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