UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission file number: 000-22433

Brigham Exploration Company

Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
(Title of Class)

     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 twelve 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 x  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.

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2 of the Act). Yes o  No x

     As of June 30, 2003, the registrant had 20,562,410 shares of voting common outstanding. The aggregate market value of the registrants outstanding shares of voting common stock held by non-affiliates, based on the closing price of these shares on June 30, 2003 of $5.01 per share as reported on The Nasdaq Stock Market^SM, was $50.5 million. Shares held by each executive officer and director and by each person who owns 10% or more of the outstanding common stock are considered affiliates. The determination of affiliate status is not necessarily a conclusive determination for other purposes.

     As of March 26, 2004, the registrant had 39,562,696 shares of voting common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the definitive proxy statement for the Registrant’s 2004 Annual Meeting of Stockholders to be held on June 3, 2004, are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2003.

TABLE OF CONTENTS

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BRIGHAM EXPLORATION COMPANY

2003 ANNUAL REPORT ON FORM 10-K

PART I

ITEM 1. BUSINESS

Overview

We are an independent exploration, development and production company that utilizes 3-D seismic imaging and other advanced technologies to systematically explore for and develop domestic onshore oil and natural gas reserves. We focus our activities in provinces where we believe 3-D seismic technology can be used effectively to maximize our return on invested capital by reducing drilling risk and enhancing our ability to grow reserves and production volumes in a cost-effective manner. Our exploration and development activities are concentrated in three provinces: the onshore Texas Gulf Coast, the Anadarko Basin and West Texas.

Since our inception in 1990, we have evolved from a pioneering, 3-D seismic-driven exploration company to a balanced exploration and development company with technical and operational expertise and a strong production base. We benefit from our focus in five proven and complementary onshore trends contained within our three core provinces, which provides us with diversification in our drilling investments. We believe that our five focus trends provide us with a broad range of risk profiles and reserve potentials for both natural gas and oil prospects and associated geographical and operational diversification. As a result, we are not dependent on our continued drilling success in a single core trend. Instead, in any given year our overall results may be positively impacted by the results in one or several of our focus trends. We believe that this diversification and our knowledge base in these trends, as demonstrated by our track record, are significant distinguishing factors for us.

We have generated a multi-year inventory of exploration prospects, which, due to our field discoveries, are complemented by a multi-year inventory of development locations. Since our inception through December 31, 2003, we have drilled 592 wells, consisting of 453 exploratory and 139 development wells with an aggregate completion rate of 69% and an average all-sources finding cost of $1.41 per Mcfe. In 2003 we spent $46.8 million in net capital expenditures on oil and gas activities and achieved an all-sources finding cost of $1.97 per Mcfe. Additionally, we completed 33 out of 37 wells drilled in 2003 replacing 223% of our 2003 production. To further capitalize on our multi-year inventory of exploration and development prospects, we currently plan to significantly increase our oil and gas capital expenditures in 2004 to approximately $78.9 million, representing a 69% increase over 2003 oil and gas capital expenditures.

We have accumulated 3-D seismic data covering approximately 9,948 square miles (6.4 million acres) in over 28 geologic trends in seven provinces and seven states. We focus our 3-D seismic acquisition efforts in and around existing producing fields where we can benefit from the imaging of producing analog wells. These 3-D defined analogs, combined with our experience in drilling 592 wells in our 3-D project areas, provide us with a knowledge base to evaluate other potential geologic trends, 3-D seismic projects within these trends and prospective 3-D delineated drilling locations.

Combining our geologic and geophysical expertise with a sophisticated land effort, we manage the majority of our projects from conception through 3-D acquisition, processing and interpretation and leasing. In addition, we manage the negotiation and drafting of most of our geophysical exploration agreements, resulting in reduced contract risk and more consistent deal terms. Because we generate most of our projects, we can often control the size of the working interest that we retain as well as the selection of the operator and the non-operating participants. Consistent with our business strategy, we have increased the working interest we retain in certain of our 2004 projects, based upon our improved capital availability. For example, approximately 37% of our budgeted 2004 drilling expenditures are allocated to the Vicksburg trend, where we expect to retain an average working interest of 61% (relative to our historical average working interest of 40% through 2003). Further, approximately 25% of our budgeted 2004 drilling expenditures are allocated to the Frio trend, where we expect to retain an average working interest of 55% (relative to our historical average working interest of 47% through 2003).

Business Strategy

Our business strategy is to create stockholder value by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we believe our operations will likely result in a high return on our invested capital. Key elements of our business strategy include:

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Focus on Core Provinces and Trends. We have accumulated and continue to add to a multi-year inventory of 3-D seismic and geologic data and have developed a strong technical knowledge base in the following geologic trends within our core provinces: the Vicksburg and Frio trends in the onshore Texas Gulf Coast, the Springer and Hunton trends in the Anadarko Basin and the Horseshoe Atoll trend of West Texas.

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Further, we believe our focus on these five proven onshore trends within our three core provinces provides us with important drilling investment diversification. Since 1999, our drilling success in these trends has resulted in six significant field discoveries and a multi-year inventory of development drilling locations. We plan to focus a majority of our near term capital expenditures in these trends, where we believe our accumulated data and knowledge base provide a substantial competitive advantage.

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Internally Generate Inventory of High Quality Exploratory Prospects. We utilize 3-D seismic and other advanced technologies, including computer-aided exploration, to generate and maintain a large multi-year inventory of high quality exploratory prospects. Our highly skilled staff of twelve geophysicists and geologists generates substantially all of our prospects. We do not rely on third party generated opportunities, which usually involve the payment of consideration over and above the costs incurred to generate and drill the prospect. We believe that our six field discoveries and our history of achieving low all-sources finding costs over the last three, five and seven years, averaging $1.50, $1.25 and $1.42 per Mcfe, respectively, reflect the quality and depth of our 3-D delineated prospect inventory as well our ability to continue to generate such opportunities.

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Capitalize on Exploration Successes Through Development of Field Discoveries. From 1990 to 1999, we grew our reserves and production volumes primarily through successful 3-D delineated exploration drilling. Due to our exploratory drilling success and the resulting growth in our inventory of development drilling locations, approximately 60% of our drilling capital expenditures in 2001, 2002 and 2003 were developmental. We believe our ability to balance our higher risk exploratory drilling with lower risk development drilling has reduced our risk profile. For 2004, we intend to allocate approximately 64% of our total drilling expenditures for development drilling. See “Item 2. Properties” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—2004 Outlook” for additional discussion about capital expenditures for 2004.

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Accelerate Drilling of Our Prospect Inventory. To capitalize on our multi-year inventory of exploration and development locations, our goal is to substantially increase our drilling activity in 2004. In 2004 we have budgeted $61.4 million in drilling capital expenditures, representing a 75% increase over amounts spent in 2003. See “Item 2. Properties” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—2004 Outlook” for additional discussion about capital expenditures for 2004.

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Enhance Returns Through Operational Control. We seek to maintain operational control of our exploration and drilling activities. As an operator, we retain more control over the timing and selection of drilling prospects, which enhances our ability to optimize our finding and development costs and to maximize our return on invested capital. Since we generate substantially all of our projects, we generally have the ability to retain operational control over all phases of our exploration and development activities. As of December 31, 2003, we operated approximately 62% of the pre-tax PV-10% value of our proved developed reserves. Further, in 2003 we operated 46% of the wells we drilled, representing 70% of our drilling capital expenditures, and we expect to operate the majority of the wells planned for 2004.

Exploration and Development Staff

Our experienced exploration staff includes six geophysicists, six geologists, two computer applications specialists and two geophysical/geological/engineering technicians. Our geologists and geophysicists have different but complementary backgrounds, and their diversity of experience in varied geological and geophysical settings, combined with various technical specializations (from hardware and systems to software and seismic data processing), provides us with valuable technical intellectual resources. Our geophysicists and geologists have an average of more than 20 years of experience per person. We assembled our team according to the expertise that these individuals have within producing basins where we focus our exploration and development activities. By integrating both geologic and geophysical expertise within our project teams, we believe we possess a competitive advantage in our exploration approach.

Our land department staff includes four landmen with an average of more than 21 years of experience primarily within our core provinces and three lease and division order analysts. Our land department contributed to pioneering many of the innovations that have facilitated exploration using large 3-D seismic projects.

Oil and Natural Gas Market and Major Customers

Our natural gas produced in the onshore Texas Gulf Coast is sold to various purchasers including intrastate pipeline purchasers, operators of processing plants, and marketing companies under both monthly spot market contracts and multi-year arrangements. The vast majority of our natural gas sales are based on related natural gas index pricing, and in some cases our gas is processed at a plant and we receive a percentage of the value of natural gas liquids recovered.

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Our markets for natural gas produced in the Anadarko Basin are operators of processing plants and marketing companies. We sell gas under both monthly spot market contracts and multi-year contracts, which are normally based on related natural gas index pricing. Some of our gas is processed and we receive a percentage of the value of natural gas liquids recovered.

Most of our natural gas in West Texas is sold to purchasers who process our natural gas under multi-year contracts and pay us a percentage of the value they receive from the resale of the natural gas liquids and the remaining residue gas.

We sell our crude oil and condensate at the lease to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive an applicable posted price plus a market-based bonus.

Since most of our oil and natural gas production is sold under price sensitive or spot market contracts, the revenues generated by our operations are highly dependent upon the prices of and demand for oil and natural gas. The price we receive for our oil and natural gas production depends upon numerous factors beyond our control, including seasonality, weather, competition, the condition of the United States economy, foreign imports, political conditions in other oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries, and domestic government regulation, legislation and policies. Decreases in the prices of oil and natural gas could have an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Although we are not currently experiencing any significant involuntary curtailment of our oil or natural gas production, market, economic and regulatory factors may in the future materially affect our ability to sell our oil or natural gas production. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors—Oil And Natural Gas Prices Fluctuate Widely And Low Prices Could Have A Material Adverse Impact On Our Business And Financial Results By Limiting Our Liquidity And Flexibility To Accelerate Our Drilling Program” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors—The Marketability Of Our Natural Gas Production Depends On Facilities That We Typically Do Not Own Or Control Which Could Result In A Curtailment Of Production And Revenues.” For the year ended December 31, 2001, sales to Lantern Petroleum Corporation and Highland Energy Company represented approximately 60% of our oil revenue and 58% of our natural gas revenue. In 2002, in an effort to achieve better price realizations from the sale of our oil and natural gas, we decided to bring our commodities marketing activities in-house so that we could market and sell our oil and natural gas to a broader universe of potential purchasers. As a consequence, on March 1, 2002, we ended our oil purchase agreement with Lantern Petroleum and on July 1, 2002, we ended a similar gas sales and purchase arrangement with Highland Energy Company. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Competition

The oil and gas industry is highly competitive in all of its phases. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of seismic and leasing options and oil and natural gas leases on properties to exploration and development of those properties. Our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies with substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for seismic and lease options on oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors—We Face Significant Competition And Many Of Our Competitors Have Resources In Excess Of Our Available Resources” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors—We Have Substantial Capital Requirements For Which We May Not Be Able To Obtain Adequate Financing.”

Operating Hazards and Uninsured Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, delays by project participants, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our business, financial condition or results of operations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors— Exploratory Drilling Is A Speculative Activity That May Not Result In Commercially Productive Reserves And May Require Expenditures In Excess Of Budgeted Amounts.”

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In addition, use of 3-D seismic technology requires greater pre-drilling expenditures than traditional drilling strategies. Although we believe that our use of 3-D seismic technology will increase the probability of drilling success, some unsuccessful wells are likely, and there can be no assurance that unsuccessful drilling efforts will not have a material adverse effect on our business, financial condition or results of operations.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and those of others. We maintain insurance against some but not all of the risks described above. In particular, the insurance we maintain does not cover claims relating to failure of title to oil and natural gas leases, trespass during 3-D survey acquisition or surface damage attributable to seismic operations, business interruption or loss of revenues due to well failure. Furthermore, in certain circumstances in which insurance is available, we may not purchase it. The occurrence of an event that is not covered, or not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors—We Are Subject To Various Operating And Other Casualty Risks That Could Result In Liability Exposure Or The Loss Of Production And Revenues” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors—We May Not Have Enough Insurance To Cover All Of The Risks We Face, Which Could Result In Significant Financial Exposure.”

Employees

On March 26, 2004, we had 55 full-time employees and two part-time employees. None of these employees are represented by any labor union and we believe relations with them are good.

Facilities

Our principal executive offices are located in Austin, Texas, where we lease approximately 34,330 square feet of office space at 6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730.

Governmental Regulation

Our oil and natural gas exploration, production, transportation and marketing activities are subject to extensive laws, rules and regulations promulgated by federal and state legislatures and agencies, including the Federal Energy Regulatory Commission (FERC), the Environmental Protection Agency, the Texas Commission on Environmental Quality (TCEQ), the Texas Railroad Commission and the Oklahoma Corporation Commission. Failure to comply with such laws, rules and regulations can result in substantial penalties. The legislative and regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability.

Although we do not own or operate any pipelines or facilities that are directly regulated by FERC, its regulation of third party pipelines and facilities could indirectly affect our ability to transport or market our production. Moreover, FERC has in the past, and could in the future impose price controls on the sale of natural gas. In addition, we believe we are in substantial compliance with all applicable laws and regulations, however, we are unable to predict the future cost or impact of complying with such laws and regulations because they are frequently amended, interpreted and reinterpreted.

The states of Texas and Oklahoma, and many other states, require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. These states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells.

Environmental Matters

Our operations and properties are, like the oil and gas industry in general, subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from our operations.

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The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines or injunction, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state statutes impose strict and arguably joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act (RCRA) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations. We are required to maintain such permits or meet general permit requirements. The Environmental Protection Agency (EPA) and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and gas exploration and production operations. Both the EPA and TCEQ have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit air pollutants. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.

Operations and Operations Staff

In an effort to retain better control of our project timing, drilling and operational costs and production volumes, we have significantly increased the percentage of the wells that we operate in the past several years. We operated 46% of the gross wells and 69% of the net wells that we drilled during 2003, as compared with 10% of the gross wells and 17% of the net wells we drilled during 1996. As a result of our increased operational control in recent years, wells operated by us constituted 62% of the pre-tax PV-10% value of our proved developed reserves at year-end 2003, as compared to only 5% at year-end 1996.

Our operations staff includes five engineers who have drilling, reservoir, environmental and operations engineering experience primarily within our three core provinces. These engineers work closely with our geologist and geophysicist and are integrally involved in all phases of the exploration and development process, including preparation of pre- and post-drill reserve estimates, well design, production management and analysis of full cycle risked drilling economics. We conduct field operations for our operated oil and natural gas properties through our field production superintendent and third party contract personnel.

Website Access to Company Reports

We make available free of charge through our website, www.bexp3d.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission. Information on our website is not a part of this report.

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ITEM 2. PROPERTIES

Our exploration and development activities are focused primarily in the onshore Texas Gulf Coast, the Anadarko Basin of northwest Oklahoma and the Texas Panhandle, and West Texas. We focus our activity in provinces where we believe 3-D seismic technology can be effectively used to maximize our return on capital invested by reducing drilling risk and enhancing our ability to cost-effectively grow reserves and production volumes.

For the three-year period ended December 31, 2003, we completed 81 gross wells (30.4 net) in 93 attempts for a completion rate of 87% at an average all-sources finding cost of $1.50 per Mcfe. We have budgeted approximately $61.4 million to drill approximately 36 development wells and 23 exploratory wells during 2004. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— 2004 Outlook.” The following is a summary of our properties by major province as of December 31, 2003, unless otherwise noted:

		Year Ended
		December 31, 2003								At December 31, 2003
		Drilling				Average
		Capital				Daily				Proved				Pre-tax				%				Productive								3-D Seismic
		Expenditures				Production				Reserves				PV-10% (a)				Natural				Wells								Data
Province		(Millions)				(MMcfe/d)				(Bcfe)				(Millions)				Gas				Gross				Net				(Sq. Miles)
Texas Gulf Coast		$	24.6				18.3				72.3			$	196.8				82	%			62				19.2				3,456
Anadarko Basin			9.0				6.7				51.7				122.3				93	%			122				28.5				2,204
West Texas/Other			1.5				4.7				10.2				24.7				20	%			98				26.9				4,288
Total		$	35.1				29.7				134.2			$	343.8				82	%			282				74.6				9,948

Texas Gulf Coast

The onshore Texas Gulf Coast region is a high potential, multi-pay province that lends itself to 3-D seismic exploration due to its substantial structural and stratigraphic complexity. In addition, certain sand reservoirs display seismic “bright spots,” which can be direct hydrocarbon indicators and can result in greatly reduced drilling risk. However, “bright spots” are not always reliable as direct hydrocarbon indicators and do not generally assess reservoir productivity. We believe our established 3-D seismic exploration approach, combined with our exploration staff’s extensive experience in the Texas Gulf Coast and accumulated knowledge base in this province, particularly given our recent drilling successes, provides us with significant competitive advantages. The majority of our Texas Gulf Coast activity is currently concentrated in the Vicksburg and Frio trends.

Over the past three years we have spent approximately 68% of our total capital expenditures for drilling, land and geological and geophysical in the onshore Texas Gulf Coast region and have completed 37 gross wells (15.6 net) in 41 attempts for a completion rate of 90%. Production from the onshore Texas Gulf Coast region represented 61% of our average daily production in 2003, up from 41% in 2001.

During 2003, we completed 15 gross wells (8.2 net) in 17 attempts for a completion rate of 88% in the onshore Texas Gulf Coast. We operated 12 of the 17 wells that we drilled. Eleven of the wells we drilled were exploratory and six were developmental. Our development drilling was focused in the Providence, Home Run and Floyd Fault Block Fields. In addition, we made a new Vicksburg field discovery with the successful completion of our Floyd South Fault Block Field discovery well.

For 2004, we intend to focus our drilling activity in this province on the development of our Home Run, Triple Crown, Floyd Fault Block and Floyd South Field discoveries in the Vicksburg, the further development of our Providence Field in the Frio and the continued drilling of our 3-D delineated exploration inventory in the Vicksburg and Frio trends. We expect to spend approximately $38.9 million to drill 25 wells in the onshore Texas Gulf Coast. Approximately 52% percent of these drilling capital expenditures are budgeted for development drilling activities, with the remainder allocated towards exploration drilling.

Vicksburg Trend

Since 1999, our exploration efforts in the Vicksburg trend have been focused in the general area of our Diablo Project located in the Brooks County area of South Texas. At inception we owned a 34% working interest in the Diablo Project, with another industry participant owning the remaining 66%. Prior to November 2003, we had approximately 8,000 acres of leasehold and 218 square miles of 3-D seismic data in the area.

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In November 2003, we significantly expanded our ownership in this area when we signed two new joint ventures with our same industry participant covering an additional 5,150 acres, increasing our total acreage under control in the area to approximately 13,150 acres. In the new joint ventures we have the opportunity to retain larger working interests, ranging from 50% to 100%, while also retaining all the associated drilling and completion operations.

As of December 31, 2003, we had completed 18 wells in 18 attempts in the Vicksburg trend and generated four significant discoveries at the Home Run Field, the Triple Crown Field, the Floyd Fault Block Field and the Floyd South Fault Block Field. The primary objectives within this area are large structural features at depths ranging from 9,000 to 14,000 feet.

We believe that we have a substantial multi-year inventory of proved undeveloped and non-proved Vicksburg drilling locations in our Home Run, Triple Crown, Floyd Fault Block and Floyd South Fault Block Fields, and other adjacent fault blocks.

In 2003 we invested approximately $10.9 million to drill and complete five wells in the Vicksburg with an average working interest of 50%. For 2004 we plan to devote approximately $22.8 million in drilling capital expenditures to drill six development wells and two exploratory wells in the Vicksburg. We expect to direct a significant portion of our future capital expenditures towards both proved and non-proved drilling opportunities in this area.

Floyd Fault Block. We drilled our Floyd Fault Block discovery well, the Sullivan #8, in December 2002. We retained a 34% working and 25% revenue interest in the Sullivan #8, which proved up reserves in one of several fault blocks adjacent to our Home Run and Triple Crown Fields. The Sullivan #8 encountered approximately 172 feet of apparent net pay in several lower Vicksburg pay intervals at depths between 12,900 and 13,650 feet. The quantity of pay encountered is approximately three times that encountered in our typical Home Run Field well.

The Sullivan #8 began producing in March 2003 at a rate of approximately 9.2 MMcf of natural gas and 580 barrels of condensate per day (12.7 MMcfe/d) or approximately 3.2 MMcfe/d net to our 25% revenue interest. After producing approximately 2.9 Bcfe, in October 2003 the well stopped producing due to an apparent blockage above the producing formation. Prior to the blockage, the Sullivan #8 was producing 7.7 MMcf of natural gas and 400 barrels of condensate per day (10.1 MMcfe/d). In February 2004, the operator of the well reestablished production at approximately 2.5 MMcf of natural gas and 100 barrels of condensate per day (3.1 MMcfe/d). It is uncertain how long the Sullivan #8 will continue to produce in its current state. If the well stops producing in the future, it is highly likely that the well will be sidetracked or redrilled.

We retained a 34% working interest and 25% net revenue interest in the Sullivan #9 and the Sullivan #10, the first two development wells in our Floyd Fault Block Field. The most recent well, the Sullivan #10, encountered approximately 187 feet of apparent net pay, and was completed and fracture stimulated. The Sullivan #10 commenced production at an initial rate of approximately 11.9 MMcf of natural gas and 689 barrels of condensate per day (16.0 MMcfe/d) or approximately 3.9 MMcfe/d net to our revenue interest, with a flowing tubing pressure of approximately 8250 psi. We estimate that up to seven additional wells will be required for full development of the Floyd Fault Block Field, four of which were classified as proved undeveloped locations at December 31, 2003. We expect to drill two additional wells within the Floyd Fault Block Field in 2004.

Home Run Field & Triple Crown Field. We discovered the Home Run Field in late 1999 and the Triple Crown Field in 2001. As of December 31, 2003, we had drilled and completed 14 consecutive wells in these fields with an average working interest of 42%. During 2003, we drilled and completed two wells in the Home Run Field and expect to drill up to three wells within the Home Run Field and one well within the Triple Crown Field in 2004. We believe that the Home Run and Triple Crown Fields could require up to 45 additional wells for full development, eleven of which were classified as proved undeveloped at December 31, 2003.

Floyd South Fault Block Field. We drilled our Floyd South Fault Block Field discovery well, the D.J. Sullivan F#1, in December 2003. The Sullivan F #1, which was drilled to a total depth of 14,177 feet, was the first well to test the Floyd South fault block as part of the new Vicksburg joint venture entered into in 2003 with our industry participant. The Sullivan F#1 encountered approximately 55 feet of apparent net pay in the Lower Vicksburg and commenced production to sales in January 2003 at a rate of approximately 6.7 MMcf of natural gas and 293 barrels of condensate per day (8.5 MMcfe/d) with a flowing tubing pressure of 8100 psi, or approximately 3.3 MMcfe/d net to our 39% revenue interest. We operated the drilling of the Sullivan F #1, retaining a working interest of 100% before and 50% after casing point. We currently plan to commence drilling the first development well in the Floyd South Fault Block Field during the second quarter of 2004. We will retain a 50% working interest before and after casing point in the first development well and any other wells subsequently drilled in the Floyd South Fault Block Field. We believe that the Floyd South Fault Block Field could require three to six wells for full development, three of which were classified as proved undeveloped at December 31, 2003.

Adjacent Fault Blocks to Prior Field Discoveries. In early 2004, the Sullivan E #1 was drilled to a total depth of 14,650 feet to test the Diablo East fault block as part of our new Vicksburg joint ventures. Despite encountering over 400 gross feet of what was apparently gas bearing sands, it was determined that the prospective zones were tight and the well was plugged and abandoned. We are evaluating the results of this well to determine if another test of the Diablo East fault block is merited. Prior to drilling the Sullivan E #1, we had completed eighteen consecutive Vicksburg wells in four different fault blocks.

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We have additional unproven fault blocks to test, most of which are adjacent to our prior discoveries.

Additional Vicksburg Potential. We continue to generate prospects in the Vicksburg trend, and seek to continue to expand our operations in this core trend, which is currently the single most important of the five focus trends.

Frio Trend

In the Frio trend of the Upper Texas Gulf Coast, we have accumulated an inventory of over 1,880 square miles (1.2 million acres) of predominantly non-proprietary 3-D seismic data located primarily in Brazoria, Calhoun, Matagorda, and Jackson Counties in the Upper Texas Gulf Coast. Within this trend we are targeting both the shallow non-pressured and the deeper pressured Frio sands. Reservoirs in this trend can display seismic “bright spots,” which can be direct hydrocarbon indicators and can result in greatly reduced drilling risk. However, “bright spots” are not always reliable as direct hydrocarbon indicators and do not generally assess reservoir productivity.

Since late 2000, we have completed 19 wells in 21 attempts in the Frio trend and discovered our prolific Providence Field. In 2003 we invested approximately $13 million in the Frio trend to drill 11 wells, 10 of which were completed. Our average working interest in these wells was 61%. For 2004 we estimate that our drilling expenditures will be approximately $15.6 million to drill five development wells with an average working interest of 52% and eleven exploratory wells with an average working interest of 57%.

Providence Frio Field. We discovered the Providence Field during the fourth quarter of 2001, when we drilled and completed the Staubach #1. Including the Staubach #1 discovery well in 2001, we have now completed five wells in five attempts in the Providence Field with an average working interest of 40%. During 2002 and 2003 we invested approximately $7.5 million in the drilling of our Providence Field, which generated approximately $24 million in net revenue during this time period. During 2004 we expect to drill one to two additional wells in the Providence Field.

General Patton Project. In early 2003, we acquired 84 square miles of new proprietary seismic data along the same trend that has provided most of our recent Frio discoveries, including the Providence Field. We sold a 50% working interest in the project to participants on a promoted basis. As a result, we paid 33.3% of the seismic and pre-seismic land costs for our 50% working interest in the project, while also retaining operational control. We began interpreting the data in May 2003 and commenced our drilling program in this project in August 2003 with the drilling of the Harriman #1 discovery. We operated and retained a 50% working and 39% revenue interest in the Harriman #1, which commenced production in early October 2003 at an initial rate of approximately 4.9 MMcf of natural gas and 50 barrels of oil per day (5.2 MMcfe/d).

In October 2003, we commenced drilling our second General Patton Project well, the Harrison #1, to test our Corner Pocket Prospect. In February 2004, the Harrison #1 commenced production at an initial rate of approximately 2.2 MMcf of natural gas and 113 barrels of oil per day (2.9 MMcfe/d). We retained a 50% working interest in the Harrison #1, which may set up one to two offsets that will be drilled during 2004. To date, we have completed two wells in two attempts in our General Patton Project, and currently expect to drill approximately eight General Patton Frio wells during 2004.

Bayou Bengal Project. In late 2003 and early 2004 we acquired approximately 77 square miles of existing non-proprietary and 54 square miles of new proprietary 3-D seismic data in our Bayou Bengal Project. This project is located along the same trend that has provided most of our recent Frio discoveries. We sold a 25% working interest in the project to a participant on a promoted basis. As a result, we paid 60% of the seismic and pre-seismic land costs for our 75% interest in the project, while also retaining operational control. We commenced drilling our first well in this project, the Trull B #2, during October 2003. The Trull B #2, which targeted a total depth of 9,500 feet, was completed to sales in January 2004 at an initial rate of approximately 2.3 MMcf of natural gas and 34 barrels of oil per day (2.5 MMcfe/d). This production rate was constrained due to limited pipeline capacity. We retained a 75% working and 56% revenue interest in this shallow Frio discovery.

In December 2003, we drilled the Sartwelle #1, our second discovery in our Bayou Bengal Project. The Sartwelle #1 commenced production to sales in February 2004 at an initial rate of approximately 4.0 MMcf of natural gas and 42 barrels of oil per day (4.2 MMcfe/d) with a flowing tubing pressure of 4750 psi. We retained a 63% working and 47% revenue interest in the Sartwelle #1, which was drilled to a total depth of approximately 10,450 feet. To date, we have completed two wells in two attempts in our Bayou Bengal Project, and currently expect to drill two additional wells during 2004.

Other Frio. In February 2004 we completed the Randall #1 in the Lower Frio at an initial rate of approximately 2.0 MMcf of natural gas and 12 barrels of oil per day (2.1 MMcfe/d) with a flowing tubing pressure of 6700 psi. We operated the Randall #1 with a 94% working and 70% revenue interest, which was drilled to a total depth of approximately 14,200 feet. We believe that the Randall #1 could set up one additional offset, which we expect to commence later in 2004.

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In addition to our ongoing drilling program in the Frio trend, we continue to generate additional drilling inventory from our 3-D seismic database of more than 1,880 square miles in this trend. Historically, approximately 20% of our exploration wells targeted higher risk, higher reserve potential objectives. The Staubach #1 discovery well for our Providence Field is an example of a successful higher potential Frio test. However, as in recent years, the vast majority of our Frio exploration wells are expected to test relatively lower risk, primarily amplitude defined prospects. In recent years these prospects have provided us with a high success rate and a high rate of return on our drilling capital investments.

We also continue to add to our drilling inventory in the Frio by assembling several new proprietary 3-D seismic projects in the same trend where we have experienced significant drilling success in recent years. We expect to commence acquisition of at least one additional proprietary 3-D project in the third quarter of 2004.

Other Texas Gulf Coast

The Dinn Ranch Field. The Dinn Ranch Field is a Wilcox discovery located in Duval County, Texas. We own interests in two wells within the field. The first well, the Lopez #1, experienced operational difficulties, but was eventually completed as a marginal producer. The second well, the Lopez #3, was producing in February 2003 at a rate of approximately 16.5 MMcf of natural gas per day. The Lopez #3 had produced approximately 2.9 Bcfe through December 31, 2003, and was producing approximately 6.3 MMcf of natural gas per day at year-end. We retain 2% overriding royalty interests in these two wells that convert to working interests at different payouts. In each of these two wells, we will own a 12.5% working interest at 100% payout, which will increase to a 25% working interest at 200% payout. Payout occurs at the point in time when the net proceeds from the sale of production from the well equals all of the costs and expenses associated with the drilling and operation of the well. We expect a third well to spud late in 2004, in which we plan to retain a 25% ground floor working interest.

Anadarko Basin

The Anadarko Basin is located in northwest Oklahoma and the Texas Panhandle. We believe this prolific natural gas producing province offers a combination of lower risk exploration and development opportunities in shallower horizons, as well as higher reserve potential in the deeper sections that have been relatively under explored.

We believe our drilling programs in the Anadarko Basin and West Texas generally provide us with longer life reserves and help to balance our drilling program in the prolific, but generally shorter reserve life, onshore Texas Gulf Coast province.

The stratigraphic and structural objectives in the Anadarko Basin can provide excellent targets for 3-D seismic imaging. In addition, drilling economics in the Anadarko Basin are enhanced by the multi-pay nature of many of these prospects; with secondary or tertiary targets serving as either incremental value or as alternatives in the event the primary target zone is not productive. Our recent activity has been focused primarily in the Springer Channel and Hunton trends. However, given the recent success of development wells in a Springer Bar Field, discovered by us in late 2000, developmental activity in this field accelerated during 2003.

Over the past three years we have spent approximately 25% of our total capital expenditures for drilling, land and geological and geophysical in the Anadarko Basin and have completed 30 gross wells (9.6 net) in 35 attempts for a completion rate of 86%. Production from the Anadarko Basin represented 23% of our average daily production in 2003, down from 38% in 2001.

During 2003, we completed 14 gross wells (4.8 net) in 15 attempts for a completion rate of 93%. We operated four of the wells that we drilled in the Anadarko Basin in 2003. Seven of the wells we drilled were exploratory and eight were developmental.

For 2004, we intend to continue to focus our drilling activity in this province on our 3-D delineated exploration and development inventory in the Springer and Hunton trends. We expect to spend approximately $20.8 million to drill 29 wells. Approximately 90% of these drilling capital expenditures are budgeted for development drilling activities, with the remainder allocated towards exploration drilling.

Grady County Springer Bar Field

In Grady County, Oklahoma we have approximately 105 square miles (67,200 acres) of 3-D seismic data and together with our participants control over 10,000 leasehold acres in one of the most prolific producing areas of the Anadarko Basin. In 2000, based on our seismic interpretation of this data, we discovered a large, stratigraphically defined Springer Bar field with the successful completion of the Nix #1 in the Britt interval of the Springer formation. In late 2000, we confirmed the field with the Pitchford #1 well, which produced from the same Britt interval at a depth of approximately 14,550 feet. We own a 17.35% working interest in the Nix #1 and a 32.27% working interest in the Pitchford #1.

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During 2003, we invested approximately $2.6 million in this area and completed 6 gross wells (1.1 net) in 7 attempts. Successful wells drilled in the field have produced at initial rates generally ranging from 2 to 8 MMcfe per day, with low production decline rates relative to our onshore Texas Gulf Coast wells. Given our drilling success to date in the field, we are currently budgeting to spend $4.3 million to drill twelve development wells with an average working interest of 10% in this area in 2004.

In early 2003 we participated in the successful drilling of the McCasland Farms #2, which commenced production in May at an initial rate of approximately 4.5 MMcf of natural gas and 50 barrels of oil per day (4.8 MMcfe/d), or approximately 0.9 MMcfe/d net to our 18.6% revenue interest. We also participated with a 15% working interest in the Stonehocker #1, which began producing to sales in July 2003 at a rate of approximately 7.0 MMcf of natural gas per day, or approximately 0.8 MMcfe/d net to our 12% revenue interest.

The Jones #2 commenced drilling in June 2003, and was subsequently completed to sales in October 2003 at a rate of approximately 7.0 MMcf of natural gas and 100 barrels of oil per day (7.6 MMcfe/d), or 1.2 MMcfe/d net to our 15.9% revenue interest. During September 2003, we participated in the Teel #1 with a 16% working interest, which commenced producing to sales in December 2003 at a rate of approximately 6.9 MMcf of natural gas and 30 barrels of oil per day (7.1 MMcfe/d), or 0.9 MMcfe/d net to our 13% revenue interest. In November 2003, we participated in the drilling of the Mack Farms #1 with a 14.6% working interest. In February 2004, the Mack Farms #1 was being completed to sales after encountering approximately 55 feet of apparent net pay in various Springer intervals.

Other Grady County Activity

In April 2003, we participated in the Palmer #1 with a 29% working interest. The Palmer #1 was completed and fracture stimulated in the Bromide formation and initially produced at a rate of approximately 130 barrels of oil and 350 Mcf of natural gas per day (1.1 MMcfe/d) or 0.2 MMcfe/d net to our 22% revenue interest. In November 2003, we participated with a 33% working interest in the Cooper #1, which was drilled to a depth of approximately 16,374 feet and encountered approximately 65 feet of apparent net pay in the Bromide formation. The Cooper #1 was being completed in February 2004, with production to sales expected in March 2004. We are also participating with a 29% working interest in the Burton #1, another Bromide test that commenced drilling in March 2004. Results for the Burton #1 are expected in late May 2004.

Springer Channel Trend

Our 3-D seismic inventory in the Springer Channel trend consists of over 629 square miles (402,560 acres) of 3-D seismic data covering portions of Dewey, Blaine, Canadian, Grady and Caddo Counties, Oklahoma. Our activities in this area target buried fluvial sand channels at depths of 9,000 to 12,000 feet, as well as other secondary objectives. Since 2000, we have completed 11 wells in 15 attempts in the Springer Channel trend. In 2003 we invested approximately $1.1 million in this trend to drill and complete five wells in 2003 with an average working interest of 47%.

During 2003 we participated in an 8,800 feet Springer test, the Bryson #1, with a 36% working interest. The Bryson #1 was completed in the Springer interval in July 2003 at a rate of approximately 2.5 MMcf of natural gas and 110 barrels of oil per day (3.1 MMcfe/d), or approximately 0.9 MMcfe/d net to our 29% revenue interest. We have budgeted approximately $4.2 million to drill four development wells with an average working interest of 53% and six exploratory wells with an average working interest of 21% in this trend in 2004.

Hunton Trend

Our 3-D seismic inventory in the Hunton trend consists of approximately 762 square miles (487,680 acres) of 3-D seismic data covering portions of Wheeler, Hemphill and Roberts Counties, Texas and Beckham County, Oklahoma. The primary exploration targets within this area are high potential, multi-well structural features at depths ranging from 7,500 to 25,000 feet. The trend has historically provided longer life reserves relative to our typical onshore Texas Gulf Coast wells. For 2004, we have budgeted approximately $9.2 million to drill three development wells in the Hunton trend with an average working interest of 64%.

Mills Ranch Field. In July 2000, we spud the Mills Ranch #1, which was drilled directionally to a total depth of over 25,000 feet. We operated this well with a 64% working interest. The Mills Ranch #1 paid out its drilling and completion costs during its first year of production, and at year-end 2003 had produced 4.1 Bcfe and was producing approximately 1.3 MMcfe/d. In the third quarter 2002, we began drilling the first offset to this discovery, the Mills Ranch #2. We retained a 64% working interest in the Mills Ranch #2 well, which encountered the basal Hunton porosity zone approximately 400 feet high to the comparable zone in the discovery well. After running production casing to a depth of approximately 23,900 feet and perforating and stimulating the lower Hunton intervals, the well began producing at an initial rate of approximately 6.7 MMcf of natural gas per day with associated condensate. The upper intervals were then stimulated and commingled into the producing stream, and the well was put on production at an initial rate of approximately 2.0 MMcfe/d.

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We believe that the Mills Ranch Field could require up to seven additional wells for full development, three of which were classified as proved undeveloped at December 31, 2003. Drilling operations commenced in February 2004 on one of the proved undeveloped locations, the Mills Ranch #1-99S. The Mills Ranch #1-99S is a reentry and sidetrack of a well previously drilled by another operator. We expect to retain at least a 68% working interest in the well, which is located several miles to the east of the Mills Ranch #1 and #2 wells. Currently there are three producing wells on the large structure, including our Mills Ranch #1 and #2 on the west side. The three producing wells on this structure have produced over 21 Bcfe to date. Subsequent to drilling the Mills Ranch #1-99S, we plan to utilize the same large drilling rig to drill two additional deep Hunton and Arbuckle wells during 2004. At least one of these wells will be a development well on the west side of the field.

Other Hunton Trend. We continue generating additional high potential opportunities within the Hunton trend, including prospects with substantial reserve potential in the stratigraphically deeper Arbuckle formation. The Arbuckle is a several thousand-foot carbonate interval that has been productive in a number of fields with significant cumulative production in the area. However, the presence of a large carbonate Arbuckle interval does not insure the presence of hydrocarbons, which in most cases will be dependent upon the presence of a fault, change in stratigraphy or other hydrocarbon trapping mechanism. The drilling depths for the Arbuckle vary widely within the trend, from as shallow as 10,000 feet to depths as great as 25,000 feet.

West Texas

West Texas is predominantly an oil producing province with generally longer lived reserves than that of the onshore Texas Gulf Coast. Our drilling activity in our West Texas province has been focused primarily in various carbonate reservoirs, including the Canyon Reef and Fusselman formations of the Horseshoe Atoll trend, the Canyon Reef of the Eastern Shelf, and the Mississippian Reef of the Hardeman Basin, at depths ranging from 7,000 to 13,000 feet.

Over the past three years, we have spent approximately 7% of our total capital expenditures for drilling, land and geological and geophysical in West Texas and have completed 14 gross wells (5.2 net) in 17 attempts for a completion rate of 82%. Production from West Texas represented 16% of our average daily production in 2003 down from 21% in 2001.

During 2003 we completed four gross wells (1.3 net) in five attempts for a completion rate of 80%. We operated one of the five wells that we drilled in West Texas in 2003. Four of the wells we drilled were exploratory and one was developmental.

For 2004, we intend to continue to focus our drilling activities on our 3-D delineated exploration inventory in the Canyon Reef and Fusselman formations of the Horseshoe Atoll trend. For 2004, we expect to spend approximately $1.7 million to drill one development well with a working interest of 40% and four exploratory wells with an average working interest of 51%.

Horseshoe Atoll Trend

We have an inventory of approximately 1,049 square miles (671,360 acres) of 3-D seismic data primarily covering significant portions of Scurry, Howard, Dawson and Borden Counties in the Horseshoe Atoll trend, where we have accumulated substantial experience exploring with 3-D seismic over the last twelve years. In 2002, and in prior years, we frequently sold working interests in our West Texas drilling prospects to industry participants on a promoted basis, which has reduced our drilling risk while also contributing to lower finding costs and higher rates of return. Since 2000, we have completed 12 gross wells in 12 attempts in the trend with an average working interest of 44%.

3-D Seismic Exploration

We have accumulated 3-D seismic data covering approximately 9,948 square miles (6.4 million acres) in over 28 geologic trends in seven basins and seven states. We typically acquire 3-D seismic data in and around existing producing fields where we can benefit from the imaging of producing analog wells. These 3-D defined analogs, combined with our experience in drilling 592 wells in our 3-D project areas, provide us with a knowledge base to evaluate other potential geologic trends, 3-D seismic projects within these trends and prospective 3-D delineated drilling locations. Through our experience in the early and mid 1990’s, we developed an expertise in the selection of geologic trends that we believe are best suited for 3-D seismic exploration. In 1997 and 1998 we invested approximately $64 million in 3-D seismic and land in plays that we believed were providing optimal 3-D delineated drilling economics. We have used the experience that we have gained within our core trends to enhance the quality of subsequent projects in the same trend and other analogous trends, to lower finding and development costs, to compress project cycle times and to enhance our return on capital.

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Over the last twelve years we have accumulated substantial experience exploring with 3-D seismic in a wide range of reservoir types and geologic trapping mechanisms. In addition, we typically acquire digital data bases for integration on our computer-aided exploration workstations, including digital land grids, well information, log curves, production information, geologic studies, geologic top data bases and existing 2-D seismic data. We use our knowledge base, local geological expertise and digital data bases integrated with 3-D seismic data to create maps of producing and potentially productive reservoirs. As such, we believe our 3-D generated maps are more accurate than previous reservoir maps (which generally are based on subsurface geological information and 2-D seismic surveys), enabling us to more precisely evaluate recoverable reserves and the economic feasibility of projects and drilling locations.

We have acquired most of our raw 3-D seismic data using seismic acquisition vendors on either a proprietary basis or through alliances affording the alliance members the exclusive right to interpret and use data for extended periods of time. In addition, we have participated in non-proprietary group shoots of 3-D seismic data (commonly referred to as “spec data”) when we believe the expected full cycle project economics were justified, and we have exchanged certain interests in some of our non-core proprietary seismic data to gain access to additional 3-D seismic data. In most of our proprietary 3-D data acquisitions and alliances, we have selected the sites of projects, primarily guided by our knowledge and experience in the core provinces we explore, established and monitored the seismic parameters of each project for which data was shot, and typically selected the equipment that was used.

Combining our geologic and geophysical expertise with a sophisticated land effort, we manage the majority of our projects from conception through 3-D acquisition, processing and interpretation and leasing. In addition, we manage the negotiation and drafting of most of our geophysical exploration agreements, resulting in reduced contract risk and more consistent deal terms. Because we generate most of our projects, we can often control the size of the working interest that we retain as well as the selection of the operator and the non-operating participants. Consistent with our business strategy, we have increased the working interest we retain in our projects, based upon capital availability and perceived risk. Our average working interest in our 3-D seismic projects acquired during 1996, 1997 and 1998 was 37%, 67% and 80%, respectively. The 3-D seismic we acquired during 1999, 2000, 2001 and 2002 was primarily through the exchange of certain rights in some of our non-core 3-D seismic projects. Most of these exchanges did not include an industry participant, therefore we retained potentially all interest in any prospects generated from the newly acquired 3-D seismic data. In early 2003, we acquired approximately 84 square miles of new proprietary 3-D seismic data in our General Patton Project located in the Frio trend of the Upper Texas Gulf Coast. We sold a working interest in this project to an industry participant on a promoted basis and thus retained a 50% working interest in the project. In 2003 and early 2004, we acquired approximately 77 square miles of non-proprietary and 54 square miles of new proprietary 3-D seismic data in our Bayou Bengal Project, also located in the Frio trend of the Upper Texas Gulf Coast. We sold a working interest in Bayou Bengal to an industry participant on a promoted basis and retained a 75% working interest in the project. In 2004, we expect to acquire approximately 267 square miles of new proprietary 3-D seismic data within our core areas.

Title to Properties

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to royalty interests, standard liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. Our senior credit facility and senior subordinated notes are secured by first and second liens, respectively, against substantially all of our proved oil and natural gas properties. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior Credit Facility” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior Subordinated Notes.”

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Oil and Natural Gas Reserves

Our estimated total net proved reserves of oil and natural gas as of December 31, 2003, 2002 and 2001 and the present values attributable to these reserves as of those dates were as follows:

The reserve estimates reflected above were prepared by Cawley, Gillespie & Associates, Inc., our independent petroleum consultants, and are part of reports on our oil and natural gas properties prepared by Cawley, Gillespie.

In accordance with applicable requirements of the Securities and Exchange Commission, estimates of our net proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of net proved reserves and future net revenues there from are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The reserve data set forth in the Cawley, Gillespie report represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas 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 geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves have not been filed with or included in reports to any federal agency. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors—We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows.”

Estimates with respect to net proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the estimated reserves that may be substantial.

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Drilling Activities

We drilled, or participated in the drilling of, the following number of wells during the periods indicated:

(a)		Excludes one (0.5 net) exploration well that is under evaluation and temporarily abandoned.
(b)		Excludes one (0.2 net) development well that is productive but was temporarily abandoned. There are no current plans to put this well on production.
(c)		Excludes one (0.3 net) development well that was temporarily abandoned during drilling due to operational difficulties encountered prior to reaching total depth. We re-entered and completed this temporarily abandoned well during 2002.

We do not own drilling rigs and the majority of our drilling activities have been conducted by independent contractors or by industry participant operators under standard drilling contracts.

Productive Wells and Acreage

Productive Wells

The following table sets forth our ownership interest at December 31, 2003 in productive oil and natural gas wells in the areas indicated.

Productive wells consist of producing wells and wells capable of production, including wells waiting on pipeline connection. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, two had multiple completions.

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Acreage

In addition, as of December 31, 2003, we had lease options to acquire additional acres. The following table sets forth the year in which our options expire and the gross and net acres we have under option:

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Volumes, Prices and Production Costs

The following table sets forth the production volumes, average prices received before hedging, average prices received after hedging and average production costs associated with our sale of oil and natural gas for the periods indicated.

Costs Incurred

The costs incurred in oil and natural gas acquisition, exploration and development activities are as follows:

(a)		Excludes $427,000 of proceeds from the sale of interests in properties, projects and prospects in 2003.
(b)		Excludes $821,000 of proceeds from the sale of interests in properties, projects and prospects in 2002.
(c)		Excludes $262,000 of proceeds from the sale of interests in properties, projects and prospects in 2001.

Costs incurred represent amounts we incurred for exploration, property acquisition and development activities. Periodically, we receive reimbursement of certain costs from participants in our projects subsequent to project initiation in return for an interest in the project. These payments are described as “Proceeds from participants” in the table above.

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ITEM 3. LEGAL PROCEEDINGS

We are, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial condition, results of operations or cash flows.

On November 20, 2001, we filed a lawsuit in the District Court of Travis County, Texas, against Steve Massey Company, Inc. The Petition claims Massey furnished defective casing to us, which ultimately led to the casing failure of our Palmer 347 #5 well and the loss of the Palmer #5 as a producing well. In 2004, the parties agreed in principle to settle the case on terms favorable to us. We will receive approximately $440,000 as a result of this settlement. The amount of the settlement will reduce capitalized well cost. In addition, Massey has agreed to drop its $445,819 counterclaim.

On July 11, 2002, an employee of a contractor on our Burkhart #1-R location, Matagorda County, Texas, was involved in a fatal accident. The United States Department of Labor Occupational Safety & Health Administration conducted an inspection and we settled all issues resulting from that inspection for $70,000 in October 2003.

On October 8, 2002, relatives of the contractor’s employee filed a wrongful death action against us and three other contractors in the District Court of Matagorda County, Texas. On March 23, 2004, a jury determined that we had no liability in the accidental death of the contractor’s employee.

In September 2002, we filed suit in the District Court of Matagorda County, Texas, against one of our contractors in connection with the drilling of the Burkhart #1-R well, claiming that contractor breached its contract with us and negligently performed services on the well. We believe the contractor’s actions damaged us by approximately $650,000. The contractor counterclaimed, claiming it is entitled to recover approximately $315,000. In February 2004, the parties agreed in principle to settle the case. The settlement will result in a payment by the contractor to our co-participants and us. In addition, the contractor will drop its counterclaim. Based on the amount of the settlement, the additional costs that were covered by insurance, and the insurer being subrogated to our claim, we will not receive any incremental recovery as a result of the settlement.

Prior to drilling, the operator of the Stonehocker #1 well disputed our ownership in the well. In March 2003, a Motion to Determine election was filed with the Oklahoma Corporation Commission. In January 2004, an Administrative Law Judge with the Oklahoma Corporation Commission ruled in our favor. The operator of the Stonehocker #1 appealed the ruling and the Appellate Referee with the Oklahoma Corporation Commission affirmed the original ruling in March 2004. The full Commission Panel will review the reports of the Referee and the original Administrative Law Judge and either approve or modify the report. An order will then be issued reflecting the Oklahoma Corporation Commission ruling. The operator will then have 30 days from the date of the final order to file an appeal with the Oklahoma Supreme Court.

A company that relinquished its ownership interest in the Nold #1S well as a result of a non-consent election in the re-completion of the well has asserted that it did not relinquish its entire interest, but rather became subject only to a 400 percent payout provision. In November 2003, the company filed a lawsuit in the District Court of Brazoria County, Texas, against us for breach of contract. If the suit is successful, it could result in a judgment of as much as $700,000. At this point in time, we cannot predict the outcome of this case.

In December 2003, we filed a lawsuit in the United States District Court for the Western District of Texas against another company and a former employee concerning the defendants’ misappropriation of our trade secrets and breach of confidentiality obligations. We are seeking recovery of our damages and injunctive relief. Defendants have denied any wrongdoing and have asserted a counterclaim against us for alleged tortuous interference with an existing business relationship between the company and its employee. The counterclaim does not specify the amount of damages claimed other than that the damages exceed $75,000 (the jurisdictional limit). At this point in time, we cannot predict the outcome of this case.

As of December 31, 2003, there are no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on our capital expenditures.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

No matter was submitted to a vote of our security holders during the fourth quarter of 2003.

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EXECUTIVE OFFICERS OF THE REGISTRANT

Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this report.

The following are our executive officers as of March 26, 2004.

Ben M. “Bud” Brigham has served as our Chief Executive Officer, President and Chairman of the Board since we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood Resources, an independent oil and gas exploration and production company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for Western Geophysical, Inc. a provider of 3-D seismic services, after earning his B.S. in Geophysics from the University of Texas. Mr. Brigham is the brother of David T. Brigham, Executive Vice President—Land and Administration.

Eugene B. Shepherd, Jr. has served as Executive Vice President since September 2003 and Chief Financial Officer since June 2002. Mr. Shepherd has approximately 20 years of financial and operational experience in the energy industry. Prior to joining us, Mr. Shepherd served as Integrated Energy Managing Director at ABN AMRO Bank, a large European bank, where he executed merger and acquisition advisory, capital markets and syndicated loan transactions for energy companies. From July 1998 to August 2000, Mr. Shepherd was an investment banking Director for Prudential Securities Incorporated, where he executed a wide range of transactions for energy companies. Prior to joining Prudential Securities Incorporated, Mr. Shepherd served as an investment banker with Stephens Inc. from 1990 to June 1998 and with Merrill Lynch Capital Markets from 1986 to 1990. Prior to joining Merrill Lynch Capital Markets, Mr. Shepherd worked for over four years as a petroleum engineer for both Amoco Production Company and the Railroad Commission of Texas. He has a B.S. in Petroleum Engineering and an MBA, both from the University of Texas at Austin.

David T. Brigham joined us in 1992 and has served as a Director since May 2003, and as Executive Vice President—Land and Administration since June 2002. Mr. Brigham served as Senior Vice President—Land and Administration from March 2001 to June 2002, Vice President—Land and Administration from February 1998 to March 2001, as Vice President—Land and Legal from 1994 until February 1998 and as Corporate Secretary from February 1998 to September 2002. From 1987 to 1992, Mr. Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels & Wooldridge. Before attending law school, Mr. Brigham was a landman for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman of the Board.

A. Lance Langford joined us in 1995 as Manager of Operations and served as Vice President—Operations from January 1997 to March 2001, served as Senior Vice President—Operations from March 2001 to September 2003 and has served as Executive Vice President—Operations since September 2003. From 1987 to 1995, Mr. Langford served in various engineering capacities with Meridian Oil Inc., handling a variety of reservoir, production and drilling responsibilities. Mr. Langford holds a B.S. in Petroleum Engineering from Texas Tech University.

Jeffery E. Larson joined us in 1997 and was Vice President—Exploration from August 1999 to March 2001, Senior Vice President—Exploration from March 2001 to September 2003 and has served as Executive Vice President—Exploration since September 2003. Prior to joining us, Mr. Larson was an explorationist in the Offshore Department of Burlington Resources, a large independent exploration company, where he was responsible for generating exploration and development drilling opportunities. Mr. Larson worked at Burlington from 1990 to 1997 in various roles of responsibility. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist and Research Scientist. He has a B.S. in Earth Science from St. Cloud State University in Minnesota and a M.S. in Geology from the University of Montana.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Price Range of Common Stock and Dividend Policy

Our common stock commenced trading on the Nasdaq National Market on May 8, 1997 under the symbol “BEXP.” The following table sets forth the high and low intra-day sales prices per share of our common stock for the periods indicated on the Nasdaq National Market for the periods indicated. The sales information below reflects inter-dealer prices, without retail mark-ups, mark-downs or commissions and may not necessarily represent actual transactions.

The closing market price of our common stock on March 26, 2004 was $6.78 per share. As of March 26, 2004, there were an estimated 122 record owners of our common stock.

No dividends have been declared or paid on our common stock to date. We intend to retain all future earnings for the development of our business. Our senior credit facility, senior subordinated notes and Series A preferred stock restrict our ability to pay dividends on our common stock.

We are obligated to pay dividends on our Series A preferred stock. At our option, these dividends may be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind on our Series A preferred stock expires in October 2005. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Commitments—Mandatorily Redeemable Preferred Stock.”

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Securities Authorized for Issuance under Equity Compensation Plans

     The following table includes information regarding our equity compensation plans as of the year ended December 31, 2003:

Recent Issuance of Unregistered Securities

Common Stock

All shares of common stock issued in the following transactions were exempted from registration under section 4(2) of the Securities Act of 1933.

In December 2002, we issued 550,000 unregistered shares of our common stock to Shell Capital. The common stock was issued in exchange for Shell Capital’s warrant position, including 1,250,000 warrants associated with our senior subordinated notes facility, and to terminate its right to convert $30 million of our senior credit facility into 5,480,769 shares of our common stock. Shell Capital subsequently sold these shares in our common stock sale in September 2003 and we received no proceeds from the sale of the common stock.

In December 2002, we issued 243,902 unregistered shares of our common stock to a group of institutional investors led by affiliates of two members of our board of directors. The common stock was issued to the group in connection with its cash exercise of warrants to purchase 243,902 shares of our common stock for $2.5625 per share. We received cash proceeds $625,000 from the exercise. The warrants exercised represented a portion of the warrants that were issued in connection with our sale of 731,707 shares of our common stock in February 2000. The remaining warrants were exercised in February 2003.

In February 2003, we issued 248,028 unregistered shares of our common stock to a group of institutional investors led by affiliates of two of our board members. The common stock was issued to the group in connection with its cashless exercise of warrants to purchase 487,805 shares of our common stock for $2.5625 per share. We received no proceeds from the warrant exercise. The warrants exercised represented a portion of the warrants that were issued in connection with our sale of 731,707 shares of our common stock in February 2000.

In June 2003, we issued 408,928 unregistered shares of our common stock to the Bank of Montreal. The common stock was issued to the Bank of Montreal in connection with its cashless exercise of warrants to purchase 661,538 shares of our common stock for $2.02 per share. We received no proceeds from the warrant exercise. The warrants were issued as consideration for an amendment to a previous senior credit facility in July 1999. The original warrant exercise price of $2.25 per share was reset to $2.02 in February 2000 in connection with an amendment to a previous senior credit facility. The Bank of Montreal subsequently sold these shares in our common stock sale in September 2003 and we received no proceeds from the sale of the common stock.

In June 2003, we issued 206,982 unregistered shares of our common stock to Société Générale. The common stock was issued to Société Générale in connection with its cashless exercise of warrants to purchase 338,462 shares of our common stock for $2.02 per share. We received no proceeds from the warrant exercise. The warrants were issued as consideration for an amendment to a previous senior credit facility in July 1999. The original warrant exercise price of $2.25 per share was reset to $2.02 in February 2000 in connection with an amendment to a previous senior credit facility. Société Générale subsequently sold these shares in our common stock sale in September 2003 and we received no proceeds from the sale of the common stock.

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In November 2003, we issued 6,666,667 unregistered shares of our common stock to CSFB Private Equity. The common stock was issued to CSFB Private Equity in connection with its exercise of warrants to purchase 6,666,667 shares of our common stock for $3.00 per share. Pursuant to the warrant agreement, we required CSFB Private Equity to exercise the warrants as the average price of our common stock closed above $5.00 per share each day for 60 consecutive days. CSFB Private Equity elected to use 1,000,002 shares of Series A preferred stock to pay the $20 million exercise price. The warrants were issued in connection with our sale of $20 million of Series A – Tranche 1 preferred stock to CSFB Private Equity in November 2000.

In December 2003, we issued 2,105,263 unregistered shares of our common stock to CSFB Private Equity. The common stock was issued to CSFB Private Equity in connection with its exercise of warrants to purchase 2,105,263 shares of our common stock for $4.35 per share. The original exercise price for the warrants was $4.75, but was reset in December 2002, in connection with the issuance of our Series B preferred stock. Pursuant to the warrant agreement, we required CSFB Private Equity to exercise the warrants as our stock price averaged at least $6.525 (150% of the exercise price of the warrants) for 60 consecutive trading days. CSFB Private Equity elected to use 457,898 shares of Series A preferred stock to pay the $9.2 million exercise price and we received no proceeds from the warrant exercise. The warrants were issued in connection with our sale of $10 million of Series A – Tranche 2 preferred stock to CSFB Private Equity in March 2001. See “— Mandatorily Redeemable Preferred Stock.”

In December 2003, we issued 2,298,850 unregistered shares of our common stock to CSFB Private Equity. The common stock was issued to CSFB Private Equity in connection with its exercise of warrants to purchase 2,298,850 shares of our common stock for $4.35 per share. Pursuant to the warrant agreement, we required CSFB Private Equity to exercise the warrants as our stock price averaged at least $6.525 (150% of the exercise price of the warrants) for 60 consecutive trading days. CSFB Private Equity elected to use 500,002 shares of Series B preferred stock to pay the $10 million exercise price and we received no proceeds from the warrant exercise. The warrants were issued in connection with our sale of $10 million of Series B preferred stock to CSFB Private Equity in December 2002. See “— Mandatorily Redeemable Preferred Stock.”

Mandatorily Redeemable Preferred Stock

All shares of mandatorily redeemable preferred stock issued in the following transactions were exempted from registration under section 4(2) of the Securities Act of 1933.

In March 2001, we issued to CSFB Private Equity 500,000 shares of our Series A – Tranche 2 preferred stock with a stated value of $20.00 per share. Net proceeds from the offering were $9.8 million and were used to fund our exploration and development activities and working capital requirements. The Series A – Tranche 2 preferred stock has terms similar to our previously issued Series A preferred stock. We are required to pay dividends on our Series A preferred stock at a rate of 6% per annum if paid in cash or 8% per annum if paid in kind through the issuance of additional shares of preferred stock in lieu of cash. Our option to pay dividends in kind expires in October 2005. In connection with the issuance of the Series A – Tranche 2 preferred stock, we issued to CSFB Private Equity warrants to purchase 2,105,263 shares of our common stock at an exercise price of $4.75 per share. The original exercise price for the warrants was reset in December 2002, in connection with the issuance of our Series B preferred stock. To exercise the warrants, CSFB Private Equity had the option to use either cash or shares of Series A preferred stock with an aggregate value equal to the exercise price. In December 2003, CSFB Private Equity elected to use 457,898 shares of Series A preferred stock to pay the $9.2 million warrant exercise price. See “—Common Stock.”

In December 2002, we issued to CSFB Private Equity 500,000 shares of our Series B preferred stock with a stated value of $20.00 per share. Net proceeds from the offering were $9.4 million and were used to reduce borrowings under our senior credit facility and to fund our drilling program and working capital requirements. The Series B preferred stock has terms similar to our previously issued Series A preferred stock. We were required to pay dividends on our Series B preferred stock at a rate of 6% per annum if paid in cash or 8% per annum if paid in kind through the issuance of additional shares of preferred stock in lieu of cash. Our option to pay dividends in kind would have expired in December 2007. In connection with the issuance of the Series B preferred stock, we issued to CSFB Private Equity warrants to purchase 2,298,851 shares of our common stock at an exercise price of $4.35 per share. To exercise the warrants, CSFB Private Equity had the option to use either cash or shares of our Series B preferred stock with an aggregate value equal to the exercise price. In December 2003, CSFB Private Equity elected to use 500,002 shares of Series B preferred stock to pay the $10 million warrant exercise price. See “—Common Stock.” In addition, pursuant to the terms of the Series B preferred stock we paid CSFB Private Equity approximately $704,000 to redeem the shares of Series B preferred stock that remained outstanding after the exercise.

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ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

This section presents our selected consolidated financial data and should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data.” The selected consolidated financial data in this section is not intended to replace the consolidated financial statements.

We derived the statement of operations data and statement of cash flows data for the years ended December 31, 2003, 2002 and 2001, and balance sheet data as of December 31, 2003 and 2002 from the audited consolidated financial statements included in this report. We derived the statement of operations data and statement of cash flows data for the years ended December 31, 2000 and 1999 and the balance sheet data as of December 31, 2001, 2000 and 1999 from audited consolidated financial statements that are not included in this report.

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

Statements in the following discussion may be forward-looking and involve risk and uncertainty. The following discussion should be read in conjunction with our Consolidated Financial Statements and Notes hereto.

Overview

We are an independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore for and develop onshore oil and natural gas reserves in the United States. Our activities are concentrated in the onshore Texas Gulf Coast, the Anadarko Basin and West Texas, which are areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs and the skills of our technical staff.

Our principal business is the generation of drilling prospects in our core provinces, the drilling of those prospects and, if successful, the subsequent completion and production of the resulting oil or natural gas well. We do not have a history of aggressively competing for acquisition opportunities, although we regularly review such opportunities. We believe that we can achieve a better and more predictable rate of return by focusing our activities on prospect generation, drilling and producing activities.

To support our prospect generation activities, we allocate a portion of our capital expenditures to land, geophysical and geological activities. Over the past three years capital expenditures for land, geophysical and geological activities represented 12% of our total capital expenditures. For 2004, we expect to spend approximately 15% of our total capital expenditures on land, geophysical and geological activities.

The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We start each year with a budget and reevaluate this budget monthly. The primary factors that impact this value creation measure include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of our drilling expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our monthly analysis results in a reprioritization of our exploration and development well drilling schedule to ensure that we are optimizing our capital expenditure plan.

Over the past three years, we have spent approximately $33 million to drill 48 exploratory wells, which represents 30% of our total capital expenditures for that time period. For 2004, we currently plan to spend approximately $22 million, or 28% of our total budgeted capital expenditures to drill 23 exploratory wells. We believe that we possess a multi-year inventory of exploratory drilling prospects, the majority of which have been internally generated by our staff. As a consequence and considering the results that we have achieved in recent years, we expect that we will continue to emphasize our prospect generation and drilling strategy as our primary means of creating value for our shareholders.

Over the past three years we have spent approximately $49.1 million to drill 45 development wells, which represents 45% of our total capital expenditures for that time period. Due to our exploratory drilling success, over the last four years, a growing percentage of our capital expenditures have been allocated to the development of our six significant field discoveries. We expect this trend to continue, and for 2004 currently plan to spend approximately $39.4 million, or 50% of our total budgeted capital expenditures to drill 36 development wells.

2003 Highlights

During 2003, we achieved several financial and operational milestones. The following are some of the highlights for 2003.

•		Our average daily production for 2003 was 29.7 MMcfe/d and increased 7% over average daily production in 2002.
•		We added approximately 23.8 Bcfe of proved reserves, of which 20 Bcfe were proved developed, growing our estimated net proved reserve volumes by 11% and replacing 223% of our 2003 production.
•		We made a new field discovery at Floyd South.
•		We expanded our Diablo Project area with two new joint ventures.
•		We acquired two new 3-D seismic data sets in the Gulf Coast, which have already generated four discoveries in four attempts.
•		We reported operating income of $21.8 million, up 131% when compared to operating income for 2002.
•		Our earnings for 2003 were $0.53 per diluted share relative to a net loss of $0.04 in 2002.

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•		Our common stock offering in September 2003, combined with the exercise of the Series A and Series B warrants and our earnings, improved our balance sheet and strengthened our overall financial position by reducing our total debt to capitalization ratio from 63% at December 31, 2002 to 27% at December 31, 2003.
•		In November 2003, we significantly increased our drilling expenditures. We plan to use the availability under our senior credit facility, along with our internally generated cash flow and cash on hand, to accelerate our drilling activities in the current environment of high commodity prices and relatively low service costs.

2004 Outlook

Our total net capital spending budget for 2004 is $79 million. The majority of our planned 2004 expenditures will be directed toward the drilling of our exploration and development inventory to focus resources on our primary objective of growing our reserves, production volumes and cash flow. For 2004, we expect to drill 59 (36 development and 23 exploratory) wells with an average working interest of approximately 42%. Capitalizing on our prior discoveries, including the Home Run, Mills Ranch, Triple Crown, Floyd Fault Block, Floyd South Fault Block and Providence Fields, approximately 64% of our 2004 drilling expenditures are allocated to development drilling. Our current cash balance, cash flow from operations and availability under our senior credit facility, will fund our spending. Estimated net capital expenditures for 2004 represent an increase of approximately 61% over the amount that we spent in 2003. The final determination with respect to our 2004 budgeted expenditures will depend on a number of factors, including:

•		commodity prices;
•		production from our existing producing wells;
•		the results of our current exploration and development drilling efforts;
•		economic and industry conditions at the time of drilling, including the availability of drilling equipment; and
•		the availability of more economically attractive prospects.

There can be no assurance that the budgeted wells will, if drilled, encounter commercial quantities of natural gas or oil.

Statements in this section include forward-looking statements. See “—Forward-Looking Statements.”

Critical Accounting Policies

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our consolidated financial statements in accordance with generally accepted accounting principles (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Property and Equipment

The method of accounting for oil and natural gas properties is a critical accounting policy because it determines what costs are capitalized, and how these costs are ultimately matched with revenues and expensed.

We use the full cost method of accounting for oil and natural gas properties. Under this method substantially all costs associated with oil and natural gas exploration and development activities are capitalized, including costs for individual exploration projects that do not directly result in the discovery of hydrocarbon reserves that can be economically recovered. A portion of the payroll, interest, and other internal costs we incur for the purpose of finding hydrocarbon reserves are also capitalized.

Full cost pool amounts associated with properties that have been evaluated through drilling or seismic analysis are depleted using the units of production method. The depletion expense per unit of production is the ratio of unamortized historical and estimated future development costs to proven hydrocarbon reserve volumes. Estimation of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. For the year ended December 31, 2003, our depletion expense per unit of production was $1.59 per Mcfe. A change of 900,000 Mcfe in our estimated net proved reserves at December 31, 2003, would result in a $0.01 per Mcfe change in our per unit depletion expense and a $107,000 change in our pre-tax net income.

To the extent costs capitalized in the full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate and based on period-end hedge adjusted oil and natural gas prices) of estimated future net

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cash flows from proved oil and natural gas reserves plus the capitalized cost of unproved properties, such costs are charged to operations as a reduction of the carrying value of oil and natural gas properties, or a “capitalized ceiling impairment” charge. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or estimations of proved reserves are substantially reduced.

A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity. Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. No assurance can be given that we will not experience a capitalized ceiling impairment charge in future periods. In addition, capitalized ceiling impairment charges may occur if estimates of proved hydrocarbon reserves are substantially reduced or estimates of future development costs increase significantly. See “—Risk Factors—Exploratory Drilling Is A Speculative Activity That May Not Result In Commercially Productive Reserves And May Require Expenditures In Excess Of Budgeted Amounts,” “—Risk Factors—The Failure To Replace Reserves In The Future Would Adversely Affect Our Production And Cash Flows” and “—Risk Factors—We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows.”

Asset Retirement Obligations

We have significant obligations to plug and abandon oil and natural gas wells and related equipment. Liabilities for asset retirement obligations are recorded at fair value in the period incurred. The related asset value is increased by the same amount. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation. See “—Property and Equipment.” Additionally, increases in the discounted asset retirement liability resulting from the passage of time are reflected as accretion of discount on asset retirement obligations expense in the Consolidated Statement of Income.

Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments. These include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the carrying cost of the related asset.

Income Taxes

Deferred tax assets are recognized for temporary differences in financial statement and tax basis amounts that will result in deductible amounts and carry-forwards in future years. Deferred tax liabilities are recognized for temporary differences that will result in taxable amounts in future years. Deferred tax assets and liabilities are measured using enacted tax law and tax rate(s) for the year in which we expect the temporary differences to be deducted or settled. The effect of a change in tax law or rates on the valuation of deferred tax assets and liabilities is recognized in income in the period of enactment. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Estimating the amount of the valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that would trigger limits on use of net operating losses under Internal Revenue Code Section 382.

We have a significant deferred tax asset associated with net operating loss carryforwards (NOLs). It is more likely than not that we could begin using these NOLs to offset current tax liabilities during 2004. Our NOLs are more fully described in “Notes to the Consolidated Financial Statements—Note 9.”

Revenue Recognition

We derive revenue primarily from the sale of produced oil and natural gas, hence our revenue recognition policy for these sales is significant.

We recognize crude oil revenue using the sales method of accounting. Under this method, revenue is recognized when oil is delivered and title transfers.

We recognize natural gas revenue using the entitlements method of accounting. Under this method, revenue is recognized based on

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our entitled ownership percentage of sales of natural gas delivered to purchasers. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. When we receive less than our entitled share, a receivable is recorded. When we receive more than our entitled share, a liability is recorded.

Settlements for hydrocarbon sales can occur up to two months after the end of the month in which the oil, gas or other hydrocarbon products were produced. We estimate and accrue for the value of these sales using information available at the time financial statements are generated. Differences are reflected in the accounting period that payments are received from the purchaser.

Derivative Instruments and Hedging Activities

We use derivative instruments to manage market risks resulting from fluctuations in commodity prices of natural gas and crude oil. We periodically enter into commodity contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells.

We similarly use derivative instruments to manage risks associated with interest rate fluctuations on long term debt. During 2003 we entered into an interest rate swap to convert the floating interest rate on our senior subordinated notes to a fixed interest rate to reduce our exposure to potentially higher interest rates in the future. The notional amount of this hedge is equal to the amount of senior subordinated notes outstanding, and is more fully described in “Notes to the Consolidated Financial Statements—Note 5” and “Notes to the Consolidated Financial Statements—Note 12.”

We adopted Statement of Financial Accounting Standards No. 133 (SFAS 133) on January 1, 2001 in accordance with Financial Accounting Standards Board (FASB) requirements. SFAS 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. All derivative instruments are recorded on the balance sheet at fair value and changes in the fair value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction, and depending on the type of hedge transaction. Our derivative contracts are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. Changes in the fair value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. We assess the effectiveness of hedging transactions every three months, consistent with documented risk management strategy for the particular hedging relationship. Changes in the fair value of the ineffective portion of hedges are included in earnings.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect reported assets, liabilities, revenues, expenses, and some narrative disclosures. Hydrocarbon reserves, future development costs, and certain hydrocarbon production expense and revenue estimates are the most critical to our financial statements.

New Accounting Pronouncements

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity’’ (SFAS 150). SFAS 150 requires us to classify certain financial instruments, such as mandatorily redeemable preferred stock, as liabilities (or assets in some circumstances). We adopted this standard as required on July 1, 2003. Upon adoption, approximately $8 million of mandatorily redeemable Series A and B preferred stock was reclassified to long-term debt. Dividends of approximately $340,000 on the reclassified amount of mandatorily redeemable Series A and B preferred stock are included in our Consolidated Statement of Operations as interest expense.

Commodity Prices

Changes in commodity prices significantly affect our capital resources, liquidity and operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of available capital to reinvest in our exploration and development activities. Commodity prices are impacted by many factors that are outside of our control. Over the past couple of years, commodity prices have been very volatile. We expect that commodity prices will continue to fluctuate significantly in the future. As a result, we cannot accurately predict future oil and natural gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues.

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The prices we receive for our crude oil production are based on global market conditions. During 2003, oil prices increased in response to political unrest and supply disruptions in the Middle East as well as other supply and demand factors. Our average sales price for oil in 2003 was $30.79 per barrel, which was 22% higher than the price we received in 2002. Significant factors that will impact 2004 oil prices include developments in Iraq and other Middle East countries, the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to manage oil supply through export quotas. North American market forces primarily drive the price we receive for our natural gas production. Factors that can affect the price of natural gas are changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Over the past two years natural gas prices have been volatile. The average sales price that we received for natural gas in 2003 was $5.68 per Mcf, which was 71% higher than the sales price that we received for sales in 2002. The average sales price that we received for natural gas in 2002 was $3.33 per Mcf, which was 22% lower than the sales price that we received in 2001. The increase North American gas prices in 2003 were in response to strong supply and demand fundamentals. Natural gas prices for 2004 will depend on variations in key North American gas supply and demand indicators.

Capital Commitments

Our primary needs for cash are for the exploration and development of oil and gas properties, repayment of contractual obligations and funding working capital obligations. Funding for the exploration and development of oil and gas properties and repayment of contractual obligations may be provided by any combination of cash flow from operations, cash on our balance sheet, the unused committed borrowing capacity under our senior credit facility, reimbursements of prior land and seismic costs by participants in our projects and the sale of interests in projects and properties or alternative financing sources as discussed in “—Capital Resources and Liquidity.” Funding for our working capital obligations is provided by cash flows from operations and the unused committed borrowing capacity under our senior credit facility.

Contractual Obligations

The following schedule summarizes our known contractual cash obligations at December 31, 2003 and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

(a)

Based on $19 million outstanding and an interest rate at December 31, 2003, of 2.7%, we would be required to pay $513,000 in interest per year until our senior credit facility matures. This amount of interest will fluctuate over time as borrowings under our senior credit facility increase or decrease and as the applicable interest rate increases or decreases. See “Item 7A Quantitative and Qualitative Disclosures About Market Risk—Quantitative Disclosures—Interest Rate Risk.”

(b)

Based on $20 million outstanding and a current interest rate of 8.8%, we would be required to pay $1.8 million in interest per year until our senior subordinated notes mature.

(c)

At our option, dividends on our Series A preferred stock may be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind expires in November 2005. If we elect to pay the dividends in cash, based on $8.8 million outstanding we would be required to pay $528,000 in dividends per year until our mandatorily redeemable Series A preferred stock matures. If we elect to pay the dividends in kind, in 2004 we would be required issue approximately 36,250 shares of additional Series A preferred to pay dividends of $725,000. In 2005, we would be required to issue approximately 32,483 shares of additional Series A preferred stock to pay dividends of $649,660. The dividends in 2005 represents dividends on the outstanding Series A preferred stock from January 1, 2005 to October 31, 2005, the expiration of our option to pay dividends in kind. Thereafter, we would be required to pay an annual cash dividend of approximately $610,000 until maturity.

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(d)

Not reduced by rental payments that we will receive from a non-cancelable sublease of approximately $64,000 due in 2004 and $38,000 due in 2005.

Senior Credit Facility

As of December 31, 2003, we had $19 million in borrowings outstanding under our senior credit facility. In March 2003, we replaced our then existing senior credit facility with a new senior credit facility that provides for a maximum $80 million in commitments and an initial committed borrowing base of $70 million and matures in March 2006.

The collateral value and borrowing base are redetermined semi-annually and are based in part on prevailing oil and natural gas prices. If, upon redetermination, our borrowing base decreases, we may have to repay a portion of our borrowings within 90 days, our access to further borrowings will be reduced, and we may not have the resources necessary to carry out our planned drilling activities. Based on the most recent determination effective December 1, 2003, the committed borrowing base was set at $68.5 million. The unused portion of the committed borrowing base is subject to an annual commitment fee of 0.5%. See “—Liquidity and Capital Resources—Common Stock Transactions” and “—Liquidity and Capital Resources—Senior Credit Facility” for explanation of the changes in our outstanding debt balance under our senior credit facility.

As of March 26, 2004, we had $29.2 million of borrowings outstanding and $39.3 million of additional borrowing capacity under our senior credit facility.

Borrowings under our senior credit facility are secured by substantially all of our oil and natural gas properties. At our option, borrowings under our senior credit facility bear interest at a rate equal to: (i) the base rate of Société Générale plus a margin which fluctuates from 0.5% to 1.5% depending on facility usage or (ii) LIBOR for one, two, three or six months plus a margin which fluctuates from 1.5% to 2.5% depending on facility usage. Interest is due quarterly for base rate tranches or periodically as LIBOR tranches mature.

The senior credit facility agreement contains various covenants and restrictive provisions, which limit our ability to incur additional indebtedness, sell properties, purchase or redeem our capital stock, make investments or loans, create liens and make certain acquisitions. Our senior credit facility requires us to maintain a current ratio (as defined) of at least 1 to 1 and an interest coverage ratio (as defined) of at least 3.25 to 1. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants in the future. In such instance, our liquidity may be adversely affected, which could in turn have an adverse impact on our future financial position and results of operations. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Our current ratio at December 31, 2003 and interest coverage ratio for the twelve-month period ending December 31, 2003, were 2.0 to 1 and 8.2 to 1, respectively.

Senior Subordinated Notes

As of December 31, 2003, we had $20 million of senior subordinated notes outstanding. The terms of the senior subordinated notes were amended in March 2003 in order to have the covenants and other features of the notes mirror those of the new senior credit facility put in place at the same time. See “—Senior Credit Facility.” The terms of the senior subordinated notes were amended again in December 2003 to reduce the outstanding balance of the notes to $20 million, reduce the interest rate and extend the maturity of the notes from October 2005 until March 2009. Prior to the December 2003 amendment, the senior subordinated notes bore interest at 10.75% per annum, were redeemable at our option for face value at any time and had no principal repayment obligations. As a consequence of the December 2003 amendment, the 10.75% fixed rate coupon was converted to a floating rate coupon. Simultaneous with the completion of the amendment, we entered into an interest rate swap contract to fix the coupon at 8.76% through the new maturity date. Interest on the senior subordinated notes is payable quarterly in arrears on the first business day following the last day of each quarter ended March, June, September and December. See “—Liquidity and Capital Resources—Senior Subordinated Notes” for explanation of the changes in our outstanding senior subordinated notes balance.

The senior subordinated notes are secured obligations ranking junior to our senior credit facility and have covenants similar to the senior credit facility. As part of the December 2003 amendment, one additional covenant was added. We are required to maintain a ratio of risked net present value (as defined) discounted at 9% to total debt of 1.5 to 1.

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Mandatorily Redeemable Preferred Stock

As of December 31, 2003, we had $8.8 million in mandatorily redeemable Series A preferred stock outstanding, which is held by merchant banking funds managed by affiliates of CSFB Private Equity. At our option, the dividends on our Series A preferred stock may be paid in cash at a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind expires in October 2005. To date, we have satisfied all of the dividend payments with issuance of additional shares of Series A preferred stock. The Series A preferred stock matures in November 2010 and is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity.

Our preferred stock balance outstanding at December 31, 2003, represents the balance of preferred stock that remained outstanding after CSFB Private Equity exercised its warrants to purchase our common stock in November and December of this year. Over the past four years we have issued mandatorily redeemable preferred stock to CSFB Private Equity on three different occasions. The first issuance was in November 2000 ($20 million Series A – Tranche 1), the second issuance was in March 2001($10 million Series A – Tranche 2) and the third issuance was in December 2002 ($10 million Series B).

In connection with each issuance of mandatorily redeemable preferred stock, we issued to CSFB Private Equity warrants to purchase shares of our common stock. To exercise the warrants, CSFB Private Equity had the option to use either cash or shares of our mandatorily redeemable preferred stock with an aggregate value equal to the exercise price. In November 2000, in connection with the Series A – Tranche 1 we issued CSFB Private Equity warrants to purchase 6,666,667 shares of our common stock at an exercise price of $3.00. In March 2001, in connection with the Series A – Tranche 2 we issued CSFB Private Equity warrants to purchase 2,105,263 shares of our common stock at an exercise price of $4.75. The exercise price on the warrants issued in March 2001 was later reset to $4.35 in connection with the issuance of the December 2002 Series B preferred stock and warrant offering. In December 2002, in connection with the Series B we issued CSFB Private Equity warrants to purchase 2,298,850 shares of our common stock at an exercise price of $4.35 per share. As part of each warrant agreement, we had the option to require CSFB Private Equity to exercise the warrants if the price of our common stock met certain thresholds over a certain period of time. In the event our stock price closed above $5.00 per share each day for 60 consecutive days, we could require CSFB Private Equity to exercise the warrants to purchase 6,666,667 shares of our common stock at an exercise price of $3.00. If our stock price averaged at least $6.525 (150% of the exercise price of the warrants) over 60 consecutive trading days, then we could require CSFB Private Equity to exercise the warrants to purchase 2,105,263 shares of our common stock at an exercise price of $4.35 and the warrants to purchase 2,298,850 shares of our common stock at an exercise price of $4.35.

In November 2003, our stock price met the threshold, which enabled us to require CSFB Private Equity to exercise the warrants to purchase 6,666,667 shares of our common stock at an exercise price of $3.00. In November 2003, our average stock price met the threshold, which enabled us to require CSFB Private Equity to exercise the warrants to purchase 2,105,263 shares of our common stock at an exercise price of $4.35 and the warrants to purchase 2,298,850 shares of our common stock at an exercise price of $4.35. In all three cases, we required CSFB Private Equity to exercise the warrants. The combined exercise price of the warrants was $39.2 million and CSFB Private Equity elected to use 1,457,900 shares of Series A preferred stock and 500,002 shares of Series B preferred stock to pay for the exercise of the warrants. In addition, pursuant to the terms of the Series B preferred stock we paid CSFB Private Equity approximately $704,000 to redeem the shares of Series B preferred stock that remained outstanding after the exercise.

Our outstanding balance of mandatorily redeemable preferred stock at December 31, 2003, consisted of the Series A shares that remained outstanding after the exercise and an additional 24,738 Series A shares issued to satisfy pay in kind dividends for the fourth quarter of 2003.

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Capital Expenditures

The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Our capital expenditures for the past three years are as follows:

Off Balance Sheet Arrangements

We currently have operating leases, which are considered off balance sheet arrangements. See “—Contractual Obligations” for future obligations associated with our operating leases. We do not currently have any other off balance sheet arrangements or other such unrecorded obligations, and we have not guaranteed the debt of any other party.

Results of Operations

Comparison of the twelve-month periods ended December 31, 2003, 2002 and 2001

Production. Our net equivalent production volumes for 2003 were 10.7 Bcfe (29.7 MMcfe/d) compared to 10.0 Bcfe (27.8 MMcfe/d) in 2002 and 9.6 Bcfe (26.6 MMcfe/d) in 2001. The increase in production volume was due to production growth from wells that were drilled and completed during the periods. New production from these wells was partially offset by the natural decline of existing production. Natural gas represented 60%, 58% and 71% of our total production in 2003, 2002 and 2001, respectively.

For 2003 compared to 2002, the change in our production volumes was due to the following:

•		Production from our Gulf Coast province for 2003 increased 24% when compared to production from that province in 2002. Gulf Coast production represented 61% of our total production in 2003 versus 53% in 2002. Natural gas represented approximately 60% of the total production from the Gulf Coast in 2003 compared to 61% in 2002.
•		Production from our Anadarko Basin province for 2003 decreased 6% when compared to production from that province in 2002. Anadarko Basin production represented 23% of our total production in 2003 versus 26% in 2002. Natural gas represented approximately 90% of the total production from the Anadarko Basin in 2003 and 2002.
•		Production from our West Texas province for 2003 decreased 21% when compared to production from that province in 2002. West Texas production represented 16% of our total production versus 21% in 2002. Production from our West Texas province is primarily oil. Oil represented approximately 85% of the total production from our West Texas province in 2003 versus 88% in 2002.

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For 2002 compared to 2001, the change in our production volumes was due to the following:

•		Production from our Gulf Coast province for 2002 increased 37% when compared to production from that province in 2001. Gulf Coast production represented 53% of our total production in 2002 versus 41% in 2001. Natural gas represented approximately 61% of the total production from the Gulf Coast in 2002 compared to 83% in 2001.
•		Production from our Anadarko Basin province for 2002 decreased 30% when compared to production from that province in 2001. Anadarko Basin production represented 26% of our total production in 2002 versus 38% in 2001. Natural gas represented approximately 90% of the total production from the Anadarko Basin in 2002 versus 91% in 2002.
•		Production from our West Texas province for 2002 decreased 3% when compared to production from that province in 2001. West Texas production represented 21% of our total production in 2002 and 2001. Production from our West Texas province is primarily oil. Oil represented approximately 88% of the total production from our West Texas province in 2002 and 2001.

Revenue from the sale of oil and natural gas. Revenues from the sale of oil and natural gas that we report are based on the market price received for our commodities adjusted by marketing charges and the results from the settlement of our derivative commodity contracts that qualify for hedge accounting treatment under SFAS 133.

We utilize commodity swap, collar and floor contracts to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Qualitative Disclosures—Commodity Price Risk” for a description of derivative commodity contracts.

The effective portions of changes in the fair values of our derivative commodity contracts that qualify for hedge accounting treatment under SFAS 133 are deferred as increases or decreases to stockholders’ equity until the underlying contract is settled. Consequentially, changes in the effective portions of our derivative commodity contracts that qualify for hedge accounting treatment under SFAS 133 add volatility to our reported stockholders’ equity until the contract is settled or is terminated. See “Notes to the Consolidated Financial Statements—Note 2.”

The gain or loss related to the ineffective portion of changes in the fair market value of our derivative commodity contracts that qualify for hedge accounting treatment under SFAS 133 is recognized in other income (expense).

The gain or loss related to the settlement and changes in the fair values of our derivative commodity contracts that do not qualify for hedge accounting treatment under SFAS 133 are recognized in other income (expense).

All of our open derivative commodity contracts at December 31, 2003, qualified for hedge accounting treatment under SFAS 133. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Qualitative Disclosures—Commodity Price Risk” for our open derivative commodity contracts at December 31, 2003.

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The table below shows revenue that we have realized from the sale of oil and natural gas over the past three years.

Our total revenue from the sale of oil and natural gas in 2003 was 47% higher than total revenue from the sale of oil and natural gas in 2002. The change in our total revenue from the sale of oil and natural gas from 2002 to 2003 is due to the following:

•		Approximately $19 million of the increase in oil and natural gas sales was due to a $1.76 Mcfe increase in the sales price that we received for oil and natural gas.
•		The remaining $2.3 million of the increase in oil and natural gas sales was due to an increase in our production volumes.
•		The increases in total revenue from the sale of oil and natural gas due to higher prices and increased production volumes were partially offset by a 262% increase in losses due to the cash settlement of derivative commodity contracts.

Our total revenue from the sale of oil and natural gas in 2002 was 9% lower than total revenue from the sale of oil and natural gas in 2001. The change in our total revenue from the sale of oil and natural gas from 2002 to 2001 is due to the following:

•		Approximately $5 million of the decrease in oil and natural gas sales was due to a $0.53 per Mcfe decline in the average sales price that we received for oil and natural gas.
•		The decrease in oil and natural gas sales due to a decline in the average sales price that we received for oil and natural gas was partially offset by a $1.5 million increase in oil and natural gas sales related to an increase in oil and natural gas production.
•		The decrease in total revenue from oil and natural gas sales due to a decline in the average sales price that we received for oil and natural gas was partially offset by a 77% decrease in losses due to the cash settlement of derivative commodity contracts.

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The following table shows the type of derivative commodity contracts, the volumes, the weighted average NYMEX reference price for those volumes, and the associated gain /(loss) upon settlement of those hedges for 2003, 2002 and 2001.

Other revenue. Other revenue relates to fees that we charge other parties who use our two gas gathering systems to move their production from the wellhead to third party gas pipeline systems. These gathering systems are owned by us and located in the Texas Gulf Coast. One of the gathering systems connects to a single well and the other connects two wells. Other revenue for 2003 was $132,000 compared to $76,000 in 2002 and $255,000 in 2001.

Production costs. Production costs include lease operating expenses and production taxes.