5 million net of tax) at December 31, 2006. The decline of natural gas prices during the third and fourth quarters was a key factor in the decline in our losses from hedging activities that totaled $64.5 million for 2006 compared to a total net loss of $264.5 million incurred during 2005, of which $116.5 million was incurred during the fourth quarter of 2005; and
	§		At December 31, 2006, due to the cumulative effect of higher finding and development costs during recent years, combined with higher estimated future operating and development costs at year-end 2006, we recorded a writedown in the carrying value of our natural gas and oil properties, taking a non-cash charge and reduction to earnings in the fourth quarter of approximately $19.0 million ($12.3 million net of tax).

Operating and Financial Results for 2006 compared to 2005 and Operating and Financial Results for 2005 compared to 2004.

The comparability of our operating and financial results for 2006 to 2005 was significantly impacted by the sale of substantially all of our Gulf of Mexico assets during the first half of 2006 and the continued effects of production curtailments caused by damage to third party pipelines and processing facilities from the 2005 Hurricanes Katrina and Rita on these offshore assets prior to the completion of their sale on June 1, 2006. Our operating results for the year ended December 31, 2006 include production, revenues and expenses relating to our Texas Gulf of Mexico properties until the completion of their sale on March 31, 2006 and our Louisiana Gulf of Mexico properties until the completion of their sale on June 1, 2006.

For 2005, the comparability of operating and financial results to 2004 was significantly impacted by offshore production curtailments caused by Hurricanes Katrina and Rita during August and September 2005.

		Year Ended December 31,																Year Ended December 31,
Summary Operating Information:		2006				2005				Change				%				2005				2004				Change				%
		(in thousands, except prices and percentages)
Operating revenues		$	531,597			$	621,543			$	(89,946	)			-14	%		$	621,543			$	650,439			$	(28,896	)			-4	%
Operating expenses			404,749				436,807				(32,058	)			-7	%			436,807				382,626				54,181				14	%
Income from operations			126,848				184,736				(57,888	)			-31	%			184,736				267,813				(83,077	)			-31	%
Net income			67,783				105,169				(37,386	)			-36	%			105,169				162,824				(57,655	)			-35	%
Production:
Natural gas (MMcf)			82,528				105,809				(23,281	)			-22	%			105,809				115,855				(10,046	)			-9	%
Oil (MBbls)			938				1,417				(479	)			-34	%			1,417				1,355				62				5	%
Total (MMcfe) (1)			88,156				114,311				(26,155	)			-23	%			114,311				123,985				(9,674	)			-8	%
Average daily production (MMcfe/d)			242				313				(71	)			-23	%			313				339				(26	)			-8	%
Average Sales Prices:
Natural Gas (per Mcf) unhedged		$	6.56			$	7.71			$	(1.15	)			-15	%		$	7.71			$	5.78			$	1.93				33	%
Natural Gas (per Mcf) realized (2)			5.72				5.21				0.51				10	%			5.21				5.19				0.02				—
Natural Gas (per Mcf) “all-in”(3)			5.77				5.21				0.56				11	%			5.21				5.17				0.04				1	%
Oil (per Bbl) realized			56.56				48.43				8.13				17	%			48.43				36.85				11.58				31	%