UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2004

or

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

For the transition period from                                          to                                         

Commission File No. 001-32367

BILL BARRETT CORPORATION

(303) 293-9100
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to section 12(g) of the Act: None

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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. þ

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of March 1, 2005. $602,471,545*

As of March 1, 2005, the registrant had outstanding 43,362,738 shares of $.001 par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE

List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security holders for fiscal year ended December 24, 1980).

Table of Contents

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

	•	business strategy;
	•	identified drilling locations;
	•	exploration and development drilling prospects, inventories, projects and programs;
	•	natural gas and oil reserves;
	•	ability to obtain permits and governmental approvals;
	•	technology;
	•	financial strategy;
	•	realized oil and natural gas prices;
	•	production;
	•	lease operating expenses, general and administrative costs and finding and development costs;
	•	future operating results; and
	•	plans, objectives, expectations and intentions.

     All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in “Items 1 and 2. Business and Properties”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, including the “Risk Factors” subsection, and other sections of this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target” or “continue”, the negative of such terms or other comparable terminology.

     The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all

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readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Factors” section and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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PART I

Items 1 and 2. Business and Properties

BUSINESS

General

     Bill Barrett Corporation (the “Company”, “we” or “us”) was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. We have exploration and development projects in nine basins. Our management has an extensive track record with expertise in the full spectrum of Rocky Mountain plays. Our strategy is to maximize stockholder value by leveraging our management team’s experience finding and developing oil and gas in the Rocky Mountain region to profitably grow our reserves and production, primarily through the drill-bit.

     The following table provides information regarding our operations by basin.

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Key Basins of Activity

     We operate in nine basins, the Piceance, the Wind River, the Uinta, the Powder River, the Williston, the Green River, the Denver-Julesburg, the Paradox and the Big Horn.

     Piceance Basin. The Piceance Basin is located in northwestern Colorado and represents a new focus area for our development activities and expected production growth in 2005. We acquired developed and undeveloped properties in September 2004.

     Wind River Basin. The Wind River Basin is located in central Wyoming and, for the year ended December 31, 2004, was our largest producing area. Our operations in the basin include active infill and field expansion development programs, as well as eight exploration projects that make this basin an important exploratory area. Our development operations are conducted in three general project areas.

     Uinta Basin. The Uinta Basin is located in northeastern Utah and represents a substantial part of our development and exploration activities and expected production growth in 2005. Our development operations are conducted primarily in two areas. We also have a position in four exploratory projects in the basin.

     Powder River Basin. The Powder River Basin is located in northeastern Wyoming. Substantially all of our operations in this basin are in coalbed methane plays targeting

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the Wyodak and Big George coals. Our coalbed methane activities have resulted in high drilling success and lower drilling costs than our other drilling programs; however, the average coalbed methane well in the Powder River Basin produces at a much lower rate with fewer reserves attributed to it than conventional natural gas wells in the Rockies. Our development operations are conducted in seven project areas in the basin. Many of our leases in the Wyodak coalbed methane area in this basin are in areas that have been partially depleted or drained by earlier offset drilling.

     Williston Basin. The Williston Basin is located in western North Dakota, northwestern South Dakota and eastern Montana. It is a predominantly oil prone basin and represents our only oil focused project area. Our activities in this basin include development and exploration drilling programs concentrated in two areas. We use horizontal drilling technology and 3-D seismic surveys in the Williston to expand existing fields, target exploration projects and increase our recoveries.

     Green River Basin. The Green River Basin is located in southwestern Wyoming and adjacent areas of northeastern Utah. In 2004, we acquired leasehold interests in an exploration project in the basin and our industry partner commenced drilling an exploration well in February 2005.

     Denver-Julesburg Basin. Our operations in the DJ Basin are concentrated in the Tri-State exploration project, which extends into Colorado, Kansas and Nebraska. These operations are exploratory and involve the extensive use of 3-D seismic technology to target shallow biogenic gas and deeper conventional oil accumulations.

     Paradox Basin. The Paradox Basin is located in southwestern Colorado and southeastern Utah. We are in the initial stages of two exploration projects in the basin focusing on natural gas.

     Big Horn Basin. The Big Horn Basin is located in north central Wyoming. We are in the initial phases of an exploration project targeting both structural-stratigraphic and basin-centered tight gas plays.

Our Strategy

     The principal elements of our strategy to maximize stockholder value are to:

	•	Drive Growth Through the Drill-bit. We expect to generate long-term reserve and production growth predominantly through our drilling activities. We believe our management team’s experience and expertise enable us to identify, evaluate and develop new natural gas and oil reservoirs. Throughout our operations, we apply technology, including advanced drilling and completion techniques and new geologic and seismic applications. From inception through December 31, 2004, we participated in the drilling of 474 gross wells. We plan to participate in the drilling of a total of 369 gross wells in 2005.
	•	Pursue High Potential Projects. We have assembled several projects that we believe provide future long-term drilling inventories. In addition to nine key development areas, as of March 1, 2005 we are involved in 24 exploration projects. Our team of 17 geologists and geophysicists, which includes our Chief Executive Officer, is dedicated to generating new geologic concepts. These

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individuals have an average of more than 23 years of experience in the industry, primarily in the Rocky Mountain region. Our long-term objective is to allocate between 70% and 80% of our capital budget to development projects, with the balance allocated to higher risk, higher potential exploration projects.

	•	Focus on Natural Gas in the Rocky Mountain Region. We intend to capitalize on the large estimated undeveloped natural gas resource base in the Rocky Mountains, while selectively pursuing attractive oil opportunities in the region. We believe the Rockies represent one of the few natural gas provinces in North America with significant remaining development potential. All of our production is from the Rockies, and for the month of December 2004, approximately 92% was natural gas.
	•	Reduce Costs and Maximize Operational Control. Our objective is to generate profitable growth and high returns for our stockholders. We expect that our unit cost structure will benefit from economies of scale as we grow, maintaining high operatorship of our reserves and production, and our continuing cost management initiatives. As we manage our growth, we are actively focusing on managing lease operating expenses, general and administrative costs and finding and development costs. It is strategically important to us to serve as operator of our properties when possible, as that allows us to exert greater control over costs and timing in our exploration, development and production activities. We operated approximately 87% of our December 2004 production and, as of December 31, 2004, we owned an average working interest of approximately 67% in 1,451,516 gross undeveloped acres, as well as an additional 161,750 net undeveloped acres that are subject to drill-to-earn agreements. Subsequent to December 31, 2004, we entered into a joint exploration agreement and sold our industry partner a 50% interest in approximately 346,000 net undeveloped leasehold acres in the Tri-State prospect area.
	•	Pursue Reserve and Leasehold Acquisitions. Past acquisitions have played an important part in establishing our asset base. We intend to use our experience and regional expertise to supplement our drill-bit growth strategy with complementary acquisitions that have the potential to provide long-term drilling inventories or that have undeveloped leasehold positions. We actively review acquisition opportunities on an ongoing basis.

Competitive Strengths

     We have a number of strengths that we believe will help us successfully execute our strategy.

•

Experienced Management Team. Although we compete against companies with more financial and human resources than ours, we believe our management team’s experience and expertise in the Rocky Mountains provide a distinct competitive advantage. Our 13 corporate officers average 26 years of experience working in and servicing the industry. Our Chief Executive Officer and other members of our management team worked together as executives or advisors for many years with Barrett Resources Corporation, a publicly-traded Rocky Mountain oil and gas company that was founded in 1980 and sold in 2001 in a transaction valued at approximately $2.8 billion. Further, members of our team are widely

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acknowledged as leading explorationists and were involved in finding or developing several of the largest Rocky Mountain natural gas and oil fields during the last three decades, including the Grand Valley, Parachute, and Rulison fields in the Piceance Basin, the Powder River Basin coalbed methane play, the Hilight field, the Cave Gulch field and the Madden field.

	•	Inventory of Growth Opportunities. We have established an asset base of 971,086 net undeveloped leasehold acres as of December 31, 2004, as well as an additional 161,750 net undeveloped acres that are subject to drill-to-earn agreements. From inception through December 31, 2004, we participated in the drilling of 474 gross wells. In 2005, we plan to participate in the drilling of 369 gross wells across our operations. In addition, as of March 1, 2005, we have 24 exploration projects.
	•	Rocky Mountain Asset Base. In January 2004, the Department of Energy estimated that Rocky Mountain natural gas production would grow by 91% from 2002 to 2025, compared to other large U.S. gas producing areas, which were forecast to decline or grow at significantly lower rates over the same period. Our assets are focused in the natural gas prone basins of the Rockies. This asset base allows us to leverage our experience and expertise as we pursue our growth strategy. Although we are focused in the Rockies, we are active in nine distinct basins in the region, which provide both geographic and geologic diversification.
	•	Financial Flexibility. As of December 31, 2004, we had $100 million in cash with no debt outstanding and $200 million available under our revolving credit facility. We are committed to maintaining a conservative financial position to preserve our financial flexibility. Based on our current budget, we believe that our operating cash flow and available borrowing capacity under our credit facility provide us with the financial flexibility to pursue our planned exploration and development activities and leasehold acquisitions in 2005.
	•	Significant Employee Investment. All of our corporate officers and employees own our stock or stock options. As a result, our management team and other employees have interests that are aligned with those of our stockholders.

Risks Related to Our Business and Strategy

     The following considerations could have a negative effect on our strategy as well as activities on our properties and what we believe to be our competitive strengths to execute our strategy and activities:

	•	Limited Operating History. We are a relatively new company. As such, we have made major expenditures to acquire and develop our property base and substantially increase production. This resulted in significant losses in certain periods since our inception. We can give no assurance that we will not incur losses in the future.
	•	Risks Relating to Oil and Gas Reserves. Reserve estimates are based on many assumptions and our properties may not produce as we originally forecast. For example, we reduced our reserves by approximately 32 Bcfe in 2004 as a result of infill drilling in depleted sands in the Wind River Basin and greater pressure

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depletion than expected in two areas in the Wyodak coals in the Power River Basin. In addition, our reserve report reflects that, as we produce our proved reserves, they would decline at an estimated rate of 7.2% per year after 2005, which will only be abated if we are successful in finding or acquiring new reserves.

	•	Concentration and Competition. Our concentration in the Rocky Mountains may make us disproportionately exposed to impacts of weather, government regulation and transportation constraints common to that geographic location. Competition with other companies in the Rockies is significant and may hinder our ability to pursue reserve and leasehold acquisitions as well as our ability to operate in certain of our core areas.
	•	Risks Related to Rapid Growth. We have grown rapidly through acquisitions and may engage in additional acquisitions in the future. Acquired properties may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

     For a discussion of other considerations that could have a negative effect on our strategy and what we believe to be our competitive strengths to execute our strategy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Risk Factors” and "—Cautionary Note Regarding Forward-Looking Statements”.

Summary of Development Areas

     The following table summarizes the information regarding our key development areas as of December 31, 2004 that is discussed in more detail below:

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Joint Exploration Strategy and
Summary of Exploration Projects

          Joint Exploration Strategy

          We are seeking industry partners to enter into joint exploration agreements, which will involve the sale of portions of our interests in several of our exploration projects to industry partners, and joint drilling obligations for these projects. The primary objective of this effort is to increase our exposure to potential reserves and production, while recouping a portion of our initial investment through the sale of a portion of our interests. In connection with these anticipated joint exploration agreements, we expect to sell approximately 30% to 60% of our working interests, depending on the project. We plan to use the proceeds from these arrangements to increase exploration activities beyond those contemplated in our current and capital expenditure budget.

          Summary of Exploration Projects

     The following table summarizes our exploration projects that are discussed in more detail below.

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Piceance Basin

     The Piceance Basin is located in northwestern Colorado. We entered the Piceance Basin on September 1, 2004, when we purchased producing and undeveloped properties from Calpine Corporation and Calpine Natural Gas L.P., which included 25,985 gross and 19,180 net acres in and around Gibson Gulch field, for approximately $137 million.

     Our total leasehold position in the Piceance Basin as of December 31, 2004 consisted of 12,812 gross and 10,031 net undeveloped acres and 9,289 gross and 7,156 net developed acres, all of which is in our Gibson Gulch area. Our estimated net proved reserves in the Piceance Basin at year end 2004 were 88.7 Bcfe. Our planned activities will be in the southeastern portion of this basin. Several members of our senior management team were involved with the discovery, exploration and development of three large gas fields, Grand Valley, Parachute and Rulison, located in the south central part of the Piceance Basin. These fields lie along a continuous 30 mile productive trend of basin-centered gas trapped in the tight sandstones of the Mesaverde Group. Industry participants along this trend, which in addition to Grand Valley, Parachute and Rulison include Mamm Creek and our Gibson Gulch field, have been actively conducting development drilling programs on 10- and 20-acre patterns. We received authority for development on a 10-acre pattern and are evaluating development on this basis. Our natural gas production in this basin currently is gathered through our own gathering system and delivered to markets through pipelines owned by Questar Pipeline Company.

Gibson Gulch

     The Gibson Gulch area is a basin-centered gas play along the north side of the Divide Creek anticline at the eastern end of the Piceance Basin’s productive Mesaverde trend. Our properties are largely undeveloped relative to those fields to the west and southwest. Currently, our primary focus at Gibson Gulch is a Mesaverde development drilling program with well depths between 7,000 and 8,000 feet. In our initial wells, we plan to drill to 8,500 feet to test the potential of the deeper more continuous Cozzette and Corcoran sandstones, which are productive at the nearby Divide Creek field. We also plan to test the potential of completing the shallower Wasatch formation in selected wellbores.

     Our estimated net proved reserves in this basin were 88.7 Bcfe at December 31, 2004. At December 31, 2004, we held interests in 93 gross producing wells that produced 6.0 MMcfe/d net to our interest in the month of December 2004 with an average working interest of 72%. At December 31, 2004, our total leasehold position in Gibson Gulch consisted of 12,812 gross and 10,031 net undeveloped acres and 9,289 gross and 7,156 net developed acres. Initially, our drilling program is focused on the undeveloped acreage comprised of fee leaseholds, which should provide broader drilling windows and fewer regulatory challenges than typically encountered with a federal leasehold. We believe that additional locations may be present on our acreage position as we investigate the feasibility of 10-acre well density for which we have received approval. Currently, we estimate our capital expenditures for 2005 will be $120 million to

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participate in the drilling of 95 wells and the recompletion of 12 wells in the Gibson Gulch area. In the period from when we acquired these properties on September 1, 2004 through December 31, 2004, our capital expenditures in this area were $151.8 million and included our acquisition of the properties as well as participating in drilling six wells and three recompletions.

Wind River Basin

     The Wind River Basin is located in central Wyoming. Our activities in the area are concentrated primarily in the eastern Wind River Basin. Our Wind River Basin development operations are conducted in three general project areas located along the greater Waltman Arch area: Cave Gulch, Cooper Reservoir and Wallace Creek. In addition, we have eight exploration projects, of which Pommard, Windjammer and East Madden are in areas of the basin where we have no existing development operations. We are attempting to sell down a portion of our interests in the Wind River Basin to industry partners.

     Our total leasehold position in the Wind River Basin as of December 31, 2004 consisted of 388,172 gross and 165,946 net undeveloped acres and 7,251 gross and 5,936 developed acres. Our estimated net proved reserves in the Wind River Basin at year end 2004 were 82.8 Bcfe. Our current operations in the basin include active infill and field expansion development programs, as well as exploration activities. We have access to over 450 square miles of 3-D seismic in seven different surveys covering the Cave Gulch, Cooper Reservoir, Wallace Creek, Stone Cabin and East Madden project areas, and 3,700 miles of 2-D seismic across a majority of the eastern Wind River Basin. Our natural gas production in this basin is gathered through our own gathering systems and delivered to markets through pipelines owned by Kinder Morgan Interstate and Colorado Interstate Gas Company (“CIG”).

Cave Gulch

     The Cave Gulch field is a structural-stratigraphic play along the Owl Creek Thrust at the northern end of the Waltman Arch. Our primary focus is a 20-acre development program involving drilling and recompletions in discontinuous lenticular sands at depths from approximately 4,900 to 9,200 feet in the Lance formation. We also are producing from wells in two other zones: the Fort Union, from 3,500 to 4,900 feet, and the overpressured deep Frontier and Muddy formations, from 16,700 to 19,000 feet.

     Our estimated net proved reserves in the Cave Gulch field were 46.7 Bcfe at year end 2004. Also at December 31, 2004, we had interests in 72 gross producing wells, and net production for the month of December 2004 was 22.3 MMcfe/d with an average working interest of 89%. We operated 99% of our December 2004 production in the area. At December 31, 2004, our total leasehold position in Cave Gulch consisted of 16,292 gross and 12,402 net undeveloped acres and 2,011 gross and 1,649 net developed acres. Currently, we estimate our capital expenditures for 2005 will be $18 million in Cave Gulch, which includes nine gross Lance wells and one recompletion. In 2004, our capital program in this area was approximately $17 million and included successfully drilling and completing ten Lance wells. In the third quarter of 2004, we identified one extension well as a dry hole.

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Cooper Reservoir

     Our position in the Cooper Reservoir field lies six miles south of Cave Gulch along the Waltman Arch. As at Cave Gulch, our targets at Cooper are the Lance and Fort Union formations at depths ranging from 3,200 to 8,500 feet. Currently, our primary focus is 20-acre development of the Lance and Fort Union formations within the Cooper Reservoir unit, and 40-acre Lance development on field extensions north and south of this unit. We are using 3-D seismic technology across the Cooper Reservoir area region to evaluate other opportunities.

     Our estimated net proved reserves in Cooper Reservoir were 22.7 Bcfe at year end 2004. Also at December 31, 2004, we had interests in 72 gross producing wells, and net production for the month of December 2004 was 12.3 MMcfe/d with an average working interest of 98.5%. We operated all of our December 2004 production in the area. At December 31, 2004, our total leasehold position in Cooper Reservoir consisted of 12,992 gross and 9,676 net undeveloped acres and 2,882 gross and 2,759 net developed acres. Currently, we estimate our capital expenditures for 2005 will be $16 million in Cooper Reservoir, which includes nine gross Lance/Fort Union wells, one Lance/Fort Union recompletion, and gas gathering and water disposal facilities. In 2004, we drilled 29 Lance/Fort Union wells as part of our 2004 capital program of $36 million. 19 of those wells are producing, and two extension wells were classified as dry holes.

Wallace Creek, Stone Cabin and Pommard

     Our estimated net proved reserves in Wallace Creek, Stone Cabin and Pommard were 13.3 Bcfe at year end 2004. At December 31, 2004, we had a 100% working interest in 15 producing wells and net production for the month of December 2004 was 6.2 MMcfe/d, all of which we operated. Currently, we estimate our capital expenditures for 2005 will be $2.6 million. In 2004, our capital program in this area was approximately $28.5 million and included eight wells.

     In 2004, four Raderville wells were drilled with no commercial production from that formation. One of these wells, the Stone Cabin 44-16, was recompleted and, as of March 1, 2005, was producing from the Lewis formation, and the other three wells, the Stone Cabin 11-27R, Stone Cabin 33-21R and Stone Cabin 33-16R, were determined to be dry holes. Through December 2004, three additional Stone Cabin wells, consisting of one development and two exploratory wells, were drilled and determined to be dry holes. In September 2004, we finished drilling and ran production casing at a depth of 14,976 feet on the Pommard #1. We are continuing to test the Tensleep formation, but, based on results to date, the well was determined to be a dry hole with total estimated costs of $9.0 million, including $7.9 million through December 31, 2004. We also may evaluate several other uphole formations.

     Our total leasehold position in Wallace Creek, Stone Cabin and Pommard consists of 38,999 gross and 32,844 net undeveloped acres and 1,758 gross and 1,389 net developed acres, with an average working interest of 84% at December 31, 2004.

     We also recognize a potential coalbed methane play in the Wallace Creek area. We currently are assessing the multiple coal beds of the Meeteetse formation which underlies the Lance formation in a 1,500 to 4,500 feet depth range.

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Windjammer

     Our Windjammer exploratory area lies to the northwest of our Wallace Creek development project. We are evaluating the same Raderville formation in Windjammer that we currently are developing at Wallace Creek. Based on 3-D amplitude mapping, subsurface and well control data, we believe the Raderville trend extends from Wallace Creek to the northwest into the Windjammer area. In late 2004, we conducted a 114 square mile 3-D survey across the Windjammer area and are currently processing this survey. We held 8,745 net undeveloped leasehold acres for exploration in this area as of December 31, 2004.

Talon and East Madden

     In our Talon and East Madden areas, we are targeting an unconventional, basin-centered play concept in the Lance and Fort Union formations. Currently, we estimate our capital expenditures for 2005 will be $15 million to purchase leases, acquire 3-D seismic, drill one Lance exploratory well, and drill five shallow Fort Union wells. In 2004, our capital program in this area was approximately $15 million and included five Fort Union wells, one East Madden and three recompletions. We have assembled 262,061 gross and 93,240 net leasehold acres in the Talon and East Madden areas as of December 31, 2004.

     Talon. The Talon exploratory project lies due west of the Cave Gulch area and extends over a multi-township area. We are targeting a basin-centered Lance and Fort Union play in the project. To date, five Lance wells and three Fort Union wells have been drilled and three Fort Union recompletions have been performed. As of March 11, 2005, all six wells were producing down the sales line, four were being tested and one recompletion was temporarily abandoned. We have begun building infrastructure to accommodate a development program. Our first production was in May 2004 and, in December 2004, we produced a net 0.1 MMcfe/d with an average working interest of 56%.

     At December 31, 2004, the first well drilled in the Talon area was producing but had evaluated costs that exceeded its estimated fair value, resulting in an impairment expense of $0.5 million for 2004. Prior to year end 2004, this well was completed in the Lance formation and connected to the sales line. Subsequent to year end 2004, this well was completed in a zone further uphole in the Fort Union and connected to the sales line. We believe there are additional zones in the Fort Union that we may complete at a later date.

     East Madden. Our East Madden exploration prospect lies east of the extensive Madden field along the Madden anticline. Our concept for East Madden, similar to that in the Talon region, is to explore the overpressured Lance formation. The Lance formation ranges from approximately 11,000 to 16,500 feet in depth in this area. As of March 11, 2005, we had reached total depth and were waiting on completion on our 16,600 foot Lance test well, for which we are operator for an industry partner pursuant to a farm-out agreement. We will retain a 25% working interest before payout and a 45% working interest after payout in this well. If the industry partner elects to drill a second option well, we will farmout an additional one-sixth (16.67%) interest, so that our eventual interest in the prospect will be 37.5%. If the industry partner drilled both the test well and option well, it will have earned 10,207 net acres out of our total net acreage

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inventory of 22,266. Depending on our exploratory results in the East Madden play, we may identify locations in the Lance formation to develop across portions of our acreage on an 80-acre pattern.

Uinta Basin

     We have a substantial acreage position in the Uinta Basin, including 134,036 gross and 96,672 net undeveloped and 6,118 gross and 5,811 net developed leasehold acres at December 31, 2004. Our estimated net proved reserves in the Uinta Basin were 49.3 Bcfe at year end 2004. Our exploration and development activities are focused on two geologic play types (structural-stratigraphic and basin-centered gas) in several locations.

West Tavaputs

     We began operations in the Uinta Basin in April 2002 at the northwestern end of the Garmesa Trend through the acquisition of 3.4 Bcfe of proved reserves and 46,702 gross and 42,355 net leasehold acres at West Tavaputs. We have a 100% working interest in the majority of this field. Although the field was discovered in 1952, there had been only limited activity at West Tavaputs over the last 20 years. In particular, no modern completion techniques or 3-D seismic technology had been applied to this field. Since we began operations here in 2002, we have drilled 17 wells, eight of which are producing, seven are awaiting completion, and one of which is awaiting further testing. With effective application of new fracturing techniques and new geologic interpretations, we have greatly enhanced our ability to commercialize the gas potential of this area. As of March 1, 2005, we were seeing increased production from the Wasatch and the deeper Mesaverde formations.

     Our estimated net proved reserves in West Tavaputs were 40.3 Bcfe at year end 2004. As of December 31, 2004, we had interests in a total of 20 wells in this area that were capable of production. Because of limitations in infrastructure, five of those wells were shut-in. The remaining 15 wells, in which we had a 100% working interest, produced 7.7 net MMcfe/d in December 2004. We operated all of our December 2004 production in West Tavaputs. We plan additional infrastructure improvements in 2005 to relieve the constraint issues. Our natural gas production at West Tavaputs is gathered and compressed by our facilities and delivered to markets on the Questar pipeline system.

     Our total leasehold position in West Tavaputs consists of 41,560 gross and 37,853 net undeveloped acres and 5,318 gross and net developed acres as of December 31, 2004. Full development of the West Tavaputs area is anticipated to require the completion of an EIS, which will be initiated as soon as appropriate. Currently, we estimate our capital expenditures in 2005 will be $52 million in the West Tavaputs area to fund our interests in 17 additional gross Wasatch-Mesaverde wells to depths ranging between 7,500 to 9,200 feet, four recompletions, and gathering and compression facilities. We recently completed an 83 square mile 3-D seismic survey covering the field area where existing but limited 2-D seismic coverage is inadequate to image the subsurface. On November 10, 2004, the BLM’s winter stipulations, which limit our activities, went into effect. As a result, we were not able to complete four of the eight wells drilled in 2004. We will commence completion operations on these four wells in the spring of 2005 when restrictions are lifted.

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Garmesa

     The Garmesa prospect lies southeast of West Tavaputs and consists of three adjacent prospects areas: Hill Creek, Tumbleweed and Cedar Camp. We believe these prospects have similar geologic characteristics and reserve potential, but are differentiated mainly by our level of working interest, industry partners and ownership structures. Currently, we estimate capital expenditures for 2005 will be $3.7 million in Garmesa to conduct a 3-D seismic survey, drill three wells, and further develop related infrastructure. In 2004, our capital program in this area was approximately $10.7 million and included two wells, infrastructure expenses, the acquisition of a 16 square mile 3-D seismic survey and regulatory expenditures

     Hill Creek. Within the Hill Creek area, we target the Dakota, Entrada and Wingate formations at depths down to 11,900 feet. In 2004, we drilled the tenth well in this area, which was the final well required under our exploration agreement with an industry partner.

     Our estimated net proved reserves at Hill Creek were 9.1 Bcfe at year end 2004. Our ten gross producing wells in the area produced 9.2 MMcfe/d net to our interest in December 2004, with an average net revenue interest of 72%. Our natural gas production in Hill Creek is sold at the wellhead. Our total leasehold position in Hill Creek consists of 1,508 gross and 754 net undeveloped acres and 800 gross and 493 net developed acres.

     Pursuant to an exploration agreement with an industry partner, we earned a net revenue interest in the 10 wells drilled in the Hill Creek area and the drillsite spacing unit pertaining to each well. We have the right to participate for a 50% working interest in the next nine wells proposed in the Hill Creek area by our industry partner.

     Tumbleweed. Our Tumbleweed project area is located directly southeast along the Garmesa Trend and adjacent to Hill Creek. As of December 31, 2004, we held a leasehold position of 7,833 gross and 2,877 net undeveloped acres, with an average working interest of 37%. We operate this prospect and are targeting the same reservoir objectives as the Hill Creek project. In order to fulfill our federal unit obligations and preserve our acreage position, we and our partners drilled a 5,785 foot exploration well in June 2003. The well was a dry hole and was too shallow to evaluate the reservoirs that are productive in the Hill Creek area. We commissioned a 21-square mile 3-D seismic survey in 2005 in order to evaluate the potential to develop this area. We are planning an 11,000-foot test well for the third quarter of 2005.

     Cedar Camp. Our Cedar Camp project area is located directly southeast along the Garmesa Trend from the Tumbleweed area. As of December 31, 2004, we held a leasehold position of 9,197 gross and 4,093 net undeveloped acres, with an average working interest of 45%. We operate this prospect and are targeting the same reservoir objectives as the Hill Creek and Tumbleweed projects. In 2004, we commissioned a 16-square mile 3-D seismic survey in order to evaluate the potential to develop this area. The survey was completed in November 2004 and, as of March 11, 2005, was still being interpreted. We are planning two 10,500-foot test wells beginning in the first half of 2005.

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Lake Canyon/Brundage Canyon

     Lake Canyon. Lake Canyon is an exploration project that targets basin-centered tight gas in the Mesaverde formation at depths ranging from approximately 10,000 to 14,000 feet. We believe Lake Canyon has a structural position similar to the Natural Buttes field in which other operators have been developing Mesaverde and Wasatch reservoirs. As of December 31, 2004, we had assembled over 33,470 net acres in this play. Currently, we estimate our capital expenditures for 2005 will be $10.1 million for acreage acquisition and to drill three exploratory wells. In 2004, our capital program in this area was approximately $2.9 million and included lease bonus payments and costs associated with the drilling of the initial well at Brundage Canyon.

     In July 2004, we and an industry partner entered into an exploration and development agreement with the Ute Indian Tribe of the Uintah and Ouray Reservation, or the Ute Tribe, to explore for and develop oil and natural gas on approximately 125,000 of their net undeveloped acres that are located in Duchesne and Wasatch Counties, Utah. This drill-to-earn agreement was revised in September 2004 to include the Ute Development Corporation as a party and was approved by the Department of Interior’s Bureau of Indian Affairs, or BIA, in October 2004. Pursuant to this agreement, we have the right to earn up to a 75% working interest in the Mesaverde formation and deeper horizons, plus up to a 25% interest in shallower formations. To earn these interests pursuant to this agreement, we and our partner are required to drill 13 deep wells and 21 shallow wells prior to December 31, 2009, including one deep and two shallow wells by December 31, 2005. The Ute Tribe has an option to participate for a 25% working interest in wells drilled pursuant to the agreement. This right terminates as to all future wells in a lease block if the Ute Tribe does not elect to participate in one of the first two wells in that lease block. We will drill and operate the deep wells and our industry partner will drill and operate the shallow wells. If we fail to drill the 2005 well commitments, we are required to pay the Ute Indian Tribe $1.775 million, which is our share of the 2005 drilling obligations, and our rights to earn interests in additional acreage would terminate. Our initial exploration well in Lake Canyon is scheduled for the fourth quarter of 2005 following acquisition and evaluation of a 50 to 60 square mile 3-D seismic survey.

     Brundage Canyon. In September 2004, we entered into a farm-out agreement with the same industry partner as with our Lake Canyon prospect pursuant to which we had the right to earn a 75% working interest in the deep Mesaverde formation and deeper horizons on existing exploration and development agreements that encompass 49,000 acres within the Brundage Canyon Field by drilling a deep exploratory test well. This field is located on the Ute Tribe’s lands and is situated adjacent to and just east of the acreage in the Lake Canyon prospect covered by our agreement with the Ute Tribe. We commenced the drilling of our initial deep exploratory well in Brundage Canyon in November 2004 and abandoned it in January 2005, pending the further evaluation of a 3-D seismic survey and assessment of the optimal completion technology for the tight gas sandstone encountered by the well.

Hook

     In 2004, we acquired 11,465 gross and 11,353 net acres in an exploration play that targets natural gas at depths of 1,000 feet to 4,500 feet. We plan to continue to acquire leasehold acreage through 2005.

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Powder River Basin

     The Powder River Basin is primarily located in northeastern Wyoming. The basin contains the Rockies’ most active drilling area: the Wyodak and Big George coalbed methane plays. As of December 31, 2004, we held approximately 24,180 gross and 16,767 net developed leasehold acres and 96,717 gross and 59,587 net undeveloped leasehold acres in the Powder River Basin. Our estimated net proved reserves in the basin at year end 2004 were 40.4 Bcfe. In December 2004, we produced a net 21.0 MMcfe/d. We are focused on continuing to build and consolidate our acreage position in the Powder River Basin. Our development and exploration activities are concentrated in seven major projects in two regional focus areas: the Southern CBM and Central CBM. We also have operations in a number of smaller producing properties located in the eastern half of the basin, which we refer to collectively as the Developed Area.

     Our key project areas are located in both the Big George and Wyodak fairways. We have strategically targeted areas that we believe have higher gas reserve potential and that are proximate to infrastructure. This infrastructure, in areas such as Cat Creek, Willow Creek, and Deadhorse, exists as a result of pre-existing conventional well development. Currently, we estimate our capital expenditures for 2005 will be $20.0 million, which includes participating in 219 wells, of which 39 are PUD locations, and leasehold acquisitions. As of March 11, 2005, we had all necessary drilling permits and environmental approvals in place for 103 locations of the 219 wells that are planned to be drilled in 2005. If we do not receive additional permits for the planned wells, we plan to drill other locations for which we have the necessary approvals.

     Coalbed methane wells typically first produce water in a process called dewatering. This process lowers pressure, allowing the gas to detach from the coal and flow to the well bore. As the reservoir pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a coal bed well is approximately seven years. The average coal bed well in the Powder River Basin produces at a much lower rate with fewer reserves attributed to it than conventional natural gas wells in the Rockies.

     We have dedicated significant resources to managing regulatory and permitting matters in the Powder River Basin to achieve efficient processing of federal permits and resource management plans.

     About 72% of our acreage in the Powder River Basin is U.S. federal land and therefore subject to the National Environmental Policy Act (“NEPA”) and certain state regulations, which require governmental agencies to evaluate the potential environmental impacts of a proposed project on government owned lands and minerals. The NEPA process imposes obligations on the federal government that may result in legal challenges and potentially lengthy delays in obtaining project permits or approvals. We have submitted six Federal Plans of Development (“PODs”) to the BLM and United States Forest Service (“USFS”) involving 470 wells. We received approval for all six of these Federal PODs, one for BLM lands in the Porcupine area for 29 wells, one for 143 wells for USFS lands in the Porcupine area, one for 36 federal wells in the Tuit project area, one for 71 wells in the Palm Tree area, one for 64 wells in the Cat Creek area, and one for 127 wells in the Deadhorse area. An application for 102 wells in Coconut Grove area that was submitted in February 2005 is pending.

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Southern CBM

     Tuit. The Tuit project area is located near the southern end of the Wyodak coal fairway. We believe the average thickness of the Wyodak coals across our acreage is approximately 80 feet at an average depth of 855 feet. As of December 31, 2004, we participated in drilling 74 gross wells in the Tuit area. We are the operator in this area.

     As of December 31, 2004, our leasehold position in Tuit consisted of 2,185 gross and 1,602 net undeveloped acres, with an average working interest of 73%. Currently, we have a five gross well drilling program planned for 2005. Our natural gas production in Tuit is gathered by facilities owned by Western Gas Resources Inc. and sold to various parties.

     Porcupine. The Porcupine project area is located southeast of Tuit on the far southern end of the Wyodak fairway. Similar to Tuit, we believe the average thickness of the Wyodak coals in this area is approximately 80 feet at an average depth of 425 feet. As of December 31, 2004, we participated in drilling 108 gross wells in the area. We are the operator in this area.

     Our leasehold position in Porcupine consists of 9,565 gross and 8,194 net undeveloped acres, with an average working interest of 86% at December 31, 2004. Currently, we have an six gross well drilling program planned for 2005 in Porcupine on a combination of fee, state and federal acreage. Our natural gas production in Porcupine is gathered by facilities owned by Western Gas Resources Inc. and sold to various parties.

     Palm Tree. The Palm Tree project area is located at the far southeast end of the Big George fairway and we believe overlies the highest structural position in the basin for the Big George. We believe the average thickness of the Big George coals is approximately 60 feet at an average depth of 835 feet. The Thunder Creek pipeline runs through our acreage position. Our natural gas production is gathered by facilities owned by Western Gas Resources Inc., and transported by Thunder Creek Gas Services, LLC.

     We have drilled 117 gross wells in Palm Tree through December 31, 2004 and have connected 96 of these wells through December 31, 2004. Of these wells, 82 were drilled in 2004. Our leasehold position consists of 17,919 gross and 14,066 net undeveloped acres, with an average working interest of 78% at December 31, 2004. Currently, we have a 102 gross well drilling program planned for 2005.

Central CBM

     Cat Creek. Cat Creek is a relatively low risk exploratory prospect area that lies on the western edge of the Big George fairway. We have drilled nine wells through December 31, 2004 on the 6,195 gross and 3,054 net acres we have under lease in the prospect area with an average working interest of 49% at December 31, 2004. We believe the average thickness of the Big George coal is approximately 90 feet at an average depth of 1,825 feet. There are three Big George pilot projects owned and operated by third parties with established production that range between four and eight miles from the prospect area. The Cat Creek area has existing road and power

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infrastructure due to historical conventional oil development, which should enhance our ability to keep operating costs low. In addition, the Thunder Creek gathering line runs directly through the area. We have a 58 gross well drilling program planned for 2005. We are the operator in this area.

     Willow Creek. Willow Creek is a relatively low risk exploratory prospect area that is 12 miles south of the Cat Creek prospect area on the western edge of the Big George fairway. We have yet to drill any wells on the 15,403 gross and 6,509 net acres we have under lease in the Willow Creek prospect area with an average working interest of 42% at December 31, 2004. We believe the average thickness of the Big George coals is approximately 85 feet at an average depth of 1,420 feet. The Big George wells in the Kingsbury Federal Unit, which lies mid-way between Cat Creek and Willow Creek, have been producing gas for third parties. We will operate a majority of our wells in Willow Creek.

     Deadhorse. The Deadhorse project area is located in an area where we believe the Big George coals and a lower split of the Wyodak coals are apparent, giving each location two coal targets. We intend to exploit cost savings on shared surface facilities and increased development efficiencies in this area. Our average working interest is 73% across 14,839 gross and 10,897 net acres in this prospect. We believe the average thickness of the Big George coal is approximately 80 feet at an average depth of 1,220 feet. We believe the Lower Wyodak coal has an average thickness of approximately 55 feet at an average depth of approximately 1,550 feet. In 2004, we drilled a five well test program to collect core and reservoir data and, as of March 11, 2005, we were analyzing the results. We intend to test the viability of a multi-seam completion in which the Big George and Lower Wyodak coals will be completed in a single well bore. We are the operator in this area.

     Amos Draw. Like the Deadhorse prospect area, Amos Draw is located in an area with multiple coal targets. As of December 31, 2004, our average working interest is 36% across 4,858 gross and 1,756 net undeveloped acres. The primary target in the area is the Lower Wyodak coal, which we believe has an average thickness of 90 feet and average depth of 1,900 feet. On the western flank of the project area, both the Big George and Werner coals are viable targets. We have entered into an area of mutual interest, or AMI, agreement with several other operators in this area. There is a third party 16 to 20 well pilot project that was dewatering as of March 11, 2005 in all three potential formations immediately adjacent to the AMI. As of December 31, 2004, we participated in the drilling of nine Lower Wyodak wells, which are expected to be connected and begin dewatering this year. We are not the operator in this area.

Developed Area

     In addition to our development and exploration activities in the Southern and Central CBM, we own interests in a number of smaller producing properties, which we refer to collectively as the Developed Area. Most of these properties were acquired as a part of a development oriented acquisition. They are generally located in the eastern half of the Powder River Basin and include Little Buffalo Ranch, Goer, Pronghorn, South Coal Gulch, Terra and Kitty. As of December 31, 2004, we had interests in 224 gross and 104 net producing wells in this area, which included 177 gross and 95 net CBM wells and 47 gross and 14 net conventional wells. Our estimated net proved reserves in the Developed Area were 1.6 Bcfe at December 31, 2004.

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Williston Basin

     The Williston Basin is located in western North Dakota, northwestern South Dakota and eastern Montana. It is a predominantly oil prone basin and produces oil and natural gas from 11 major geologic horizons that range in depth from approximately 1,000 to over 14,000 feet.

     While we have interests in a substantial number of wells in the Williston Basin, which target several different zones, our exploration and development activities currently are concentrated on three of the producing formations, the Madison, Bakken and the Red River. The application of horizontal completions in these formations has yielded significant improvement in the recovery of hydrocarbons from reservoirs compared to vertically drilled well completions in the same type of formations. The basin has established infrastructure and access to materials and services. Regulatory delays are less prevalent than other areas due to fee ownership of properties, more efficient state and local regulatory bodies and more reasonable permitting requirements.

     Our total leasehold position in the Williston Basin as of December 31, 2004 consisted of 179,259 gross and 113,403 net undeveloped acres and 12,141 gross and 7,472 net developed acres. Our estimated net proved reserves in the Williston Basin were 31 Bcfe at year end 2004. As of December 31, 2004, we had 31 net producing wells and production of 6.3 MMcfe/d for December 2004, with an average working interest of 39.7%. Our average working interest in the wells we operate is approximately 92%. We participated in the drilling of nine horizontal wells in 2004 as part of our 2004 capital program of $20 million in this area. Currently, we estimate our capital expenditures for 2005 will be $9.2 million in the Williston Basin, which includes drilling six horizontal wells and one recompletion. We are seeking an industry partner to enter into joint exploration or drilling agreements and to sell up to 50% of our interests in up to 57,892 net undeveloped acres in certain of our Williston projects to industry partners. If we are successful in obtaining industry partners and selling interests in these prospects, we plan to participate in the drilling of three Madison, one Bakken and two Red River exploration wells. Our oil is stored in tanks located at the wellsite and periodically collected by independent oil purchasers.

Madison

     Our development projects within the Madison area lie within the central Williston Basin along the Montana and North Dakota border. The majority of our properties, both producing and prospective, are located within a 50-mile radius of Williston, North Dakota, the major industry service center for the area. The tight concentration of assets and proximate location to a service center allows for efficient operations. Our drilling program targets the Madison formations at depths of 9,000 to 9,500 feet and the Bakken formation at depths of 7,500 to 10,500 feet. Our wells are drilled vertically 7,500 to 10,500 feet and then extended laterally up to 5,000 feet through the formation. As of December 31, 2004, we held 100,132 gross and 66,613 net leasehold acres in the area. In 2004, we drilled nine horizontal Madison wells. Eight were producing successfully and one was determined to be a dry hole. In addition, we determined the Karst 33-5 development well, drilled in 2003, was a dry hole.

Red River

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     Our Red River area lies along the North and South Dakota border on the southern flank of the Williston Basin. Within this area, we target the B Zone porosity of the Red River formation at approximately 9,300 feet. We believe Red River B porosity is a uniform, widespread, seven to eight feet thick reservoir unit present across the area. The B Zone is one of the primary producing zones along the Cedar Creek Anticline, which trends northwest from our acreage.

     Our total leasehold position in Red River consisted of 22,281 gross and 17,102 net undeveloped acres and 957 gross and 255 net developed acres, with an average working interest of 75% at December 31, 2004. Our exploration drilling program in Red River is scheduled to begin in 2005 after selling interests to industry partners. Our wells will be drilled vertically 9,000 to 9,400 feet and then extended laterally up to 5,000 feet through the formation.

Green River Basin

     The Green River Basin is located in southwestern Wyoming and adjacent areas of northeastern Utah. Two of the Rockies largest gas fields are in the Green River Basin, the Pinedale Anticline and Jonah.

Antelope Hollow

     Our total leasehold position in the Antelope Hollow exploration project consists of 13,297 gross and 7,977 net undeveloped acres as of December 31, 2004. The Antelope Hollow prospect is a seismically defined, anticlinal feature. We are participating as a non-operator in an 18,250 foot Dakota test, with a 40% working interest. This well commenced drilling on February 2, 2005 and, as of March 11, 2005, was drilling ahead. We may evaluate several other potentially productive formations uphole. We currently plan a $2 million capital program in this area in 2005 to drill this exploratory well. Subsequent to December 31, 2004, we have offered our working interest partner the opportunity to purchase a 60% interest in three leases covering 4,518 gross and net acres.

Denver-Julesburg Basin

     The DJ Basin covers parts of Colorado, Wyoming, Nebraska and Kansas and contains the well known Wattenberg field. Other operators have established production in the Wattenberg field from multiple zones, including the Niobrara formation at depths of 7,000 feet.

Tri-State

     Our exploration program focuses on the eastern side of the DJ Basin, which we refer to as our Tri-State area (which includes portions of northeastern Colorado, southwestern Nebraska and northwestern Kansas) and targets the biogenic shale gas potential of the Sharon Springs Member of the Pierre Formation and the biogenic gas potential of the underlying Niobrara Formation at depths less than 2,000 feet, and the conventional oil potential of Kansas City-Lansing, Marmaton, and Cherokee Formations of the Pennsylvanian System at depths of 4,000 to 4,800 feet. If successful, production can be sold into an already established interstate pipeline network.

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     We believe the Niobrara potential of the Tri-State area can be exploited with 3-D seismic “bright spot” and horizontal drilling technologies. Our project capital expenditures for 2003 and 2004 were $6.3 million for the purchase of 367,000 gross (346,000 net) acres and the acquisition of 224 miles of 2-D and 24 square miles of 3-D seismic.

     On January 28, 2005, we sold a 50% working interest in our Tri-State leasehold to an industry partner and entered into an agreement to jointly explore this area. In 2005, we anticipate acquiring additional 2-D seismic and drilling two exploration wells (one vertical and one horizontal) as part of a $2.5 million (gross) capital expenditure in this area. As a result of the sale to our industry partner, we now have interests in 367,426 gross and 173,011 net undeveloped acres in the Tri-State area.

Paradox Basin

     The Paradox Basin is located in southwestern Colorado and southeastern Utah, and is adjacent to the San Juan Basin of New Mexico and Colorado. Although the Paradox Basin is generally considered to be an oil prone basin, the application of 3-D seismic and new drilling fluid technology has enabled other operators to commercialize a new gas play in the Lower Honaker Trail formation in San Miguel County, Colorado.

Pine Ridge

     One of our project areas in the Paradox Basin is the Pine Ridge exploration prospect, which is a very early stage exploration concept. We are exploring for gas fields in stratigraphic traps associated with salt diapirs, a geological structure feature characterized by salt intrusion into a rock formation from below. As of December 31, 2004, we had interests in 2,042 gross acres and 1,960 net acres in the Pine Ridge prospect, located in San Juan County, Utah. We intend to build our acreage position in this play through acquisitions or other arrangements with acreage owners in the area. We also are in discussions with the U.S. Forest Service and the Bureau of Land Management as we begin the permitting process for a 20 square mile 3-D seismic survey that we have targeted for 2005.

Yellow Jacket

     In 2004, we acquired 13,118 gross acres and 8,044 net acres in Yellow Jacket. This prospect will target natural gas from a fractured shale reservoir at depths of 4,500 to 6,500 feet. Currently, we have not budgeted any capital expenditures for 2005.

Big Horn Basin

     We recently began building an exploratory position in the Big Horn Basin. The Big Horn Basin is located in north central Wyoming and lies west and north of the Powder River and Wind River Basins, respectively. Although the Big Horn Basin is largely considered an oil prone basin, we are pursuing both conventional stratigraphic and structural gas plays, as well as unconventional basin-centered type gas plays in the basin. As of December 31, 2004, we had leasehold interests in 192,799 gross and 145,442 net undeveloped acres in the Big Horn Basin.

Oil and Gas Data

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Proved Reserves

     The following table presents our estimated net proved natural gas and oil reserves and the present value of our estimated proved reserves at each of December 31, 2002, 2003, and 2004 based on reserve reports prepared by us and reviewed in their entirety by our independent petroleum engineers. All our proved reserves included in the reserve report are located in North America. Ryder Scott Company, L.P. reviews all our reserve estimates except for our reserve estimates in the Powder River Basin, which are reviewed by Netherland, Sewell & Associates, Inc. When compared on a well-by-well or lease-by-lease basis, some of our estimates of net proved reserves are greater and some are less than the estimates of our independent petroleum engineers. However, our internal estimates of total net proved reserves are within 10% of those estimated by our independent petroleum engineers. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission in connection with our registration statement for our initial public offering. The PV-10 and Standardized Measure shown in the table are not intended to represent the current market value of our estimated natural gas and oil reserves.

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     Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

     The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors”.

     Our independent engineers, Ryder Scott Company, L.P. and Netherland, Sewell & Associates, Inc., perform a well-by-well review of all of our properties and of our estimates of proved reserves and then provide us with their review reports concerning our estimates. Ryder Scott Company, L.P. provided us with a report stating its opinion that the methods and techniques used in preparing our reserve report are in accordance with generally accepted procedures for the determination of reserves, and that, in its judgment, there was no evidence of bias in the application of the methods and techniques for estimating proved reserves, and that the total proved net reserves estimated would be within 10% of those estimated by Ryder Scott Company, L.P. Netherland, Sewell & Associates, Inc. stated in its report that our estimates of proved oil and gas reserves and future revenue as shown in its report and in certain computer printouts in its office are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These review reports do not state the degree of their concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well, although this information is generated by the independent engineers as a basis for their review report.

     Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The PV-10 shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

     From time to time, we engage Ryder Scott Company, L.P. and Netherland, Sewell & Associates, Inc. to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. Neither Ryder

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Scott Company, L.P. nor Netherland, Sewell & Associates, Inc. nor any of their respective employees has any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future cash inflows for the subject properties. During 2004, we paid Ryder Scott Company, L.P. $31,616 for reviewing our reserve estimates and $29,840 for other consulting services. During 2004, we paid Netherland, Sewell & Associates, Inc. $66,010 for reviewing our reserve estimates and $79,232 for other consulting services.

Production and Price History

     The following table sets forth information regarding net production of oil, natural gas and natural gas liquids, and certain price and cost information for each of the periods indicated:

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Productive Wells

     The following table sets forth information at December 31, 2004, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

     The following table sets forth information as of December 31, 2004 relating to our leasehold acreage.

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     Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able to obtain extensions of the primary terms of our federal leases for the period that we have been unable to obtain drilling permits due to a pending EA, Environmental Impact Statement or related legal challenge. The following table sets forth as of September 30, 2004 the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

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Drilling Results

     The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

     From inception through December 31, 2004, we participated in drilling 474 gross wells, of which 335 were completed as producing, 121 were in process of completing or dewatering and 18 were dry holes. Also during that time, we recompleted 46 gross wells, which are not included in the totals above.

Operations

General

     In general, we serve as operator of wells in which we have a greater than 50% interest. In addition, we seek to be operator of wells in which we have lesser interests. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ drilling, production, and reservoir engineers,

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geologists and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our natural gas and oil properties.

Marketing and Customers

     We market the majority of the natural gas and oil production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell the majority of our production to a variety of purchasers under short-term contracts or spot gas purchase contracts ranging anywhere from one day to seven months, all at market prices. We have one long-term contract to sell natural gas at market rates through December 2007. The gas volumes subject to this agreement are negotiated annually and currently are 22.5 MMBtu/d. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. However, based on the current demand for natural gas and oil and availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations. For a list of our purchasers that accounted for 10% or more of our natural gas and oil revenues during the last two calendar years, see “Notes to Consolidated Financial Statements—Note 12—Significant Customers and Other Concentrations”.

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

     We incur gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third party transporter. We have three firm transportation agreements. The first agreement is with Questar Pipeline Company for 8,500 MMBtu/d of guaranteed pipeline capacity at a monthly charge of $45,000 for one year beginning in March 2004. The second agreement is with Cheyenne Plains Company for 9,000 MMBtu of guaranteed pipeline capacity for 12 years and three months beginning with our first shipments of gas in February 2005, with an annual commitment of $1,117,000 and for 5,000 MMBtu/d of guaranteed pipeline capacity for an additional year thereafter. The third agreement is with Questar Pipeline Company for 12,000 MMBtu/d of guaranteed pipeline capacity at a monthly charge of $94,000 per month for ten years beginning upon the completion of Questar’s upgrade of its pipeline in the Piceance Basin, which is expected to be completed in November 2005. Our natural gas and oil are transported through third party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected.

Competition

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     The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, local and Native American tribal laws and regulations more easily than we can, which would adversely affect our competitive position. 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. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Title to Properties

     As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing natural gas and oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. Our natural gas and oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Seasonal Nature of Business

     Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in certain areas of the Rocky Mountain region. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations. For an example of drilling reductions, see “Uinta Basin — West Tavaputs”.

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Environmental Matters and Regulation

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

	•	require the acquisition of various permits before drilling commences;
	•	require the installation of expensive pollution control equipment;
	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
	•	limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;
	•	require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
	•	impose substantial liabilities for pollution resulting from our operations; and
	•	with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

     These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and the federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations at this time. For the year ended December 31, 2004, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities.

     The environmental laws and regulations which could have a material impact on the oil and natural gas exploration and production industry are as follows:

     National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an EA prepared that assesses the potential

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direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the BLM will prepare a more detailed EIS that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

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

     As of March 11, 2005, we believe that we were in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we held all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we believe the current costs of managing our wastes as they are presently classified are not significant and are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

     Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site, or site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for 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. In the course of our operations, we use materials, that, if released, would be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been deposited.

     Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls

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regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the state. These prescriptions also prohibit the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We maintain all required discharge permits necessary to conduct our operations, and we believe we are substantial compliance with the terms thereof. Obtaining permits has the potential to delay the development of oil and natural gas projects.

     Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. These regulations may increase the costs of compliance for some facilities federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining permits has the potential to delay the development of oil and natural gas projects.

     Other Laws and Regulation. In 1997, numerous countries reached agreement on the Kyoto Protocol to the United Nations Framework Convention on Climate Change. If the Protocol enters into force, adopting countries would be required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The Bush administration has indicated it will not support ratification of the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from certain greenhouse gas emission sources, primarily power plants. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

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

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Other Regulation of the Oil and Gas Industry

     The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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

	•	the location of wells;
	•	the method of drilling and casing wells;
	•	the rates of production or “allowables”;
	•	the surface use and restoration of properties upon which wells are drilled and other third parties;
	•	the plugging and abandoning of wells; and
	•	notice to, and consultation with, surface owners and other third parties.

     State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

     Natural Gas Sales Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale for resale of natural gas in interstate

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commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales”, which include all of our sales of our own production.

     FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what affect, if any, future regulatory changes might have on our natural gas related activities.

     Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by state agencies. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.

     Operations on Native American Reservations. A portion of our leases in the Uinta basin are, and some of our future leases in this and other areas may be, regulated by Native American tribes. In addition to regulation by various federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations. Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, and numerous other matters.

     Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs. However, each Native American tribe is a sovereign nation and has the right to enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members, and numerous other conditions that apply to lessees, operators, and contractors conducting operations within the boundaries of an Native American reservation. Further, lessees and operators within an Native American reservation are subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe

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allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.

     Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases, fees, taxes, and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations. One or more of these requirements may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.

Employees

     As of March 1, 2005, we had 150 full time employees, including 17 geologists and geophysicists, 16 petroleum engineers and eight land and regulatory professionals. Of our 150 full time employees, 106 work in our Denver office and 44 are in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Offices

     As of March 11, 2005, we leased approximately 39,400 square feet of office space in Denver, Colorado at 1099 18th Street, where our principal offices are located. The lease for our Denver office expires in January 2009. We also have field offices in or near the Cave Gulch field and Gillette, Wyoming, Parachute, Colorado, and Roosevelt, Utah. We believe that our facilities are adequate for our current operations and that additional leased space can be obtained if needed.

Website and Code of Business Conduct and Ethics

     Our website address is http://www.billbarrettcorp.com. We make available free of charge through our website 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 or furnished to the SEC at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee are posted on our website at http://www.billbarrettcorp.com and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1099 18^th Street, Suite 2300, Denver, Colorado 80202.

GLOSSARY OF OIL AND NATURAL GAS TERMS

     The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K.

     3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the

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subsurface strata than 2-D, or two-dimensional, seismic.

     AMI. Area of mutual interest.

     Basin-centered gas. A regional abnormally-pressured, gas-saturated accumulation in low-permeability reservoirs lacking a down-dip water contact.

     Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report on Form 10-K in reference to crude oil or other liquid hydrocarbons.

     Bbl/d. Bbl per day.

     Bcf. Billion cubic feet of natural gas.

     Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

     Biogenic gas. Bacteria-generated natural gas usually found at depths of a few hundred to a few thousand feet because it is formed at the low temperatures that accompany the shallow burial and rarely is generated at depths greater that 3,000 feet.

     Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

     Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

     Coalbed methane (CBM). Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and produced by non-traditional means.

     Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

     Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

     Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

     Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

     Discontinuous lenticular sands. Sandstone reservoirs that have a limited aerial extent. In general these types of sandstones will be encountered by separate wellbores infrequently in a given area depending on well density. By comparison, a continuous or blanket sandstone may be encountered repeatedly by multiple wellbores in a given area.

     Down-dip. The occurrence of a formation at a lower elevation than a nearby area.

     Drill-to-earn. The process of earning an interest in leasehold acreage by drilling a

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well pursuant to a farm-in or exploration agreement.

     Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

     Environmental Assessment (EA). An environmental assessment, a study that can be required pursuant to federal law prior to drilling a well.

     Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

     Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out”.

     Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

     Finding and Development Costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

     Fractured shale gas. Gas that is present in fractures in a formation consisting mostly of shale.

     Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

     Horizontal re-entry well. A new well in which a pre-existing wellbore is used as the starting point of a new horizontal borehole. Drilling a horizontal re-entry well typically involves milling a hole in the casing of the pre-existing wellbore and drilling hundreds or thousands of feet from the pre- existing wellbore.

     Infill drilling. The drilling of wells between established producing wells on a lease to increase reserves or productive capacity from the reservoir.

     MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

     Mcf. Thousand cubic feet of natural gas.

     Mcf/d. Mcf per day.

     Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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     MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

     MMboe. Million barrels of oil equivalent.

     MMBtu. Million British Thermal Units.

     MMcf. Million cubic feet of natural gas.

     MMcf/d. MMcf per day.

     MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

     MMcfe/d. MMcfe per day.

     Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

     Overpressured. A subsurface formation that exerts an abnormally high formation pressure on a wellbore drilled into it.

     PDNP. Proved developed nonproducing.

     PDP. Proved developed producing.

     Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

     PUD. Proved undeveloped.

     Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

     Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

     Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

     Proved developed reserves (PDP). Reserves that can be expected to be recovered

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through existing wells with existing equipment and operating methods.

     Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

     Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

     PV-10. The present value, discounted at 10% per annum, of estimated future net cash flows before income tax of estimated proved reserves.

     Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

     Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

     Standardized Measure. The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.

     Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

     Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

     Tight gas sands. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

     Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

     Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Item 3. Legal Proceedings

     We are not a party to any material pending legal or governmental proceedings, other

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

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

During the quarter ended December 31, 2004, but prior to the time that the Company became a reporting company under the Securities Exchange Act, the Company’s securities holders approved the following matters by written consent on the dates indicated.

December 1, 2004

The stockholders approved our 2004 Stock Incentive Plan, which is described below in “Item 11. Executive Compensation”.

December 6, 2004

The stockholders approved (1) a Certificate of Amendment to our Certificate of Incorporation that reduced the number of authorized shares of Series B Preferred Stock from 52,185,000 to 51,951,418 and to prohibit the reissuance of shares of Series B Preferred Stock that are purchased or otherwise acquired by the Company; (2) a Restated Certificate of Incorporation that reflected amendments made to the Certificate of Incorporation in anticipation of our initial public offering, combined previous amendments and referenced the reverse stock split undertaken in connection with our initial public offering; (3) the Certificate of Designations setting forth the rights of our Series A Junior Participating Preferred Stock for our shareholder rights plan; and (4) our bylaws.

December 9, 2004

The stockholders approved a revised version of our Restated Certificate of Incorporation with a larger possible range of our reverse stock split.

Each of these matters was approved by the holders of the following securities, representing a majority of the voting power at each respective approval date. The shares of Series A Preferred Stock and Series B Preferred Stock automatically converted into shares of common stock upon the completion of our initial public offering on December 15, 2004.

PART II

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

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     Market for Registrant’s Common Equity. Our Common Stock is listed on the New York Stock Exchange under the symbol “BBG”.

     The range of high and low sales prices for our Common Stock for the period from December 10, 2004 when trading of our Common Stock commenced on the New York Stock Exchange through December 31, 2004, as reported by the NYSE, is as follows:

     On March 1, 2005, the closing sales price for the Common Stock as reported by the NYSE was $30.73 per share.

     Holders. On March 1, 2005, the number of holders of record of common stock was 209.

     Dividends. We have not paid any cash dividends since our inception. We anticipate that all earnings will be retained for the development of our business and that no cash dividends will be paid on our Common Stock in the foreseeable future.

     Use of Proceeds. On December 9, 2004, our Registration Statements on Form S-1 (SEC File Nos. 333-114554, 333-121128 and 333-121142) concerning our initial public offering were declared effective by the SEC. The offering was completed on December 15, 2004 and the underwriters purchased a total of 14,950,000 shares of our common stock at a price to public of $25.00 per share, for aggregate proceeds, before underwriting discounts, of $373.8 million. Goldman, Sachs & Co., J.P. Morgan Securities Inc. and Lehman Brothers Inc. were the representatives of the underwriters. We paid total underwriting discounts and commissions of $23.2 million, net of a $1.1 million credit received for early re-payment of the bridge loan, and total other expenses of $3.3 million in connection with our initial public offering, which resulted in our receiving net offering proceeds of approximately $347.3 million. The underwriting discounts and commissions included approximately $10.4 million paid to Goldman, Sachs & Co., whose related entities own more than 10% of our Common Stock. None of the other payments were to officers, directors or their associates, 10% stockholders or affiliates of the Company.

     We used $149.3 million of the net proceeds of our initial public to repay the entire $150 million principal amount, net of refunds of certain fees, and accrued interest outstanding under our senior subordinated credit and guaranty agreement, or ‘‘bridge loan’’, and $123.2 million, including accrued interest, to repay the entire outstanding indebtedness under our revolving credit facility. The additional proceeds of approximately $77.1 million will be used to fund general corporate purposes, including exploration and development activities, oil and gas reserve and leasehold acquisitions in the ordinary course of business, working capital and other general corporate purposes. The bridge loan was made to the Company by, and the repayment of the bridge loan was made to, an affiliate of Goldman, Sachs & Co. An affiliate of J.P. Morgan Securities Inc. serves as sole lead arranger on our revolving credit facility. Entities related to each of Goldman, Sachs & Co. and J.P. Morgan Securities Inc. own more than 10% or our Common Stock. See, “Item 13. Certain Relationships and Related Transactions”. None

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of the other payments were to officers, directors or their associates, 10% stockholders or affiliates of the Company.

Item 6. Selected Financial Data

     The following table presents selected historical financial data of the Company for the period from January 7, 2002 (inception) through December 31, 2002 and the years ended December 31, 2003 and 2004. All share and per share amounts for all periods presented have been restated to reflect the 1-for-4.658 reverse stock split which was effected upon completion of our IPO. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, presented elsewhere in this Annual Report on Form 10-K.

Selected Historical Information for Bill Barrett Corporation

     The consolidated income statement information for the period from January 7, 2002 (inception) through December 31, 2002 and for the years ended December 31, 2003 and 2004 and the balance sheet information as of December 31, 2003 and 2004 are derived from our audited financial statements included elsewhere in this report. The balance sheet information at December 31, 2002 is derived from audited financial statements that are not included in this report.

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Selected Historical Financial and Operating Information for Wind River Acquisition
Properties

     The selected financial data for the Wind River Acquisition Properties for the years ended December 31, 2000 and 2001 and for the period from January 1, 2002 through March 28, 2002 were derived from the audited and unaudited financial statements concerning the Wind River Acquisition Properties not included in this report and information provided by the seller. We requested that the seller provide us with all available information concerning these properties. Because these properties were a small portion of the seller’s total assets, the seller did not have more detailed financial information regarding these properties. For additional information concerning our financial data, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

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

Introduction

     The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying financial statements and related notes included elsewhere herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements”, subsections of this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-

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looking events discussed may not occur.

Overview

     We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. On December 9, 2004, our Registration Statements on Form S-1 (SEC File Nos. 333-114554, 333-121128 and 333-121142) concerning our initial public offering (“IPO”) were declared effective by the SEC. The offering was completed on December 15, 2004 and the underwriters purchased a total of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. We received net proceeds of $347 million after deducting underwriting fees and other offering costs.

     We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling operations. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. We recently decided to enter into joint exploration agreements with industry partners to whom a plan to sell portions of our interests in several exploratory projects to recoup a portion of our investment, to reduce the risk of exploratory drilling and to expedite drilling across our exploration inventory. We currently plan to use the proceeds from the selldowns to increase planned exploration activities and capital expenditures. Substantially all of our revenues are generated through the sale of natural gas and oil production under either short-term contracts or spot gas purchase contracts at market prices. Approximately 92% of our December 2004 production was natural gas.

     Our company was formed in January 2002. We began active natural gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin. We acquired these properties from a subsidiary of the Williams Companies, which acquired these properties in connection with the Williams Companies’ acquisition of Barrett Resources Corporation in August 2001. Since inception, we substantially increased our activity level and the number of properties that we operate. Our operating results reflect this growth. Also in 2002, we completed two additional acquisitions of properties in the Uinta, Wind River, Powder River and Williston Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired properties in the Piceance Basin consisting of 8,537 net developed and 9,044 net undeveloped lease acres, and 79 net producing wells in or around the Gibson Gulch field (the “Piceance Basin Acquisition Properties”). A summary of our significant property acquisitions is as follows:

Because of our rapid growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

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     Our acquisitions were financed with a combination of funding from our private equity stock investments, our bank line of credit, cash flow from operations and, in the case of the Piceance Basin properties, a bridge loan that was repaid in December 2004 with a portion of the proceeds of our IPO. The March 2002 purchase of properties in the Wind River Basin included core properties in the Cave Gulch and Wallace Creek fields. The April 2002 acquisition in the Uinta Basin included the West Tavaputs project area. The December 2002 acquisition included the Cooper Reservoir field, properties in the Powder River Basin and oil properties in the Williston Basin, along with other properties that were not deemed core to our business operations (approximately 20% of the acquisition) and that were sold in 2003. The September 2004 acquisition included the Gibson Gulch field in the Piceance Basin. Our 2003 and 2004 activities include development drilling and exploration in each of these areas. Our activities are now focused on evaluating and developing our asset base, increasing our acreage positions, and evaluating potential acquisitions.

     As of December 31, 2004, we had 292 Bcfe of estimated net proved reserves with a PV-10 of $592 million and a Standardized Measure of $466 million, while at December 31, 2003, we had 204 Bcfe of estimated net proved reserves with a PV-10 of $521 million and a Standardized Measure of $405 million, excluding properties held for sale.

     The average sales prices received for natural gas in all our core areas rose sharply in 2003 and 2004 compared to 2002. Before the effect of hedging contracts, the average price we received for natural gas in 2003 was $4.51 per Mcf compared to $2.39 per Mcf in 2002. Before the effects of hedging contracts, the average price we received for oil was $28.85 per Bbl in 2003 compared to $25.39 per Bbl in 2002. Before the effect of hedging contracts, the average price we received for natural gas and oil in 2004 was $5.53 per Mcf and $39.49 per Bbl, respectively.

     Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. To date, the higher sales prices for natural gas and oil have more than offset the higher field costs. Given the inherent volatility of oil and natural gas prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received in 2004. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production.

     Like all oil and gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. The permitting and

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approval process has been more difficult in recent years than in the past due to increased activism from environmental and other groups and has extended the time it takes us to receive permits and other necessary approvals. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

Results of Operations

     The following table sets forth selected operating data for the periods indicated.

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Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

     Revenues. Production revenues increased from $75.3 million for the year ended December 31, 2003 to $165.8 million for the year ended December 31, 2004 due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $20.3 million of production revenues, and production increases from the development of existing properties, and to a lesser extent, the Piceance Basin Acquisition Properties, added approximately $70.2 million of production revenues. Significant decreases in product prices would significantly reduce our revenues from existing properties. See “— Quantitative and Qualitative Disclosure about Market Risk”. Other revenues totaled $4.1 million for the year ended December 31, 2004, which were principally gains on disposals of oil and gas properties.

     Total production volumes for the 2004 calendar year increased 74% from 2003 with increases in all major producing basins. Additional information concerning production is in the following table.