UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

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

Commission File No. 001-11899

THE HOUSTON EXPLORATION COMPANY

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

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act: None

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 an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1,112,109,212, based on the closing sales price of $51.84 per share of the registrant’s common stock as reported by on the New York Stock Exchange as of June 30, 2004, the last business day of the registrant’s most recently completed second fiscal quarter. For purposes of the preceding sentence only, all directors, executive officers and beneficial owners of ten percent or more of the common stock are assumed to be affiliates. As of February 22, 2005, 28,457,804 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 April 26, 2005 are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

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Forward-Looking Statements and Other Information

This Annual Report on Form 10-K (“Annual Report”) and the documents we have incorporated by reference into this Annual Report contain forward-looking statements as that term is defined in 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 statements use forward-looking words such as “anticipate,” “believe,” “continue,” “expect,” “estimate,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should,” “target,” “goal,” “objective” or other similar expressions and discuss forward-looking information. Forward-looking statements include all statements under the caption “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” involving the discussion of the following:

Although we believe that these forward-looking statements are based on reasonable assumptions, our expectations may not occur and we cannot guarantee that the anticipated future results will be achieved. A number of factors could cause our actual future results to differ materially from those anticipated or implied in the forward-looking statements. These factors include, among other things:

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For additional discussion of these and other risks, uncertainties and assumptions, see “Items 1 and 2. Business and Properties” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in this Annual Report. We undertake no obligation to publicly update or revise any forward-looking statements.

In this Annual Report, unless the context requires otherwise, when we refer to “we,” “us” and “our,” we are describing The Houston Exploration Company and our former sole subsidiary on a consolidated basis.

If you are not familiar with the natural gas and oil terms used in this Annual Report, please refer to the explanations of the terms under the caption “Glossary of Natural Gas and Oil Terms” included on pages G-1 through G-2. When we refer to “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one barrel of oil is equal to six thousand cubic feet of natural gas.

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Part I.

Items 1. and 2. Business and Properties

Overview of Our Business

We are an independent natural gas and oil producer concentrating on growing reserves and production through the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. Approximately 94% of our proved reserves as of December 31, 2004 were natural gas. Our principal operations are located in the following areas:

At December 31, 2004, net proved reserves were 793 billion cubic feet equivalent or Bcfe, with a standardized measure of future net cash flows including income taxes, discounted at 10% per annum, of $1.4 billion. Our reserves are fully engineered on an annual basis by independent petroleum engineers. Approximately 63% of our proved reserves at December 31, 2004, were classified as proved developed. As of December 31, 2004, we operated approximately 77% of our producing wells. Daily production averaged 339 million cubic feet of natural gas equivalent or MMcfe in 2004.

We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and oil on behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poor’s 500 Index, is a diversified energy provider whose principal natural gas distribution and electric generation operations are located in the Northeastern United States. In September 1996, we completed our initial public offering and sold approximately 31% of our shares to the public. Through three separate transactions, the first in February 2003 and last in November 2004, KeySpan completely divested of its investment in the common stock of our company. As of December 31, 2004, KeySpan no longer owned any common stock of our company.

Our corporate offices are located at 1100 Louisiana Street, Suite 2000, Houston, Texas 77002. Our telephone number is (713) 830-6800.

Business Strategy

We strive to maximize shareholder value by growing reserves, production, cash flow and net asset value on a per share basis while maintaining our financial flexibility and discipline. We incorporate the following operating philosophies in executing our strategy:

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Properties and Operating Areas

The table below summarizes certain data for our core operating areas for the year ended December 31, 2004.

Activity and Balances as of or for the Year Ended December 31, 2004

South Texas. Our South Texas properties are concentrated in the Charco, Haynes and South Trevino Fields of Zapata County; the Alexander, Hubbard and South Laredo Fields of Webb County; and the Northeast Thompsonville Field in Jim Hogg County. As of December 31, 2004, our South Texas properties cover approximately 67,900 net acres and we own interests in 640 producing wells, 534 or 83% of which we operate. Our average working interest is 83%. Average well depth is between 8,000 to 12,500 feet with production from the Wilcox formations.

When we acquired the Charco Field in July 1996, it had approximately 150 producing wells and average daily production was 38 MMcfe per day, net to our interest. We expanded our existing production and reserve base with the acquisition of the Alexander, Hubbard and South Laredo Fields in December 2001, and again, in May 2002, with the acquisition of the Northeast Thompsonville Field. During 2004, we expanded our acreage position in Zapata County with the acquisition of undeveloped acreage in the Cisco-Benavides Field for $2.7 million, and purchased incremental working interests in several producing wells in the North East Thompsonville Field for $3.3 million. In total, our net South Texas production has more than tripled since July 1996, to an average of 142 MMcfe per day during 2004, which compares to 140 MMcfe per day in 2003. Over the course of eight and a half years, we have drilled 284 successful wells at an average success rate of 80%, produced 293 Bcfe and added 507 Bcfe in reserves through drilling and acquisitions. As we see our South Texas properties begin to mature and production growth to minimize, we plan to maintain production at existing levels while improving drilling and operating efficiencies in an effort to control finding and operating costs.

Gulf of Mexico. Our offshore properties are located in the shallow waters of the Outer Continental Shelf. Our key producing properties are located in the western and central Gulf of Mexico and include the Mustang Island, High Island, East Cameron, Vermilion and West Cameron areas. In October 2003, we added to our existing production base through the acquisition of 11 producing fields in the central Gulf of Mexico. The properties were purchased for a net $147.5 million and had estimated proved reserves of 88.5 Bcfe at October 15, 2003. During the second half of 2004, we again added to our offshore shore production base through two producing property acquisitions. On a combined basis, the properties were purchased for a net $139.8 million, had estimated proved reserves of 76.9 Bcfe at acquisition, and covered 12 blocks in the Central Gulf of Mexico. As of December 31, 2004, we hold interests in 142 blocks in federal and state waters, of which 78 are developed. As of December 31, 2004, we operated 45 of our developed blocks, which accounted for approximately 70% of our offshore production during 2004. We have a total of 92 producing platforms and production caissons, of which we operate 60. During 2004, production from our Gulf of Mexico properties averaged 153 MMcfe per day.

During the last two years, our offshore operation has evolved from almost exclusively an exploration focus to a blended enterprise with substantial elements of new project exploration and exploitation activities aimed at maximizing production from older, previously produced fields acquired from third parties. Going forward, we expect to continue to evaluate the profitability of each of our core operating areas and shift our emphasis between exploration and exploitation in response to operational developments and economic factors.

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, 2004, we had approximately 35,400 net acres under lease and we owned working interests in 349 producing natural gas wells, 232 of which we operated. Wells average a depth of 5,500 feet and production is from the Atoka formation. As a result of continued downspacing of in-field drilling by the Arkansas Oil and Gas Commission, first in September 2002 from 680 acres to 160 acres per well and again in September 2003 from 160 acres per well to 80 acres per well, we were able to increase the number of wells drilled during 2004 to 79 wells from 51 wells drilled in 2003 and 24

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wells drilled in 2002. During 2004, average daily production increased by 65% from 23 MMcfe per day during 2003 to 38 MMcfe per day during 2004. Acquisition values in the Arkoma Basin have impeded the expansion of our operations beyond our existing acreage position and, as a result, our current activities are focused on the substantial number of in-field drilling opportunities within our existing acreage. The Arkansas Oil and Gas Commission has approved downspacing from 320 acres per well in 2002 to approximately 40 acres per well as of December 2004, facilitating the expansion of our in-field drilling opportunities.

Rocky Mountains. During 2003, we began a lease acquisition initiative in the Rocky Mountain region, initially leasing more than 200,000 net undeveloped acres encompassing portions of the Uinta Basin of Northeastern Utah, the Williston Basin spanning North and South Dakota, the Crazy Mountain Basin of Southwestern Montana, and the Green River Basin of Southwestern Wyoming. Our primary focus for 2004 was proving up and delineating portions of our Uinta Basin acreage, where we drilled a total of 26 wells, of which 25, or 96%, were successful. At December 31, 2004, 19 of our Uinta wells were shut-in and awaiting approvals for pipeline right-of-ways. In January 2005, 11 of the 19 Uinta wells came on-line with estimated initial production rates, on a combined basis, of approximately 8 MMcfe per day, net to our interest.

In August 2004, we acquired approximately 330,000 net acres in the DJ Basin of Eastern Colorado. During the second half of 2004, we drilled four wells and successfully completed three or 75%. Pipeline installation and hookup are expected for these DJ Basin wells during 2005. At December 31, 2004, we had estimated proved reserves in the Rocky Mountains of 22 Bcfe and our daily production averaged 4 MMcfe per day, net to our interests.

Other. As of December 31, 2004, “other” includes our East Texas properties and two fields located in Central Mississippi. The East Texas properties are located in the Willow Springs Field in Gregg County, Texas and include interests in 24 wells, all of which we operate. The Mississippi properties were acquired in October 2004 as part of our acquisition of 10 offshore blocks in the shallow waters of the Central Gulf of Mexico and consist of two fields containing three producing wells, all of which are non-operated. The Wausau Field is located in Wayne County and the Oakvale Dome Field is located in Jefferson Davis County. In addition to these properties, we have interests or rights of an immaterial nature in other prospective properties or projects with respect to which no reserves are currently associated, and may make future investments of immaterial amounts in similar such projects from time to time in the future.

2004 Divestures

In February 2004, we completed the sale of our South Louisiana properties for net proceeds of $13.1 million. The properties were located in the South Lake Arthur and Lake Pagie Fields located primarily in Vermilion and Terrebonne Parishes. The properties represented 12.3 Bcfe proved reserves as of December 31, 2003, and included interests in 33 gross (9.5 net) producing wells and covered approximately 6,300 gross (2,300 net) acres. Production averaged 5 MMcfe/day during 2003.

In June 2004, we divested of our Appalachian Basin assets as part of an asset exchange transaction with KeySpan. The properties were located primarily in central West Virginia and included the Belington, Clarksburg and Seneca Upshur Fields located in Barbour, Randolph, Upshur and Mingo Counties of West Virginia. Included were the assets acquired on December 31, 2003 from EnerVest East Limited Partnership that were located adjacent to our existing base in the Crawford and Pennsboro Fields in Lewis, Harrison, Tyler and Ritchie Counties of West Virginia and the Waynesburg and Yatesboro Fields in Greene and Armstrong Counties of southwestern Pennsylvania. Based on internal estimates at June 1, 2004, the properties had 51.2 Bcfe of proved reserves with an agreed upon fair value of $60 million. Our average daily production was approximately 8 MMcfe/day at May 21, 2004. We had approximately 207,000 gross (129,000 net) acres under lease and owned working interests in approximately 1,414 gross (1,035 net) wells, of which we operated approximately 92% of the wells.

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Natural Gas and Oil Reserves

The following table summarizes the estimates of historical net proved reserves as of December 31, 2004, 2003 and 2002, and the present values attributable to these reserves at these dates. The reserve data and present values were fully engineered by Netherland, Sewell & Associates, Inc. or Miller and Lents, Ltd., independent petroleum engineering consultants.

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. Volatility is expected to continue and price fluctuations 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 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.

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Drilling Activity

We engage in numerous drilling activities on properties presently owned by us and intend to drill or develop other properties we may acquire in the future. The following table sets forth the results of our drilling activities for the years ended December 31, 2004, 2003 and 2002. 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.

As of December 31, 2004, we were drilling or participating in the drilling of 22 gross (18.2 net) wells. Of these wells, through February 22, 2005, 17 gross (15.9 net) wells have been determined to be successful and 2 gross (1.5 net) were unsuccessful, with the remaining 3 gross (0.8 net) wells still in progress.

Productive Wells

The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2004. Productive wells consist of producing wells and wells capable of production, including 28 wells, 22 of which were located in the Rocky Mountains, awaiting connections. Wells that are completed in more than one producing horizon are counted as one well. The “operator” is the designated party under the terms of an operating agreement that manages the day-to-day operations of the well.

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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, 2004. 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.

Undeveloped Acreage Expirations

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

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

We enter into hedging transactions with unaffiliated third parties for portions of our natural gas production to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in gas prices. For a more detailed discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

We incur gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third party transporter. We do not have any material transportation agreements and we have not contracted for firm capacity for which we would pay monthly demand charges. Our natural gas and oil are transported through third party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has only been infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. See the section entitled “Risk Factors — Our business depends on oil and natural gas transportation facilities that are owned by others.”

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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 of the undeveloped property, are typically responsible for curing any title defects at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. Prior to completing an acquisition of producing natural gas and oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion. Our natural gas and oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Competition

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of additional properties and acreage. This competition is intensifying 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 and which, in many instances, have been engaged in the oil and gas business for a much longer time than we have. Our ability to acquire additional properties and to discover new reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Seasonal Nature of Business

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

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 affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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

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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.

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:

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, 2004, we did not incur any material capital expenditures for environmental control facilities. As of the date of our Annual Report, we are not aware of any environmental issues or claims that will require material expenditures during 2005 or that will have a material impact on our financial position or results of operations.

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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.

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.

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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.

Natural Gas Sales 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, unregulated, 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 less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what affect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. In offshore Federal waters, gathering is regulated by FERC under the Outer Continental Shelf Lands Act. The Outer Continental Shelf Lands Act requires open access and non-discriminatory rates, but does not provide for cost-based rates. Although its policy is still in flux, FERC has recently reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.

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Risk Factors Affecting Our Business

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

As an independent natural gas and oil producer, our revenues are highly dependent on the price of, and demand for, natural gas and oil. 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:

We cannot predict future natural gas and oil price movements. If natural gas and oil prices decline, the amount of natural gas and oil we can economically produce may be reduced, which may result in a material decline in our revenues.

We may be required to take additional 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 when natural gas and oil prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results.

We utilize the full cost method of accounting for natural gas and oil exploration and development activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of our natural gas and oil properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges, calculated using prevailing prices on the last day of the period. If the net book value of our natural gas and oil properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds our ceiling limitation, SEC regulations require us to impair or “writedown” the book value of our natural gas and oil properties. Depending on the magnitude of any future impairments, a ceiling test writedown could significantly reduce our income, or produce a loss. As ceiling test computations involve the prevailing price on the last day of the quarter, it is impossible to predict the timing and magnitude of any future impairments. The book value of our proved natural gas and oil properties increased in 2004 as a function of our higher acquisition, exploration and development costs for the year and the increase in future development costs associated with reserves added during the year. To the extent our finding and development costs continue to increase, we will become more susceptible to ceiling test writedowns in low price environments.

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

The amount of borrowings available to us under our revolving bank credit facility is determined by reference to a borrowing base. The amount of our borrowing base is established by our banks and is primarily a function of the quantity and value of our reserves. Our borrowing base is re-determined at least twice a year to take into account changes in our reserve base and prevailing commodity prices. Our current borrowing base is $400 million. 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

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at lower price levels. Additionally, the indenture governing our 7% senior subordinated notes due 2013 conditions our ability to incur additional indebtedness on our satisfaction of tests relating to “earnings before interest, taxes and depreciation, depletion and amortization expense” and “consolidated net tangible assets” (as defined in the indenture), both of which are sensitive to commodity prices. Consequently, the amount of borrowing available to us under our revolving bank credit facility as well as our ability to incur additional indebtedness under our senior subordinated notes could be adversely affected by extended periods of low commodity prices.

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.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as they are produced. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Virtually all of our onshore production is located in prolific natural gas producing regions where completion techniques result in hyperbolic production decline profiles characterized by high initial production rates, followed by rapid intermediate production declines, and culminating in a long-term low production rate subject to a shallow decline. Likewise, our offshore production is generally characterized by small reservoirs with high porosity and permeablilty rocks that produce at very high rates but typically deplete rapidly. Because of the high-rate production profiles of our properties, replacing produced reserves is more difficult 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 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 the cost of finding new reserves through exploration and development operations has been increasing. 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 climbed toward historic highs during 2004 on a per unit basis, particularly in our focus areas of South Texas and the Rocky Mountain regions, and we believe these values may continue to increase in 2005. For full cost companies such as ours, this increase in finding and development costs is resulting in higher depreciation, depletion and amortization rates. If the upward trend in finding and development costs continues, we and other full cost companies will be exposed to an increased likelihood of a writedown in carrying value of our natural gas and oil properties in response to falling prices, which would impair our profitability.

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

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

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

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering, geological interpretation and judgment and the assumptions used regarding quantities of recoverable natural gas and oil reserves and prices for crude oil and natural gas. 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

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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, results of drilling, testing and production and changes in crude oil and natural gas prices after the date of the estimate may result in revisions to our reserve estimates. During 2004 and 2003, we incurred downward revisions of our proved reserves of 20 Bcfe and 40 Bcfe, respectively, either from proved undeveloped reserves that were depleted or otherwise not recoverable, or from production performance indicating less gas in place or smaller reservoir size than initially estimated.

The reserve data contained in this Annual Report represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological 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 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 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 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 debt or equity financing, 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:

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We are insured against some, but not all, of the hazards associated with our business, although we believe this is standard practice in our industry. Because of this practice, however, we may be liable or 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.

Our reserves, production and cash flow are highly dependent upon operations that are concentrated in three primary areas.

During 2004, we generated approximately 98% of our production from three primary areas of operation, with 42% from South Texas, 45% from offshore Gulf of Mexico and 11% from the Arkoma Basin. The concentrated nature of our operations subjects us to the risk that a regional event could cause a significant interruption in our production or otherwise have a material affect on our profitability. This is particularly true of our offshore operations, which are susceptible to 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.

Our hedging activities could result in financial losses or reduce our income.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and expect to in the future enter into hedging arrangements for a significant portion of our natural gas and oil production. For both 2005 and 2006, we have entered into derivative instruments relating to approximately 70% of our planned production utilizing a variety of instruments, including fixed price swaps and collars. We have begun to establish hedging positions for 2007 and 2008. The derivative instruments that we employ require us to make cash payments to the extent the NYMEX index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in natural gas prices. As we typically index our derivative instruments to NYMEX prices as opposed to the local indices where we sell our gas, our hedging strategy may not protect our cash flows if basis differentials increase between the NYMEX and local prices. Under SFAS 133, our income could be negatively affected to the extent our NYMEX-indexed derivative instruments are deemed ineffective in hedging price fluctuations at our sales points. In addition, if we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Another risk of hedging activities is that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge. It is also important to note that it is not practical to hedge the cash flows relating to all of our production, and we therefore retain the risk of a price decrease on our unhedged volumes.

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 throughout 2003 and 2004. Given this extended strong demand for drilling rigs and other oil field services necessary to our operation, we began experiencing increased service and material costs in the second half of 2004, as well as longer lead times and reduced service availability. We anticipate that this trend will continue in 2005. If current utilization rates continue at fourth-quarter 2004 levels or increase, a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop, especially in the areas where we operate. Should this transpire, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. If we do not have

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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 unavailability of or lack of available capacity on these systems and related facilities could result in the shut-in of producing wells or the delay or discontinuation of development plans for 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.

Our investments in the Rocky Mountains may not be successful.

Our future growth plans rely in part on establishing significant production and reserves in the Rocky Mountains, particularly the Uinta Basin in Utah and the DJ Basin in Colorado. To date, we lack sufficient production history from these areas to accurately estimate the likelihood that our endeavors will yield meaningful reserves and production with an acceptable rate of return. Certain of our exploration objectives in the Rocky Mountain area involve geology types and mechanical operations that differ substantially from our historic operations in South Texas and the Arkoma Basin. In addition, operations in the Rocky Mountain region present unique operational challenges, such as more acute transportation constraints, higher pricing differentials, and more extensive regulatory oversight. For example, 22 of the 25 successful wells that we drilled during 2004 in the Uinta Basin where shut in at year end awaiting right of way approval from the U.S. Bureau of Land Management (the “BLM”). Increased drilling in the vicinity of our Rocky Mountain acreage has also resulted in the EPA increasingly requiring the preparation of environmental assessments or more comprehensive environmental impact statements, as a condition to conducting operations on certain lands that the BLM administers. Any or all of these contingencies could delay or halt our drilling activities or the construction of ancillary facilities necessary for production, which would prevent us from developing our property interests in the Rocky Mountains as planned. This could in turn impede our growth, as we intend to undertake significant activity in order to increase our production and reserves in this area in the future.

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 investigating and remedial obligations, and the issuance of injunctions limiting or prohibiting our operations. We have made and plan to continue making all necessary expenditures, both financial and managerial, in our efforts to comply with the requirements of environmental and governmental regulations. 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, lease, and have in the past owned or leased, numerous properties that have been used for the exploration and production of oil and gas for many years. Although we have used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed 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 or released by prior operators of properties that we are acquiring as well as by current third party operators of properties in which we have an ownership interest. Properties impacted by any such disposal 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, also known as “CERCLA” or the “Superfund” law, the federal Oil Pollution Act or “OPA,” the federal Resource Conservation and Recovery Act or “RCRA,” 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 currently do not expect any remedial obligations imposed under environmental laws to have a significant effect on our operations.

We face strong competition.

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As an independent natural gas and oil producer, we face strong competition in all aspects of our business. Many of our competitors are large, well-established companies that have substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for productive natural gas and oil properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial and human resources permit.

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

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

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

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

Employees

As of December 31, 2004, we had 155 full time employees, 121 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 is represented by a labor union or other collective bargaining arrangement. We employ the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design and well-site surveillance, permitting and environmental assessment. At our direction, independent contractors usually perform field and on-site production operation services, including pumping, maintenance, dispatching, inspection and testing.

Offices

We currently lease approximately 91,600 square feet of office space in Houston, Texas, at 1100 Louisiana Street, where our principal offices are located. We lease approximately 2,250 square feet of office space in Denver, Colorado, at 700 17^th Street. In addition, we maintain field operations offices in South Texas, Arkansas, and East Texas.

Available Information

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

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

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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.

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

Item 3. Legal Proceedings

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

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

No matters were submitted to a vote of our security holders during the last quarter of the fiscal year ended December 31, 2004.

Part II.

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

Our common stock is traded on the New York Stock Exchange under the symbol “THX.” The following table sets forth the range of high and low sales prices for each calendar quarterly period from January 1, 2003, through December 31, 2004 as reported on the New York Stock Exchange:

As of February 22, 2005, 28,457,804 shares of common stock were outstanding, and we had approximately 50 stockholders of record and approximately 14,800 beneficial owners.

Dividends

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

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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, 2004. 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.

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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 conditions. 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” and Other Information at the beginning of this Annual Report and “Risk Factors Affecting Our Business” beginning on page 15 for additional discussion of some of these factors and risks.

Overview of Our Business

We are an independent natural gas and oil producer concentrating on growing reserves and production through the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. Our core areas of operations are South Texas, offshore in the shallow waters of the Gulf of Mexico and the Arkoma Basin of Oklahoma and Arkansas. During 2003, we initiated operations in the Rocky Mountain Region, with an initial focus in the Uinta Basin of northeastern Utah, and during 2004, we expanded our focus to include the DJ Basin of Eastern Colorado. In February 2004, we divested our South Louisiana assets and in June 2004, we divested our Appalachian Basin assets in connection

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with the KeySpan Exchange transaction described in Note 3 – Stockholders’ Equity – KeySpan Exchange and Offering of Item 15 contained in this Form 10-K. We operate as one segment as each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information.”

At December 31, 2004, net proved reserves were 793 billion cubic feet equivalent or Bcfe, with a present value of future net cash flows before income taxes, discounted at 10% per annum, of $2.2 billion and standardized measure of future net cash flows including income taxes, discounted at 10% per annum, of $1.4 billion. Our reserves are fully engineered on an annual basis by independent petroleum engineers. Approximately 94% of our proved reserves at December 31, 2004, were natural gas, approximately 63% of which were classified as proved developed. As of December 31, 2004, we operated approximately 77% of our producing wells. Daily production averaged 339 million cubic feet of natural gas equivalent or MMcfe in 2004.

We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and oil on behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poor’s 500 Index, is a diversified energy provider whose principal natural gas distribution and electric generation operations are located in the Northeastern United States. In September 1996 we completed our initial public offering and sold approximately 31% of our shares to the public. Through three separate transactions, the first in February 2003 and the last in November 2004, KeySpan completely divested of its investment in the common stock of our company. As of December 31, 2004, KeySpan no longer owned any common stock of our company. See Note 3 – Stockholders’ Equity and Note 6 – Related Party Transactions for a complete description of these three transactions.

Source of Our Revenues

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

Principal Components of Our Cost Structure

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Industry Environment

We currently operate in North America. After over 100 years of active natural gas and oil exploration and production within the lower 48 states and Gulf of Mexico, the region is maturing and production growth is slowing or possibly declining. Numerous technological advances during this timeframe, including increasingly sophisticated geophysical tools that allow more accurate identification of reservoirs, horizontal and other drilling technologies that facilitate and enhance the extraction process, and advanced completion techniques have accelerated both production and depletion rates. While new discoveries are still being made in North America, the frequency and size of these discoveries is declining while the finding and development costs are increasing. As a result, given our current technology, domestic natural gas and oil production as a whole may be at or near its peak and can be expected to decline in the future, with the exception of regions such as the Rocky Mountains.

In this mature environment, companies will find it increasingly difficult to replace their reserves through traditional exploration and development efforts, and companies will increasingly be forced to rely on acquisitions to sustain their growth. Our future success in growing our reserve base at an acceptable finding cost will depend in large part on our ability to acquire new proved reserves and unevaluated acreage on which we can explore. We currently maintain a very active acquisition program and expect to continue to devote significant resources to identifying and pursuing both tactical acquisitions that augment our existing property base as well as substantial strategic acquisitions.

We anticipate that the continued decline of the North American gas basins will lead to higher cost structures throughout our industry. We currently believe that the cost of finding, developing and producing new natural gas and oil reserves through exploration and development operations will rise as the industry makes fewer discoveries and such discoveries generally tend to decrease in reserve size. In addition, we believe the acquisition market for natural gas properties has become extremely competitive as producers vie for additional production and expanded drilling opportunities in North America. Acquisition values climbed toward historic highs during 2004 on a per unit basis, particularly in our focus areas of South Texas and the Rocky Mountains, and we expect acquisition values to continue to climb in 2005. For full cost companies such as ours, increases in both acquisition and finding and development costs, are expected to yield higher depreciation, depletion and amortization rates and ultimately, could increase the likelihood of a writedown in carrying value of our natural gas and oil properties if commodity prices fall substantially below current levels. In addition, we expect drilling costs, especially in the Gulf of Mexico, and lease operating expenses to continue to rise as producers are forced to make operational enhancements to maintain aging fields.

Like any commodity, the price that we receive for the gas we produce is largely a function of supply and demand. Demand for natural gas is affected by general economic conditions, such as growth in the space heating, industrial and power generation segments, and seasonal conditions. Demand has also typically been impacted by seasonal fluctuations, with the peak demand during the winter heating season and summer air conditioning season. As natural gas is difficult to import, 80% to 85% of the United States’ natural gas demand in recent years has been supplied by domestic production. Imports from Canada have made up 10% to 15% of the United States’ natural gas needs and imports from a variety of other countries now make up for 1% to 2% of total supply in the form of liquefied natural gas, or LNG.

Situations involving over or under supply of natural gas can result in substantial price volatility. Continued concerns over the United States’ ability to meet its longer-term gas needs from declining domestic supply have resulted in sustained prices above $5.00 throughout 2003, 2004 and continuing into 2005. As a direct result of the strong commodity prices during 2004, we were able to increase our net income, generate substantial cash flows to fund acquisitions, our capital budget and repay borrowings on our revolving bank credit facility. However, historically, commodity prices have been very volatile, and we expect the volatility to continue in the future. As a result, we cannot accurately predict future natural gas and oil prices, and, therefore, we cannot determine what effect increases or decreases will have on our future revenues and cash flows. A substantial or extended decline in natural gas and oil prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas and oil reserves that may be economically produced and our ability to access capital markets. Our continued growth and profitability depends on the strength of natural gas prices and our ability to acquire, find and develop new reserves at economical costs.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make assumptions and prepare estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and revenues and expenses. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ. We evaluate our assumptions and estimates on a regular basis and discuss the development and disclosure

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process with our Audit Committee. See Note 1 - Summary of Organization and Significant Accounting Policies of Item 8 contained in this Form 10-K for a discussion of our significant accounting policies.

Proved Reserves. Our 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 relies on assumptions and 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 changing market conditions, commodity prices and future development costs will change from year to year, causing estimates of proved reserves to also change. For the years ended December 31, 2004 and 2003, we revised our proved reserves downward from prior years’ reports by approximately 20 Bcfe and 40 Bcfe, respectively, due to proved undeveloped reserves that were depleted or otherwise not recoverable, or from production performance indicating less gas in place or smaller reservoir size than initially estimated. Estimates of proved reserves are key components of our most significant financial estimates involving our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. Our reserves are fully engineered on an annual basis by independent petroleum engineers.

Unevaluated Properties. The balance of unevaluated properties is comprised of capital costs incurred for undeveloped acreage, seismic data, wells and production facilities in progress, wells pending determination and related capitalized interest. These costs are initially excluded from our amortization base until the outcome of the project has been determined, or generally, until it is known whether proved reserves will or will not be assigned to the property. We assess all items in our unevaluated property balance on a quarterly basis for possible impairment or reduction in value. We believe that substantially all of the costs included in our unevaluated property balance will be evaluated in the next four years.

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

Derivative Instruments. Under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we reflect the fair market value of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes from counterparties, as well as utilizing a Black-Scholes option valuation model that is based upon underlying forward price curve data, a risk-free interest rate and estimated volatility factors.

In addition to the critical estimates discussed above, estimates are used primarily in accounting and computing depreciation, depletion and amortization, the full cost ceiling, taxes, accruals of operating costs and production revenues, effectiveness of derivative instruments and fair value of stock options and related compensation expense.

New Accounting Pronouncements

On September 28, 2004, the SEC released Staff Accounting Bulletin (“SAB”) 106 regarding the application of SFAS 143, “Accounting for Asset Retirement Obligations (“AROs”),” by oil and gas producing companies following the full cost accounting method. Pursuant to SAB 106, oil and gas producing companies that have adopted SFAS 143 should exclude the future cash outflows associated with settling AROs (ARO liabilities) from the computation of the present value of estimated future net revenues for the purposes of the full cost ceiling calculation. In addition, estimated dismantlement and abandonment costs, net of estimated salvage values, that have been capitalized (ARO assets) should be included in the amortization base for computing depreciation, depletion and amortization expense. Disclosures are required to include discussion of how a company’s ceiling test and depreciation, depletion and amortization calculations are impacted by the adoption of SFAS 143. SAB 106 is effective prospectively as of the beginning of the first fiscal quarter beginning after October 4, 2004. Since our adoption of SFAS 143 on January 1, 2003, we have calculated the ceiling test and our depreciation, depletion and amortization expense in accordance with the interpretations set forth in SAB 106; therefore, the adoption of SAB 106 had no effect on our financial statements.

On December 16, 2004, the FASB revised Statement 123 (revised 2004), “Share-Based Payment” that will require compensation costs related to share-based payment transactions (e.g., issuance of stock options and restricted stock) to be

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recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. Statement 123(R) replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” For us, SFAS 123(R) is effective for the first quarterly reporting period after June 15, 2005. Entities that use the fair-value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123(R) using a modified version of prospective application. Under this method, an entity records compensation expense for all awards it grants after the date of adoption. In addition, the entity is required to record compensation expense for the unvested portion of previously granted awards that remain outstanding at the date of adoption. In addition, entities may elect to adopt SFAS 123(R) using a modified retrospective method where by previously issued financial statements are restated based on the expense previously calculated and reported in their pro forma footnote disclosures.

On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123 as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” using the “prospective method” as defined by the SFAS 148. As a result, we have recognized compensation expense for all stock options granted subsequent to January 1, 2003 with no expense recognized for grants made prior to 2003. Adoption of SFAS 123(R) will require us to recognize compensation expense over the remaining service period for the unvested portion of all options granted during 2000, 2001 and 2002. All options granted prior to 2000 are fully vested. We expect to adopt SFAS 123(R) on January 1, 2005, using the modified version of prospective application and are currently evaluating the effect of adopting SFAS 123(R).

On December 16, 2004, the FASB issued Statement 153, “Exchanges of Nonmonetary Assets”, an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetrary exchanges of similar productive assets. SFAS 153 eliminates the exception from the fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not have any nonmonetary transactions for any period presented that this Statement would apply. We do not expect the adoption of SFAS 153 to have a material impact on our financials statements.

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Overview of 2004 Results

The sustained strength of commodity prices throughout 2004 and production growth of 15% generated from all core operating areas were the primary factors behind results for operations, earnings and cash flows for 2004. The increase in our cash flows from operations allowed for increased capital spending from prior year levels for drilling and acquisitions and the repurchase and retirement of a portion of our common stock from KeySpan. During 2004:

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Operating and Financial Results for 2004 Compared to 2003 and Operating and Financial Results for 2003 Compared to 2002

Income from Operations

Production growth and higher realized natural gas prices were the primary factors contributing to our 35% increase in operating income in 2004 over 2003. Increased revenues were offset in part by a 30% increase in operating expenses.

Higher natural gas prices were the primary factor contributing to our 86% increase in net income and our 84% increase in operating income in 2003 over 2002. Adding to the effects of higher commodity prices realized in 2003 was an increase of 5% in production volume from 2002 levels. Increased revenues were offset in part by a 24% increase in operating expenses during 2003 due primarily to the continued expansion of our operations combined with an increase in costs to maintain our existing production base together with higher depreciation, depletion and amortization rates.

Production Volume 2004 vs. 2003

The 15% increase in production for 2004 is primarily a result of both production added from Gulf of Mexico properties acquired during the fourth quarter of 2003 as well as newly developed production, both onshore and offshore, from our existing property base.

Onshore. Daily production rates increased 8% from an average of 173 MMcfe per day in 2003 to 186 MMcfe per day in 2004, despite our loss of approximately 8 MMcfe per day as a result of the divesture of our South Louisiana and Appalachian Basin properties during the first half of 2004. The Arkoma Basin was our onshore growth area during 2004. We experienced the full impact of the accelerated drilling program initiated in 2003 that continued throughout 2004 as we added 15 MMcfe per day in newly developed production. With three rigs drilling through the first 10 months of 2004, Arkoma production reached a record of 44 MMcfe per day during the fourth quarter compared to 25 MMcfe per day during the fourth quarter of 2003. For 2004, South Texas production increased to an average of 142 MMcfe per day compared to 140 MMcfe per day 2003.

Average daily production rates for Arkoma and South Texas were negatively impacted during the quarter by our operational curtailment. As a result of rising rig rates and service costs during the fourth quarter of 2004, we reduced our onshore rig activity to keep capital spending within budgeted levels during the fourth quarter. In South Texas, we went

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from six rigs to four and in Arkoma we went from three rigs to one. In addition, we deferred the completion of seven wells in South Texas capable of producing an estimated 11 MMcfe per day, net, and five wells in Arkoma capable of producing an estimated 2 MMcfe per day, net. By the end of January 2005, we had resumed our six-rig program in South Texas and add a second rig in Arkoma. We expect to be able to add a third rig in Arkoma by the end of the first quarter 2005. As our South Texas properties begin to mature and production growth to minimize, our strategy will be to maintain production at existing levels while improving drilling and operating efficiencies.

In the Rockies, 2004 was an exploratory year and our activities were aimed at expanding our acreage position and proving up reserves in several exploration projects on our Uinta Basin acreage acquired in 2003. We drilled a total of 31 wells, 26 in the Uinta Basin, four in the DJ Basin and one in Montana. Of the total drilled, 28 wells or 90% were successful. By December 2004, six of our Uinta Basin wells were producing approximately 4 MMcfe per day, net to our interest. At December 31, 2004, production from the remaining 19 of our 25 successful Uinta Basin wells remained delayed, awaiting right-of-way approval for pipeline construction from the Bureau of Land Management (“BLM”). Subsequent to December 31, 2004, we received approval from the BLM for pipelines on 11 of the wells. We estimate initial production rates from these 11 wells, on a combined basis, to be approximately 8 MMcfe per day, net to our interests.

Offshore. We experienced record production growth as average daily rates increased 25% from 122 MMcfe per day during 2003 to an average of 153 MMcfe per day during 2004. We added approximately 41 MMcfe per day in newly developed production, of which an average of 22 MMcfe per day was attributable to development drilling at High Island A283 and East Cameron 56/57 and 148. During the year, we completed and brought on-line seven development wells at High Island A283, two at EC 56/57 and one at East Cameron 148. All of these fields were acquired in mid-October 2003, as part of our acquisition of Gulf of Mexico properties. Production from these properties accounted for approximately 71 MMcfe per day of our offshore production during 2004. Partially offsetting the production from our newly acquired properties were declines from existing and maturing fields totaling approximately 40 MMcfe per day, resulting in a net 31 MMcfe per day production increase year-over-year. Because the majority of our fields are located in the Western and Central Gulf of Mexico, Hurricane Ivan in September 2004, had minimal impact on our results for the year. We estimate that during the third quarter, approximately 210,000 or 2 MMcfe per day was deferred. All shut-in production was fully restored prior to the end of the third quarter of 2004.

During the fourth quarter of 2004, we experienced production declines at three key fields. In November 2004, the High Island 47 No. 1 well depleted. A third party operates this field and, our working interest is 33%. Prior to depletion, the well produced an average of 5 MMcfe per day to our interest, during 2004. In December 2004, our deep well at High Island 115, the No. 1, was shut-in due to a mechanical problem. A third party operates the well, and, we have a 50% working interest. During 2004, this well contributed an average of 9 MMcfe per day to our total daily production. We expect production to be restored during the third quarter of 2005. In late December 2004, our average daily production rate at High Island A283, dropped by an estimated 5 MMcfe/day from approximately 28 MMcfe/day as a result of the depletion on a pre-existing well and natural decline of newly developed wells.

Production Volume 2003 vs. 2002

The 5% increase in production for 2003 as compared to 2002, is primarily a result of newly developed production combined with additions from acquisitions made in 2003 and 2002.

Onshore. Daily production rates increased 12% from an average of 155 MMcfe/day during 2002 to 173 MMcfe/day during 2003. The increase in onshore production is primarily attributable to newly developed production in South Texas and Arkoma. In South Texas we drilled 56 successful wells and increased our average daily production rate to 140 MMcfe/day during 2003 from 123 MMcfe/day in 2002. In Arkoma, we more than doubled the number of wells drilled in 2002 by successfully drilling 46 wells during 2003. The impact of the newly developed production was seen in the fourth quarter of 2003 as our average daily rate in Arkoma increased to 25 MMcfe/day.

Offshore. Production decreased 3% from an average of 126 MMcfe/day during 2002 to an average of 122 MMcfe/day during 2003. For the first nine months of 2003, offshore production averaged 117 MMcfe/day as production declines due to maturing reservoirs from existing key fields, Mustang Island A-31/32, High Island 39, West Cameron 587 and South Marsh Island 253, were greater than new production added from wells and facilities brought on-line throughout 2003. Specifically, we had disappointing results at South Timbalier 314/317 that was brought on-line in early 2003. Contributing to the year-over-year production decline was the effect of shifting approximately $40 million of our 2002 offshore capital expenditure budget to our onshore region to fund the May 2002 acquisition of producing properties in South Texas from Burlington Resources. During the fourth quarter of 2003, offshore production increased by approximately 16% to an average rate of 136 MMcfe/day as we began to absorb the properties acquired from Transworld in mid-October and experienced production increases from newly developed fields, in particular, High Island 115 and High Island 47.

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Commodity Prices and Effects of Hedging 2004 vs. 2003

Our average unhedged or sales price for natural gas increased by 11% from $5.23 per Mcf during 2003 to $5.78 per Mcf during 2004. Included in natural gas revenues for 2004 is a loss of $70.1 million from natural gas hedging activities, which includes an unrealized loss of $1.9 million representing the ineffective portion of our derivative instruments that are not eligible for deferral under SFAS 133. The ineffectiveness was a result of changes during the period in the price differentials between the index price of the derivative contract, which uses a New York Mercantile Exchange (NYMEX) index, and the index price for the point of sale for the cash flow that is being hedged, the majority of which is the Houston Ship Channel index. As a result of the loss from hedging activities, we realized an average natural gas price during 2004 of $5.17 per Mcf that was 89% of or $0.61 lower than our average sales price. During 2003, we incurred a hedge loss from natural gas derivatives of $67.9 million, which is included in natural gas revenues and includes an unrealized loss of $1.9 million recognized for ineffectiveness, resulting in an average realized price of $4.55 per Mcf that was 87% of, or $0.68 per Mcf lower than our sales price.

Commodity Prices and Effects of Hedging 2003 vs. 2002

Our average wellhead price during 2003, before the effects of our hedging program, was $5.23 per Mcfe, up 66% over 2002. The increase in our natural gas and oil revenues was substantially offset by a $68.3 million loss from our hedging program, which lowered the price that we realized on our natural gas production by $0.68 Mcf during the period. The largest portion of this loss resulted from fixed price swaps for natural gas that we entered into during the fourth quarter of 2001 in connection with our acquisition of producing properties in South Texas. As a result of these swaps, we effectively fixed the price that we received on approximately 40 MMcf per day at $3.19, resulting in a loss of $32 million, or 47% of our total hedging loss for 2003.

For 2003, we realized an average natural gas price of $4.55 per Mcf, which was 87% of, or $0.68 per Mcf lower than our average unhedged natural gas price or wellhead price of $5.23 per Mcf for the period. Included in natural gas revenues is a loss of $67.9 million from natural gas hedging activities, which includes an unrealized loss of $1.9 million representing the ineffective portion of our derivative instruments that are not eligible for deferral under SFAS No. 133. For 2002, we realized an average gas price of $3.32 per Mcf, which was 105% of the average unhedged natural gas price of $3.16 per Mcf for the period. This resulted in natural gas revenues that were $16.4 million higher than the revenues we would have achieved if hedges had not been in place during the period. For 2002, our natural gas revenues included a realized gain of $16.4 million from hedging activities.

For 2003, we realized an average oil price of $28.15 per Bbl, which was 99% of or $0.31 per Bbl lower than the average unhedged price of $28.46 per Bbl for the period. As a result of oil hedging activities, oil revenues for 2003 were $0.4 million lower than the revenues we would have achieved if oil hedges had not been in place during the period. We had no oil hedges in place during 2002 and realized an average oil price of $23.99 per Bbl.

Operating Expenses

Total operating expenses in 2004 increased 30% over 2003 driven primarily by higher depreciation, depletion and non-recurring general and administrative expenses. On a unit production basis, operating expenses increased $0.37 per Mcfe produced, or 14%, over 2003. Depreciation, depletion and amortization accounted for $0.31 of the increase and the additional general and administrative expenses contributed $0.08 per Mcfe. Severance tax was $0.05 per Mcfe lower primarily as a result of exemptions in South Texas due to our “high-cost/tight-gas formation” designation.

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Lease Operating Expense. On an absolute dollar basis, lease operating expense increased by 19% during 2004. This increase relates primarily to our integration of offshore Gulf of Mexico properties that we acquired during the fourth quarter of 2003. These properties originally carried a relatively high operating cost and we are working to bring the cost structure of these properties more into line with our base offshore properties. Although lease operating expense was up in absolute terms in 2004, on a per unit of production basis taking into account our 15% increase in production, lease operating expense increased by only 2% or $0.01 in 2004. While we remain committed to minimizing our operating cost structure, in light of increasing service costs and our continued acquisition activities, we expect to experience upward pressure in our lease operating expense during 2005 and beyond.

During 2003, the increase in lease operating expenses as compared to 2002 is attributable to the continued expansion of our operations both onshore and offshore. Our overall operating expenses are increasing as we add new wells and production facilities and continue to maintain production from existing, maturing properties. Specific increases for 2003 were incurred for production enhancement and compression, insurance and contract services. In addition, we incurred $2.6 million in non-recurring expenses associated with workovers.

The acquisition of the Transworld properties in October 2003 caused our lease operating expense on a per unit basis to increase from an average of $0.42 per Mcfe for the first nine months of 2003 to $0.47 per Mcfe during the fourth quarter of 2003. The majority of the Transworld fields were originally developed by major oil and gas producers and due to their age and complexity, lease operating expenses for these properties are expected to be significantly higher than that of our existing offshore fields.

Severance Tax. Severance tax is a function of volume and revenues generated from onshore production. On an absolute dollar basis, severance tax decreased by 25% from 2003 to 2004. On an Mcfe basis, severance tax decreased by $0.05 or 33% for the twelve-month period. Despite higher wellhead prices during 2004, severance tax expense is lower primarily due to severance tax rebates received late in 2004 on our South Texas properties as a result of their “high-cost/tight-sand” designation.

For 2003, the increase in severance tax expense and severance tax per Mcfe is due to a 66% increase in average wellhead prices for natural gas during 2003 combined with a 12% increase in onshore production as compared to 2002.

Depreciation, Depletion and Amortization. The increase in our depreciation, depletion and amortization expense for 2004 was primarily a result of a higher depletion rate combined with a 15% increase in production for the year. Our depletion rate of $2.14 per Mcfe during 2004 was 17% higher than the $1.83 per Mcfe during 2003. Higher average finding costs per unit were the primary factor in the increase in our depletion rate. These higher finding costs are the result of the naturally declining productivity of our mature onshore drilling operations compounded by increasing service costs. Rising acquisition prices resulting from the continued strength of natural gas prices were also a factor. In addition, our estimated future development costs at December 31, 2004 increased 48% from estimates at December 31, 2003, primarily as a result of the future development costs relating to several offshore Gulf of Mexico properties acquired in October 2004. For 2004, producing property dispositions resulted in reserve reductions of 63.3 Bcfe. Finally, for 2004, we incurred downward revisions of 20 Bcfe, either due to proved undeveloped reserves that were depleted or otherwise not recoverable, or from production performance indicating less gas in place or smaller reservoir size than initially estimated.

During 2003, the increase in our DD&A expense was primarily a result of a higher depletion rate combined with a 5% increase in production volumes for 2003. Our depletion rate increased during 2003 as a result of downward reserve revisions related to reservoir performance of approximately 40 Bcfe; the addition of more costs to our depreciation base with fewer additions for reserves as our average finding and development cost increased during 2003; and a 52% increase in our estimated future development costs at year end, the majority of which was due to the proved undeveloped classification of 68% of the reserves acquired from Transworld.

Asset Retirement Accretion Expense. The increase in ARO accretion expense during 2004 as compared to 2003, is primarily a result of additions to our ARO liability since the end of the third quarter of 2003 as a result of producing property acquisitions, offset in part by the disposition of our South Louisiana properties in February 2004 and our Appalachian Basin properties in June 2004.

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General and Administrative Expenses, Net of Overhead Reimbursements and Capitalized General and Administrative Expenses