Bill Barrett (BBG) 10-K 2007 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2007

or

¨ 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

(Exact name of registrant as specified in its charter)

Delaware	80-0000545
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

1099 18th Street, Suite 2300 Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 293-9100

(Registrant’s telephone number, including area code)

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

Title of each class	Name of each exchange on which registered
Common Stock, $.001 par value	New York Stock Exchange
Series A Junior Participating Preferred Stock Purchase Rights	New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    x  Yes    ¨  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    ¨  Yes    x  No

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.    x  Yes    ¨  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.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    ¨  Yes    x  No

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant as of June 30, 2007 was $1,232,782,371. For the purpose of the foregoing calculation only, the shares beneficially owned the Registrant’s directors, executive officers and the entity affiliated with a director that currently beneficially owns 10,081,278 shares of common stock have been assumed to be owned by affiliates.

* Without assuming that any of the issuer’s directors or executive officers, or the entity affiliated with a director that currently beneficially owns 10,081,278 shares of common stock, is an affiliate, the shares of which they are beneficial owners have been deemed to be owned by affiliates solely for this calculation.

As of February 15, 2008, the registrant had 44,790,978 outstanding shares of $.001 per share par value common stock.

DOCUMENTS INCORPORATED BY REFERENCE:

The information required in Part III of this Annual Report on Form 10-K is incorporated by reference from the registrant’s definitive proxy statement for the registrant’s Annual Meeting of Stockholders to be held in May 2008 to be filed pursuant to Regulation 14A no later than 120 days after the end of the Registrant’s fiscal year ended December 31, 2007.

TABLE OF CONTENTS

		Page
Cautionary Note Regarding Forward-Looking Statements		2
Part I	��	3
Items 1 and 2. Business and Properties		3
Glossary of Oil and Natural Gas Terms		26
Item 1A. Risk Factors		29
Item 1B. Unresolved Staff Comments		39
Item 3. Legal Proceedings		39
Item 4. Submission of Matters to a Vote of Security Holders		40
Part II		41
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		41
Item 6. Selected Financial Data		43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		45
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		69
Item 8. Financial Statements and Supplementary Data		70
Item 9. Changes in and Disagreements with Accountants and Financial Disclosure		70
Item 9A. Controls and Procedures		70
Report of Independent Registered Public Accounting Firm		71
Item 9B. Other Information		72
Part III		72
Item 10. Directors, Executive Officers and Corporate Governance		72
Item 11. Executive Compensation		72
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		72
Item 13. Certain Relationships and Related Transactions and Director Independence		72
Item 14. Principal Accounting Fees and Services		73
Part IV		73
Item 15. Exhibits, Financial Statement Schedules		73
Signatures		76
Financial Statements—Index to Financial Statements		F-1
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets		F-3
Consolidated Statements of Operations		F-4
Consolidated Statements of Stockholders’ Equity and Comprehensive Income		F-5
Consolidated Statements of Cash Flows		F-6
Notes to Consolidated Financial Statements		F-7

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended, which are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements may include statements about our:

• business and financial 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;

• realized oil and natural gas prices;

• production;

• changing regulatory environment;

• transportation and access to pipelines;

• lease operating expenses and costs related to the acquisition and development of oil and gas properties;

• availability and costs of drilling rigs and field services;

• general and administrative costs, oilfield services costs and other expenses related to our business;

• 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 1A. Risk Factors”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” 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”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target”, “seek”, “objective”, 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 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 “Item 1A. Risk Factors” 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 undertake no obligation 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. Our management has an extensive track record of growth and has significant expertise in unconventional and conventional reservoirs. 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 internally generated projects.

Our current strategy is to profitably grow our reserves and production by drilling low-risk repeatable development wells and finding developing gas and oil in the Rocky Mountain Region. In addition to low-risk development drilling, we plan to maintain our delineation and exploration progress on our extensive acreage portion of nearly 1.2 million net undeveloped acres. Our operating results reflect our exploration success and development growth on our properties.

We began active natural gas and oil operations in March 2002 with 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. Initially, we increased our activity level and the number of properties that we operate by acquiring a large inventory of undeveloped leasehold interests through federal and state sales as well as private purchases and trades. We have also acquired producing properties that had large undeveloped acreage positions associated with them. For example, 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 interests in properties in the Piceance Basin in or around the Gibson Gulch field; and in May 2006, we added to our coalbed methane position in the Powder River Basin with our acquisition of CH4 Energy Corporation. In June 2007, we sold our Williston Basin properties.

The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the United States. Consequently, the Company currently reports a single industry segment. See “Financial Statements” and the notes to our consolidated financial statements for financial information about this industry segment. See definitions of oil and natural gas terms below at “—Glossary of Oil and Natural Gas Terms.”

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The following table provides information regarding our operations by basin.

Basin/Area	State	Estimated Net Proved Reserves(1) (Bcfe)	December 2007 Average Daily Net Production (MMcfe/d)	Net Producing Wells	Net Undeveloped Acreage
Uinta	UT	243.6	75.6	99.4	166,212	(2)
Piceance	CO	212.2	85.2	279.3	12,404
Powder River	WY	47.7	17.9	412.3	86,566
Wind River	WY	54.0	16.1	150.8	233,157
Big Horn	WY	—	0.1	1.5	77,327
Paradox	CO/UT	—	—	—	213,529
Green River	CO/WY	—	—	—	54,965
Montana Overthrust	MT	—	—	—	161,513
Other(3)		0.1	0.1	4.5	180,118	(3)
Total		557.6	195.0	947.8	1,185,791	(2)(3)

(1) Our proved reserves were determined in accordance with SEC guidelines, using the market prices for natural gas (CIGRM price) and oil (WTI price) at December 31, 2007, which were $6.04 per MMBtu of natural gas and $92.50 per barrel of oil, without giving effect to hedging transactions. CIGRM refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. Our reserve estimates are based on a reserve report prepared by us and reviewed by our independent petroleum engineer. See “—Oil and Gas Data—Proved Reserves”.

(2) An additional 156,060 net undeveloped acres that are subject to drill-to-earn agreements are not included.

(3) Includes acreage associated with Denver-Julesburg Basin and Utah Hingeline properties that are held for sale.

Our Offices

We were founded in 2002 and incorporated in Delaware. Our principal executive offices are located at 1099 18th Street, Suite 2300, Denver, Colorado 80202, and our telephone number at that address is (303) 293-9100.

Business Strengths

We believe we have the following strengths:

• Proven track record of efficient production and reserve growth through drilling activities. We have increased our production and proved reserves by double-digit percentage growth rates each year that we have been in existence. In 2002, we produced 6.6 Bcfe and, in 2007, we produced 61.2 Bcfe. Proved reserves grew from 119.1 Bcfe at year-end 2002 to 557.6 Bcfe at year-end 2007. Over this time period, we replaced 288% of production through drilling and 343% of production in total, including acquisitions. From inception through December 31, 2007, we participated in the drilling of 1,335 gross wells, achieving a 97% success rate.

• Multi-year, low-risk, development drilling inventory. We have assembled an inventory of approximately 2,100 locations in our three core development areas in the Uinta, Piceance and Powder River Basins. The majority of these locations are in undeveloped areas or down-spacing programs where there are proved oil and gas reserves. We plan to allocate 80% or more of our capital budget to these low-risk development projects.

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• High operatorship and control of capital program. Based on our year-end 2007 proved reserves, we had a weighted-average working interest of 94% and operatorship of 97%. High operatorship allows us to more effectively control operating costs, timing of development activities, application of technological enhancements, marketing of production and allocation of our capital budget. In addition, the timing of most of our capital expenditures is discretionary, which allows us a significant degree of flexibility to adjust the size and timing of our capital development.

• Experienced management team. We believe our management team’s experience and expertise in the Rocky Mountains provides a distinct competitive advantage. Our 13 corporate officers average nearly 25 years of experience working in the industry. Our Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and most other members of our management team worked together as managers or executives with Barrett Resources Corporation, a publicly-traded Rocky Mountain oil and gas company that was founded in 1980 and sold to the Williams Companies in 2001.

• Expertise with unconventional resources. Approximately 70% of our properties are classified as unconventional resources, including basin-centered tight gas, CBM, fractured oil and shale gas plays. According to the Department of Energy’s Information Administration (“EIA”) 2008 Annual Energy Outlook, the EIA estimates that the lower 48 states unconventional natural gas resources will increase from 7.9 Tcf in 2005 to 9.3 Tcf in 2015.

• Large undeveloped acreage position that provides potential future growth opportunities. We have established an asset base of 1,185,791 net undeveloped leasehold acres as of December 31, 2007, as well as an additional 156,060 net undeveloped acres that are subject to drill-to-earn agreements. We have multiple exploration projects in five different basins and along the overthrust belt. We typically allocate up to 20% of our capital towards exploration and delineation projects. These projects provide us with an inventory of future long-term growth potential.

• Financial flexibility. As of December 31, 2007, we had $60.3 million in cash. At December 31, 2007, the outstanding balance under our $545.0 million credit facility was $274.0 million. We are committed to maintaining a conservative financial position to preserve our financial flexibility. We have hedged approximately 70% of our 2008 estimated production through swaps and collars to provide certainty for a portion of operating cash flows. We hedge natural gas prices at sales points in the Rocky Mountain and Mid-Continent regions, which mitigates the risk of basis differential to the Henry Hub index. We believe that our operating cash flow and available borrowing capacity under our credit facility provide us with the financial flexibility to pursue our currently planned development and exploration activities through 2008.

Business Strategy

Our strategy is to profitably grow our reserves and production by drilling low-risk, repeatable development wells and exploring for developing natural gas and oil in the Rocky Mountain region. The following are key components of that strategy:

• Drive growth through development drilling.We expect to generate profitable, long-term reserve and production growth predominantly through repeatable, low-risk drilling on our development assets. We typically allocate 80% of our capital budget to our development projects. Our three core development areas have approximately 2,100 identified drilling locations as of December 31, 2007. In 2008, we plan to participate in the drilling of up to 500 gross wells across our operations.

• Maximize operational control. We seek to operate our properties and maintain a high working interest. For the month of December 2007, we operated approximately 96% of our net production. We believe the ability to control our drilling inventory will provide us with the opportunity to efficiently allocate capital, manage resources, control operating and development costs and utilize our experience and knowledge of oilfield technologies.

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• Focus on natural gas in the Rocky Mountain region. We intend to capitalize on the large estimated undeveloped natural gas and oil resource base in the Rocky Mountains. We believe the Rocky Mountains represent one of the few natural gas regions in North America with significant remaining growth potential and, according to the EIA, the Rocky Mountains contain 22% of the United States’ natural gas reserves. All of our production is from the Rocky Mountains and, for the month of December 2007, 96% consisted of natural gas. The Rockies Express-West pipeline, which began operations in January 2008, provides Rocky Mountain producers additional takeaway capacity and access to markets with improved pricing for selling natural gas. There is additional pipeline capacity proposed to be built from the region over the next several years as Rocky Mountain production increases.

• Maintain financial flexibility and conservative financial position. Historically, we have funded our capital program with operating cash flow, debt, sales of equity and sales of interests in our properties. We continually monitor our debt levels to maintain a conservative financial position. Furthermore, we intend to continue hedging approximately 50-70% of our anticipated production on a 12-month forward basis to ensure a certain level of cash flow from operations.

• Pursue high potential projects. In addition to our low-risk development projects, we believe our management team’s experience and expertise enable us to identify, evaluate and develop new natural gas and oil reservoirs. We have assembled several exploration projects that we believe may provide future potential, long-term, cost-effective drilling inventories. We have a team of geologists and geophysicists dedicated to generating new geologic concepts to provide us exposure to high-potential exploration projects. We typically add partners and enter into joint exploration agreements to reduce our capital risk and accelerate our exposure to potential reserves and production in these high potential projects.

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Areas of Operation

Uinta Basin

The Uinta Basin, located in northeastern Utah, was our largest producing area for the year ended December 31, 2007. Our development operations are conducted in West Tavaputs, and we are currently testing offsets to attempt to delineate our Lake Canyon/Blacktail Ridge exploration discoveries. We also have a position in several exploration prospects in the Uinta Basin.

Key Statistics

• Estimated proved reserves as of December 31, 2007—243.6 Bcfe.

• Producing wells—We held interests in 112 gross producing wells as of December 31, 2007.

• 2007 production—25.8 Bcfe.

• Acreage—We held 166,212 net undeveloped acres as of December 31, 2007, along with 156,060 net acres that are subject to drill-to-earn agreements.

• Capital budget—In 2007, our capital expenditures were $166.4 million in the Uinta Basin area to drill 42 gross wells and install compression and gathering facilities. In our current 2008 capital budget, we plan to spend between $220 million and $240 million for drilling wells and installation of compression and gathering facilities.

West Tavaputs

We serve as operator of our interests in the West Tavaputs area. As of December 31, 2007, we had 550 drilling locations and 238.1 Bcfe of estimated proved reserves with a weighted average working interest of 98%. We are actively drilling our shallow program, which targets the gas-productive sands of the Wasatch and

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Mesaverde formations at depths down to 8,000 feet. We drilled 31 shallow wells in 2007 and plan to drill 51 shallow wells in 2008. The Wasatch and Mesaverde formations are currently being developed on 40-acre density following testing and analysis of 40-acre pilots in 2007.

With 3-D seismic, we have also identified two deeper structures targeting the Jurassic Navajo and Entrada and the Cretaceous Dakota formations at depths of nearly 15,000 feet. The eastern deep structure has been productive in five of seven wells drilled thus far; the other two are currently testing. We intend to drill up to five deep wells in 2008, including one test in the western deep structure in 2008.

Full development of the West Tavaputs area will require the completion of an Environmental Impact Statement, or EIS, which we initiated in February 2005 and which we expect to have a Record of Decision issued in the second half of 2008. See “Operations—Environmental Matters and Regulation.”

Our natural gas production at West Tavaputs is gathered and compressed by our facilities and delivered to markets on the Questar and its various subsidiaries’ pipeline systems. We recently entered into precedent agreements with Questar to subscribe for firm transportation arrangements on an expansion project as well as additional processing that we believe will provide adequate capability to move anticipated gas volumes from West Tavaputs.

Lake Canyon/Blacktail Ridge

Lake Canyon. In 2004, we and an industry partner entered into a drill-to-earn exploration and development agreement with the Ute Indian Tribe of the Uintah and Ouray Reservation, or the Ute Tribe and Ute Development Corporation 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. Pursuant to this agreement, we have the right to earn up to a 75% working interest in the Wasatch formation (targeting oil at approximately 8,000 feet) and deeper horizons, for which we serve as operator, plus up to a 25% interest in shallower Green River 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. The Ute Tribe has an option to participate in a 25% working interest in wells drilled pursuant to the agreement. Through 2006, we drilled three wells to the Wasatch formation, one of which was deemed a dry hole. We are in the process of drilling and testing our 2007 three-well program.

Blacktail Ridge. In December 2006, we entered into an exploration and development agreement with the Ute Tribe and the Ute Development Corporation to explore for and develop oil and natural gas on approximately 51,000 of their net undeveloped acres that are located in Duchesne County, Utah. Pursuant to this agreement, we serve as operator and have the right to earn a minimum of 50% working interest in all formations. To earn these interests pursuant to this agreement, we were required to drill a five Wasatch well program that began in 2007 followed by eight Wasatch wells per year thereafter. The Ute Tribe has an option to participate in up to 50% working interest in wells drilled pursuant to the agreement. We are in the process of drilling and testing our 2007 five-well commitment program.

Hook

Hook is a shale gas prospect in the southwestern portion of the Uinta Basin. In late 2007, we sold a 50% working interest in 29,531 net acres. In 2008, we plan to continue to acquire leasehold acreage and drill two exploration tests in these prospects.

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Piceance Basin

The Piceance Basin is located in northwestern Colorado. We began operations in the Gibson Gulch area of the Piceance Basin on September 1, 2004, with the purchase of producing and undeveloped properties from Calpine Corporation and Calpine Natural Gas L.P. for approximately $137.3 million.

Key Statistics

• Estimated proved reserves as of December 31, 2007—212.2 Bcfe.

• Producing wells—We held interests in 312 gross producing wells as of December 31, 2007.

• 2007 production—20.8 Bcfe.

• Acreage—We held 12,404 net undeveloped acres as of December 31, 2007.

• Capital budget—Our capital expenditures for 2007 were $180.3 million for participation in the drilling of 91 gross wells and to expand our compression and gathering facilities. In our current 2008 capital budget, we plan to spend between $230 million and $240 million for drilling wells, including on 10-acre and 20-acre density, and installation of additional compression and gathering facilities.

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 (Williams Fork) trend at depths of 7,500 feet. Through 2006, we drilled on a 20-acre well pattern. Beginning in 2007, we commenced drilling 10-acre pilot programs, and our 2007 year-end reserves include proved reserves associated with these pilots. Our natural gas production in this basin is currently gathered through our own gathering system and Encana’s and delivered to markets through a variety of pipelines including pipelines owned by Questar Pipeline Company, Northwest Pipeline, Colorado Interstate Gas Rocky Mountains (CIGRM) and Rockies Express Pipeline LLC. Our natural gas is processed at an Enterprise Products Partners L.P. plant in Meeker, CO.

Powder River Basin

The Powder River Basin is primarily located in northeastern Wyoming. Our operations are focused on the development drilling of coalbed methane wells, typically to a depth of 1,200 feet. Future development is primarily located in the Big George Coals.

Key Statistics

• Estimated proved reserves as of December 31, 2007—47.7 Bcfe.

• Producing wells—We held interests in 617 gross producing wells as of December 31, 2007.

• 2007 production—6.0 Bcfe.

• Acreage—We held 86,566 net undeveloped acres as of December 31, 2007.

• Capital budget—In 2007, our capital expenditures for the Powder River Basin were $39.3 million, which included participating in drilling 175 wells and acquisitions. In our current 2008 capital budget, we plan to spend between $35 million and $40 million for wells and facilities.

Coalbed methane wells typically first produce water in a process called dewatering. This process lowers reservoir pressure, allowing the gas to desorb 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 can range from five to 11 years depending on the coal seam.

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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. See “—Operations—Environmental Matters and Regulation.”

Our natural gas production in this basin is gathered through our own gathering systems and, for a majority of our gas, delivered to markets through additional gathering and pipeline systems owned by Fort Union Gas Gathering, LLC and Thunder Creek Gas Services.

Wind River Basin

The Wind River Basin is located in central Wyoming. Our activities are concentrated primarily in the eastern Wind River Basin, along the greater Waltman Arch, where we generally serve as operator. In addition, we have a number of exploration projects, some of which are in areas of the Wind River Basin where we have no existing development operations. We are seeking industry partners to enter into joint exploration agreements, which may involve the sale of a portion of our interests and joint drilling obligations for certain exploration projects in the Wind River Basin.

Key Statistics

• Estimated proved reserves as of December 31, 2007—54.0 Bcfe.

• Producing wells—We held interests in 168 gross producing wells as of December 31, 2007.

• 2007 production—7.4 Bcfe.

• Acreage—We held 233,157 net undeveloped acres as of December 31, 2007.

• Capital budget—For 2007, our operations in the basin included recompletions and exploration drilling, and capital expenditures were $10.5 million. In our current 2008 capital budget, we plan to spend between $35 million and $40 million for drilling wells, recompletions and facilities.

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 (“KMI”) and CIGRM.

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 on the productive overpressured deep Frontier, Muddy and Lakota formations at depths of up to 20,000 feet. In addition, we also produce from the shallower Lance and Fort Union formations.

We recently signed a joint exploration agreement with two industry partners for the drilling of at least two deep wells in 2008 on a partially promoted basis.

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.

Key Statistics

• Acreage—We held 213,529 net undeveloped acres as of December 31, 2007.

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Yellow Jacket

This prospect targets natural gas from a fractured shale reservoir at depths of 4,500 to 6,500 feet. Through 2007, we had drilled three exploratory vertical tests, of which one was deemed a dry hole and the other two are still being assessed. In 2008, we intend to drill at least two exploratory tests using horizontal well bores. We serve as operator in this area and have an average working interest of 46%.

Green Jacket

This prospect targets natural gas from a fractured shale reservoir at depths of 4,500 to 6,500 feet and is directly adjacent to our Yellow Jacket prospect. We plan to drill one vertical science well in 2008 and serve as operator in this area where we have a working interest of 100%.

Salt Flank

In the Salt Flank exploration prospect, we are targeting gas fields in stratigraphic and structural traps associated with salt diapirs. We plan to drill our first exploratory test on our Pine Ridge prospect in 2008, subject to selling down to an industry partner.

Montana Overthrust

We serve as operator and have a 50% working interest in this prospect in southwestern Montana. In 2007, we drilled two exploratory structural wells, which have been deemed dry holes below the Cody Shale interval. In 2008, we plan to conduct further tests on the Cody Shale.

Key Statistics

• Acreage—We held 161,513 net undeveloped acres as of December 31, 2007.

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.

Key Statistics

• Acreage—We held 77,327 net undeveloped acres at December 31, 2007.

• Capital budget—For 2007, our operations in the basin included a recompletion and seismic activity. In our current 2008 capital budget, we plan to spend up to $15 million for drilling exploratory tests.

Oil and Gas Data

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, 2005, 2006 and 2007 based on reserve reports prepared by us and reviewed in their entirety by outside independent petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our estimates independently reviewed, we are required by our revolving credit agreement with our lenders to have an independent engineering firm perform an annual review of our estimated reserves. All of our proved reserves included in our reserve reports are located in

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North America. Through December 31, 2006 Ryder Scott Company, L.P. reviewed all our reserve estimates except for our reserve estimates in the Powder River Basin, which were reviewed by Netherland, Sewell & Associates, Inc. (“NSAI”). As of December 31, 2007, NSAI reviewed all of our reserve estimates. 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 outside independent petroleum engineers. However, in aggregate, the independent petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with our registration statement for our initial public offering. The Standardized Measure shown in the table is not intended to represent the current market value of our estimated natural gas and oil reserves.

	As of December 31,
	2005		2006		2007
Proved Reserves:
Natural gas (Bcf)		306.0		377.7		538.3
Oil (MMBbls)		5.8		8.5		3.2
Total proved reserves (Bcfe)(1)		341.0		428.4		557.6
Proved developed reserves (Bcfe)		208.5		248.9		329.8
Standardized Measure (in millions)(2)	$	782.5	$	529.3	$	941.2

(1) Total does not add because of rounding.

(2) The Standardized Measure represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. In accordance with SFAS No. 69, our reserves and the future net revenues were determined using market prices for natural gas and oil, without giving effect to hedging transactions, at each of December 31, 2005, 2006 and 2007, which were $7.72 per MMBtu of gas and $61.04 per barrel of oil at December 31, 2005, $4.46 per MMBtu of gas and $61.06 per barrel of oil at December 31, 2006, and $6.04 per MMBtu of gas and $92.50 per barrel of oil at December 31, 2007. These prices were adjusted by lease for quality, transportation fees and regional price differences.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are 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. Proved undeveloped reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved undeveloped reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

The data in the above table represents estimates only. Oil and natural gas reserve engineering is an estimation of 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 “ Item 1A. Risk Factors”.

At year-end 2007, we revised our proved reserves upward by 34.8 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped locations in the West Tavaputs field and continued improved performance of wells drilled in the West Tavaputs and Piceance fields. We also revised our 2007 year-end proved reserves upward by 19.4 Bcfe, as year-end 2007 pricing was $6.04 per MMBtu and $92.50 per barrel of oil, relative to year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil. These prices were adjusted by lease for quality, transportation fees and regional price differences. At year-end 2006, we revised our proved reserves upward by 12.4 Bcfe, excluding pricing revisions. This revision was primarily the result of increased performance of wells drilled during the last half of 2005 and the first half of 2006.

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During years 2004 and 2005, we participated in drilling 610 gross wells. Of the 610 wells, 158 were producing at less than 75% of the original forecast at December 31, 2005. The revision in forecast of these wells resulted in negative reserve revisions, excluding pricing effects, of 32 Bcfe and 24.7 Bcfe for year-end 2004 and 2005, respectively. These revisions resulted from estimating reserves with insufficient performance to define long term production profiles. In order to reduce the risk of negative reserve revisions, we place lower reserve values on new wells in areas of insufficient performance. We will only increase the reserve values after sufficient performance data is acquired.

We use our internal reserve estimates rather than the estimates from the independent engineering firms, because we believe that our reserve and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by the independent engineers. We use our internal reserve estimates on all properties regardless of the positive or negative variance to the independent engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the independent engineers. These differences are investigated by us and the independent engineers and discussed with the independent engineers to confirm that we used the proper methodologies and techniques in estimating reserves for these fields. These differences are not resolved to a specified tolerance at the field or property level.

For the year ended December 31, 2007, our outside independent engineer, NSAI, performed a well-by-well review of all of our properties and of our estimates of proved reserves and then provided us with their review report concerning our estimates. The review completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These review procedures may be the same or different from those review procedures performed by other independent engineering firms for other oil and gas companies. NSAI’s review report does 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.

For the year ended December 31, 2007, the estimate provided by NSAI was 4.5% above our reserve estimate. For the year ended December 31, 2006, in which the review was performed by two independent engineering firms, Ryder Scott Company, L.P.’s estimate was 6.2% below our reserve estimate, and NSAI’s estimate was 7.9% below our reserve estimate. For estimates of proved reserves at December 31, 2006, our outside independent reserve engineers arrived at reserve estimates that were greater than 10% above or below our own estimates for approximately 52% of our wells. This represents approximately 45% of the total proved reserves covered in the review reports. At the material property level, the independent engineer reserve estimates ranged between 21.3% above our internal reserve estimates to 2.4% below our estimates in the year-end 2006 reserve report. At December 31, 2005, at the material property level, the independent engineer reserve estimates ranged between 1.0% above our internal reserve estimates to 0.3% below our estimates. At December 31, 2004, at the material property level, the independent engineer reserve estimates ranged between 0.3% above our internal reserve estimates to 13.8% below our estimates.

The NSAI review process of our wells and reserve estimates is intended to determine the percent difference, in the aggregate, of our internal net proved reserve estimate and future net revenue (discounted 10%) and the reserve estimate and net revenue as determined by NSAI. The review process includes the following:

• The NSAI engineer performs an independent decline curve analysis on proved producing wells based on production and pressure data. This data is provided to NSAI by us as well as other companies operating in the Powder River Basin.

• The NSAI engineer may verify the production data with the public data.

• The NSAI engineer uses his or her individual interpretation of the information and knowledge of the reservoir and area to make an independent analysis of proved producing reserves.

• The NSAI technical staff will prepare independent maps and volumetric analyses on our properties and offsetting properties. They review our geologic maps, log data, core data, pertinent pressure data, test information and pertinent technical analyses, as well as data from offsetting producers.

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• For the reserve estimates of proved non-producing and proved undeveloped locations, the NSAI engineer will estimate the potential for depletion by generating a potentiometric surface map, which relates directly to remaining gas-in-place, and analyzing this information with the maps generated earlier in the process.

• The NSAI engineer will estimate the hydrocarbon recovery of the remaining gas-in-place based upon their knowledge and experience.

• The NSAI engineer does not verify our working and net revenue interests or product price deductions.

• The NSAI engineer does not verify our capital costs although they may ask for confirming information.

• The NSAI engineer reviews 12 months of operating cost, revenue and pricing information that we provide.

• The NSAI engineer confirms the oil and gas prices used for the SEC reserve estimate.

• NSAI will confirm that their reserve estimate is within a 10% variance of our internal net reserve estimate and estimated future net revenue (discounted 10%), in the aggregate, before a review letter is issued.

• The review by NSAI is not performed such that differences in reserves or revenue on a well level are resolved to any specific tolerance.

The reserve review letter provided by NSAI states that “in our opinion the estimates of Bill Barrett’s proved reserves and future revenue shown herein are, in the aggregate, reasonable” following an independent estimation of reserve quantities with economic parameters and other factual data provided by us and accepted by NSAI.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure 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 Standards 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 NSAI and Ryder Scott to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. Neither NSAI nor Ryder Scott 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 2007, we paid NSAI approximately $216,000 for reviewing our reserve estimates and $0 for other consulting services. During 2007, we did not employ Ryder Scott to review our reserves or provide other consulting services.

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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:

	Year Ended December 31,
	2005		2006		2007
Production Data:
Natural gas (MMcf)(1)		36,287		47,928		57,678
Oil (MBbls)		523		696		586
Combined volumes (MMcfe)		39,425		52,104		61,194
Daily combined volumes (MMcfe/d)		108.0		142.8		167.7
Average Prices(2):
Natural gas (per Mcf)	$	7.16	$	6.40	$	5.89
Oil (per Bbl)		46.68		53.50		59.87
Combined (per Mcfe)		7.21		6.60		6.13
Average Costs (per Mcfe):
Lease operating expense	$	0.50	$	0.57	$	0.68
Gathering and transportation expense		0.30		0.30		0.38
Production tax expense		0.85		0.50		0.37
Depreciation, depletion and amortization(3)		2.27		2.69		2.87
General and administrative(4)		0.62		0.53		0.52

(1) Production of natural gas liquids is included in natural gas revenues and production.

(2) Includes the effects of hedging transactions, which reduced average natural gas prices by $0.57 per Mcf in 2005, and increased average natural gas prices by $0.46 and $1.52 per Mcf in 2006 and 2007, respectively, and reduced average oil prices by $7.01, $5.90, and $1.31 per Bbl in 2005, 2006 and 2007, respectively.

(3) The depreciation, depletion and amortization per Mcfe for the years ended December 31, 2006 and 2007 excludes the production associated with our properties held for sale throughout the year in the Uinta, Williston and DJ Basins, as these properties were excluded from amortization during the appropriate periods in which these properties were classified as held for sale.

(4) General and administrative expense presented herein excludes non-cash stock-based compensation of $3.2 million, $6.5 million and $10.2 million for the years ended December 31, 2005, 2006 and 2007, respectively, which equates to a reduction to G&A of $0.08 per Mcfe, $0.12 per Mcfe and $0.17 per Mcfe, respectively. Non-cash stock-based compensation is combined with general and administrative expense for a total of $27.8 million, $34.2 million and $42.2 million for the years ended December 31, 2005, 2006 and 2007, respectively, in the Consolidated Statement of Operations. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, who may have higher or lower costs associated with equity grants.

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Productive Wells

The following table sets forth information at December 31, 2007 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.

	Gas		Oil
	Gross Wells	Net Wells	Gross Wells	Net Wells
Basin
Uinta	109.0	97.3	3.0	2.1
Piceance	312.0	279.3	—	—
Powder River	570.0	403.7	47.0	8.5
Wind River	168.0	150.9	—	—
Other	12.0	6.0	—	—
Total	1,171.0	937.2	50.0	10.6

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2007 relating to our leasehold acreage.

	Developed Acreage(1)		Undeveloped Acreage(2)
	Gross	Net	Gross	Net
Basin/Area
Uinta	14,631	13,337	229,119	166,212	(3)
Piceance	4,767	3,837	15,136	12,404
Powder River	63,519	43,351	133,794	86,566
Wind River	6,911	5,293	366,252	233,157
Big Horn	801	374	181,419	77,327
Paradox	—	—	360,427	213,529
Green River	—	—	62,556	54,965
Montana Overthrust	—	—	377,227	161,513
Denver-Julesburg(4)	1,974	987	314,803	146,086
Utah Hingeline(4)	—	—	26,417	18,096
Other	1,241	904	30,131	15,936
Total	93,844	68,083	2,097,281	1,185,791	(3)

(1) Developed acres are acres spaced or assigned to productive wells.

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

(3) An additional 156,060 net undeveloped acres that are subject to drill-to-earn agreements are not included.

(4) These properties are held for sale as of December 31, 2007. Subsequent to December 31, 2007, we sold 249,700 gross and 120,019 net acres.

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

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to obtain extensions of the primary terms of our federal leases for the period in which we have been unable to obtain drilling permits due to a pending Environmental Assessment, Environmental Impact Statement or related legal challenge. The following table sets forth, as of December 31, 2007, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

	Undeveloped Acres Expiring
Twelve Months Ending:	Gross	Net
December 31, 2008	301,226	139,089
December 31, 2009	152,584	73,064
December 31, 2010	266,927	129,031
December 31, 2011	260,982	150,410
December 31, 2012 and later(1)	1,115,562	694,197
Total	2,097,281	1,185,791

(1) Includes 393,524 gross and 226,120 net undeveloped acres held by production from other leasehold acreage or held by federal units.

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 and quantities of reserves found or economic value. Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

	Year Ended December 31, 2005		Year Ended December 31, 2006		Year Ended December 31, 2007(1)
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	98.0	82.3	48.0	41.1	54.0	46.6
Dry	3.0	3.0	—	—	1.0	0.5
Exploratory
Productive	103.0	84.9	121.0	85.2	177.0	136.4
Dry	5.0	3.3	3.0	1.6	6.0	2.5
Total
Productive	201.0	167.2	169.0	126.3	231.0	183.0
Dry	8.0	6.3	3.0	1.6	7.0	3.0

(1) The determination of development and exploratory wells shown in the table above is based on an interpretation of the definitions of those terms in Rule 4-10(a) of Regulation S-X, which governs financial disclosures in filings with the SEC, that includes as development wells only those wells drilled on drilling locations to which proved undeveloped reserves have been attributed at the time at which drilling of the wells commenced and in which all other wells are considered exploratory. We also are providing information with respect to drilling results in which development wells include not only wells drilled on PUD locations but also wells drilled in a proved area in which proved reserves have been attributed by our reservoir engineers as of the time of commencement of drilling. On this basis, during 2007, we completed 227 gross (180.4 net) productive and 1 gross (0.5 net) dry development wells and 4 gross (2.6 net) productive and 6 gross (2.5 net) dry exploratory wells.

From our inception through December 31, 2007, we participated in drilling 1,335 gross wells, of which 936 were completed as producing; 363 were in process of completing or dewatering; and 36 were dry holes. Also during that time, we recompleted 40 gross wells, which are not included in the totals above.

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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 obtain regulatory authorizations, 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 the properties we operate. Independent contractors engaged by us provide all of the equipment and personnel associated with these activities. We employ drilling, production and reservoir engineers and 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 gas purchase contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, marketing companies, local distribution companies, and end users. 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 the 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.

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 fluctuations in gas prices. For a more 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”.

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Our natural gas and oil are transported through our own and third party gathering systems and pipelines, and we incur processing, 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 processor or transporter. Capacity 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. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We typically contract with third parties in the Piceance, Wind River and Uinta Basins to process our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. These agreements are subject to the limitations discussed above in this paragraph. The following table sets forth information about material long-term (greater than one year from December 31, 2007) firm transportation contracts for pipeline capacity and firm processing contracts, both of which typically require a demand charge and firm sales contracts.

Type of Arrangement	Pipeline System / Location	Gross Deliveries (MMBtu/d)	Term
Firm Sales	Questar Pipeline	10,000	4/06 – 12/09
Firm Sales	Questar Pipeline	5,000	4/06 – 3/09
Firm Sales	Questar Pipeline	8,500	5/05 – 3/10
Firm Sales	KMI	10,000	11/07 – 12/08
Firm Transport	WIC Medicine Bow	5,000	6/08 – 3/14
Firm Transport	WIC Medicine Bow	30,000	11/07 – 3/15
Firm Transport	Questar Pipeline	12,000	11/05 – 10/15
Firm Transport	Questar Pipeline	25,000	1/07 – 12/16
Firm Transport	Cheyenne Plains	9,000	2/05 – 4/17
Firm Transport	Cheyenne Plains	5,000	5/17 – 4/18
Firm Transport	Questar Pipeline	25,000	11/07 – 10/17
Firm Transport	Rockies Express	25,000	1/08 – 6/19
Firm Transport	Questar Pipeline	15,000	1/08 – 6/09
Firm Transport	Questar Gas	70,000	4/08 – 1/17
Firm Transport	Questar Pipeline	11,000	4/07 – 9/08
Firm Processing	Questar Pipeline	50,000	8/06 – 8/16
Firm Processing	Questar Gas	50,000	4/07 – 12/08

Hedging Activities

We have an active commodity hedging program to mitigate the risks of the volatile prices of natural gas and oil. Typically, we intend to be approximately 50-70% hedged on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with creditworthy counterparties. For additional information on our hedging activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”

Competition

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 are 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

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our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors are better 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 for 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 the 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 our properties or affect of our carrying value of the properties.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the spring and fall months and increases during the summer and 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 can 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.

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;

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• 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;

• with respect to operations affecting federal lands or leases, require time consuming environmental analysis; and

• expose us to litigation by environmental and other special interest groups.

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 and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or 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, 2007, we did not incur any material capital expenditures for remediation or retrofit of 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 Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment, or EA, prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study, or 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. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt 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”.

We believe that we are 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 that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative

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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 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 the 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 in 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 will 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 we own or operate, and 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. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily carbon dioxide emissions from 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 the combustion of fossil fuels or the venting of natural gas could impact our future operations. Our operations are not adversely impacted by current state and local climate

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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.

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 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 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.

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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 effect, 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 services, 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 a Native American reservation. Further, lessees and operators within a 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 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 February 15, 2008, we had 252 full time employees. Of our 252 full time employees, 156 work in our Denver office and 96 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 is represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

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Offices

As of December 31, 2007, we leased approximately 62,633 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 March 2011. We also own field offices in Waltman, Wyoming, Roosevelt, Utah and Silt, Colorado, and lease a field office in Gillette, Wyoming. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space 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. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K. This Annual Report on Form 10-K and our website contain information provided by other sources that we believe are reliable. We cannot assure you that the information obtained from other sources is accurate or complete. No information on our website is incorporated by reference herein.

Annual CEO Certification

As required by New York Stock Exchange rules, on June 8, 2007 we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:

3C 3-D seismic.A three dimensional seismic survey employing three-component geophones. These multi-component geophones record three orthogonal components of ground motion and provide information about shear waves that are unobtainable by conventional 3-D seismic surveys.

3-D seismic.Acoustical reflection data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

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.

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.

BtuorBritish 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 nontraditional 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.

Curtailments.The delivery of gas below contract entitlements due to system restrictions.

Desorb.A physical process whereby gas molecules are liberated from a host rock, such as a shale or coal reservoir, when the formation pressure is reduced.

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.

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 well pursuant to a farm-in, exploration, or other 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.

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Environmental Impact Statement (EIS).An environmental impact statement, a more detailed study that can be required pursuant to federal law of the potential direct, indirect and cumulative impacts of a project that may be made available for public review and comment.

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.

Fractured oil.A type of hydrocarbon accumulation where the storage and movement of oil in the reservoir is strongly controlled by natural fractures.

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

Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

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.

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

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.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

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

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.

Potentiometric surface.An imaginary surface defined by the level to which water in an aquifer would rise due to the natural pressure in the rocks.

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 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.

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.

Salt diapir.A generally long and linear geologic structure formed from the emplacement of a large column of salt into pre-existing rock layers.

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, 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% to reflect timing of future cash flows.

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.

Tcf. Trillion cubic feet (of gas)

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.

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Item 1A. Risk Factors

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect our company.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil and natural gas prices are volatile and a decline in oil and natural gas prices can significantly affect our financial results and impede our growth.

Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the domestic and foreign supply of oil and natural gas;

• the price of foreign imports;

• overall domestic and global economic conditions;

• political and economic conditions in oil producing countries, including the Middle East and South America;

• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• the level of consumer product demand;

• weather conditions;

• technological advances affecting energy consumption;

• domestic and foreign governmental regulations;

• proximity and capacity of oil and gas pipelines and other transportation facilities;

• the price and availability of alternative fuels; and

• variations between product prices at sales points and applicable index prices.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

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We have incurred losses from operations for various periods since our inception and may do so in the future.

We incurred net losses of $5.0 million, $4.0 million and $5.3 million in the period from January 7, 2002 (inception) through December 31, 2002 and in the years ended December 31, 2003 and 2004, respectively. Our development of and participation in an increasingly larger number of prospects has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire natural gas and oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. At year-end 2004 and 2005, we revised our reserves downward by 32 Bcfe and 24.7 Bcfe, excluding pricing revisions, respectively. We participated in drilling 798 gross wells from inception through December 31, 2005. Of the 798 wells, 219 were producing at less than 75% of original forecast at year-end 2005, which resulted in the reserve revisions in 2004 and 2005.

Our estimates of proved reserves are determined at prices and costs at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. The pricing revision at year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil, relative to year-end 2005 prices of $7.72 per MMBtu and $61.04 per barrel of oil, was downward 33.8 Bcfe.

We prepare our own estimates of proved reserves, which are reviewed by independent petroleum engineers. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties—Oil and Gas Data—Proved Reserves” and “Notes to Consolidated Financial Statements—14. Supplementary Oil and Gas Information (unaudited)—Analysis of Changes in Proved Reserves” in this Annual Report on Form 10-K.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2007, production will decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities.

We describe some of our prospects and our plans to explore those prospects in “Items 1 and 2. Business and Properties”. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. However, the use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling and

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testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. From inception through December 31, 2007, we participated in drilling a total of 1,335 gross wells, of which 936 were completed as producing, 363 were in process of completing or dewatering and 36 were identified as dry holes. Of the 797 wells drilled from inception through December 31, 2005, 219 were producing at less than 75% of original forecast at year-end 2005. If we drill additional wells that we identify as dry holes in our current and future prospects, our drilling success rate may decline and materially harm our business. The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive. Such uncertainties may harm our business and results of operations.

Certain of our leases in the Powder River Basin are in areas that may have been partially depleted or drained by offset wells.

The Powder River Basin represents a significant part of our drilling program and production. In the Powder River Basin, nearly all of our operations are in coalbed methane plays, and our key project areas are located in areas that have been the most active drilling areas in the Rocky Mountain region. As a result, many of our leases are in areas that may have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business. In 2008, we plan to participate in the drilling of up to 500 gross wells.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of natural gas and oil, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures. We are employing 3C 3-D seismic technology to certain of our projects. The implementation and practical use of 3C 3-D seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may chose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.

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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

• unusual or unexpected geological formations;

• pressures;

• fires;

• blowouts;

• loss of drilling fluid circulation;

• title problems;

• facility or equipment malfunctions;

• unexpected operational events;

• shortages or delivery delays of equipment and services;

• objections from surface owners and nearby surface owners in the areas where we operate;

• compliance with environmental and other governmental requirements and related lawsuits; and

• adverse weather conditions.

The occurrence of these events could also impact third parties, including persons living near our operations, our employees and employees of our contractors, leading to injuries or death or property damage. As a result, we face the possibility of liabilities from these events that could adversely affect our business, financial condition or results of operations.

Additionally, the coal beds in the Powder River Basin from which we produce methane gas frequently contain water, which may hamper our ability to produce gas in commercial quantities. The amount of coalbed methane that can be commercially produced depends upon the coal quality, the original gas content of the coal seam, the thickness of the seam, the reservoir pressure, the rate at which gas is released from the coal and the existence of any natural fractures through which the gas can flow to the well bore. Coal beds, however, frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. The average life of a coal bed well can range from five to 11 years depending on the coal seam compared to up to 30 years for a non-coal bed well. Our ability to remove and economically dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce coalbed methane in commercial quantities.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

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Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with sales of our equity securities, proceeds from bank borrowings and cash generated by operations. We intend to finance our capital expenditures with cash flow from operations and our existing financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:

• our proved reserves;

• the level of oil and natural gas we are able to produce from existing wells;

• the prices at which oil and natural gas are sold; and

• our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our revolving credit facility restricts our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing.

If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas and oil reserves as well as our revenues and results of operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by Native American tribes. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Our Powder River Basin coalbed methane exploration and production activities result in the discharge of large volumes of produced groundwater into adjacent lands and waterways. The ratio of methane gas to produced water varies over the life of the well. The environmental soundness of discharging produced groundwater pursuant to water discharge permits has come under increased scrutiny. Moratoriums on the issuance of additional water discharge permits or more costly methods of handling these produced waters, may affect future well development. Compliance with more stringent laws or regulations, more vigorous enforcement policies of the regulatory agencies, difficulties in negotiating required surface use agreements with land owners or receiving other governmental approvals could delay our Powder River Basin exploration and production activities and/or require us to make material expenditures for the installation and operation of systems and equipment for

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pollution control and/or remediation, all of which could have a material adverse effect on our financial condition or results of operations.

In August 2004, the Tenth Circuit Court of Appeals in Pennaco Energy, Inc. v. United States Department of the Interior, upheld a decision by the Interior Board of Land Appeals that the Department of the Interior’s Bureau of Land Management, or BLM, failed to fully comply with the National Environmental Policy Act, or NEPA, in granting certain federal leases in the Powder River Basin to Pennaco Energy, Inc. for coalbed methane development. Other recent decisions in the federal district court in Montana have also held that BLM failed to comply with NEPA when considering coalbed methane development in the Powder River Basin. While these recent decisions have not had a material direct impact on our current operations or planned exploration and development activities, future litigation and/or agency responses to such litigation could materially impact our ability to obtain required regulatory approvals to conduct operations in the Powder River Basin.

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to the regulation by oil and natural gas-producing states and Native American tribes of conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating area. See “Items 1 and 2. Business and Properties—Business—Operations—Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties—Business—Operations—Other Regulation of the Oil and Gas Industry”.

Recent Colorado legislative changes could limit our Colorado operations and adversely affect our cost of doing business.

Our properties located in Colorado are subject to the authority of the Colorado Oil & Gas Conservation Commission (the “COGCC”). The COGCC has the authority to regulate oil and gas activities to protect public health, safety and welfare, including the environment and wildlife. In 2007, the Colorado legislature approved legislation changing the composition of the COGCC to reduce industry representation and to add the heads of the Colorado Department of Natural Resources and the Colorado Department of Public Health and Environment (“CDPHE”) plus other stakeholders. In addition, the legislation required the COGCC to promulgate rules, (1) in consultation with CDPHE, to provide CDPHE an opportunity to provide comments on public health issues during the COGCC’s decision-making process and (2) in consultation with the Colorado Wildlife Commission, to establish standards for minimizing adverse impacts to wildlife resources affected by oil and gas operations and to ensure the proper reclamation of wildlife habitat during and following such operations. The COGCC has published a draft proposal to implement these provisions and expects to initiate formal rule-making in the first quarter of 2008. Final rules could be effective by the third quarter of 2008. While this regulatory development has not adversely affected our operations to date, these additional rules could cause additional costs, delay and uncertainty in our operations in Colorado and may be emulated in other jurisdictions in which we operate.

Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our operations have been focused on the Rocky Mountain region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are

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not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

During the second half of 2007, natural gas prices in the Rocky Mountain region fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural gas from producing properties in the region. Because of the concentration of our operations in the Rocky Mountain region, such price decreases are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. For example, we encountered limitations on our activities in the West Tavaputs area of the Uinta Basin earlier than expected in the fourth quarter of 2004 due to lease stipulations, which prevented us from completing wells. In addition, our costs increased due to removal of a drilling rig, incurrence of expenses relating to the reinstallation of that rig and additional mobilization costs when the winter stipulations ended in the spring of 2005.

Properties that we buy 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.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. However, our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

Substantially all of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

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Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.

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

To achieve a more predictable cash flow, to reduce our exposure to adverse fluctuations in the prices of oil and natural gas and to comply with credit agreement requirements, we currently, and may in the future, enter into hedging arrangements for a portion of our oil and natural gas production. Hedging arrangements for a portion of our oil and natural gas production expose us to the risk of financial loss in some circumstances, including when:

• production is less than expected;

• the counterparty to the hedging contract defaults on its contractual obligations; or

• there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, these types of hedging arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.

The risk that a counterparty may default on its obligations is heightened by the recent sub-prime mortgage losses incurred by many banks and other financial institutions, including our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales, thus triggering the hedge payments. As a result, our financial condition could be materially, adversely affected.

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

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

We depend on a limited number of key personnel who would be difficult to replace.

We depend on the performance of our executive officers and other key employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy. We do not maintain key person life insurance policies on any of our employees.

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Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

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 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 competitors may be able to absorb the burden of present and future federal, state, local and other 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.

Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations.

We will depend on our revolving credit facility for a portion of our future capital needs. Our current revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are, and expect to continue to be, required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable.

Our current revolving credit facility limits the amounts we can borrow up to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 75% of the commitments. If the required lenders do not agree on an increase, then the borrowing base will be the lowest borrowing base acceptable to the required number of lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility.

The ability of our banks to fund their lending obligations under our credit facility may be limited, which would affect our ability to fund our operations.

Our credit facility has commitments from 14 banks. With the current turbulent credit markets, including as a result of losses from the sub-prime mortgage crisis, the banks may become more restrictive in their lending practices or unable to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserve growth, leading to losses and declining production.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s

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atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have already taken legal measures to reduce emissions of greenhouse gases. As a result of the U.S. Supreme Court’s decision on April 2, 2007 inMassachusetts, et al. v. EPA, the EPA also may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of state or federal climate control legislation or other regulatory initiatives or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for oil and gas.

Risks Related to Our Common Stock

Our stock price and trading volume may be volatile, which could result in losses for our stockholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common stock include:

• actual or anticipated quarterly variations in our operating results;

• changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;

• announcements relating to our business or the business of our competitors;

• conditions generally affecting the oil and natural gas industry;

• the success of our operating strategy; and

• the operating and stock price performance of other comparable companies.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

Future sales of our common stock or other equity linked products may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock.

As of December 31, 2007, we had 44,760,955 shares of common stock outstanding, excluding stock options. All of the 14,950,000 shares sold in our initial public offering in December 2004, other than shares purchased by our affiliates, are freely tradable. In addition, the remaining outstanding shares are either freely tradable or may be sold in accordance with the provisions of Rule 144. Certain of our stockholders have contractual rights to cause us to register the resale of up to 10,081,278 of our outstanding shares. This registration may be accomplished quickly by filing prospectus supplements under our currently effective shelf registration statement. The resale of a large number of shares could cause our stock price to decline.

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Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

Delaware corporate law and our certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:

• a classified board of directors;

• giving the board the exclusive right to fill all board vacancies;

• permitting removal of directors only for cause and with a super-majority vote of the stockholders;

• requiring special meetings of stockholders to be called only by the board;

• requiring advance notice for stockholder proposals and director nominations;

• prohibiting stockholder action by written consent;

• prohibiting cumulative voting in the election of directors; and

• allowing for authorized but unissued common and preferred shares, including shares used in our shareholder rights plan.

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

We have significant stockholders with the ability to influence our actions.

Warburg Pincus Private Equity VIII, L.P. owns approximately 23% of our outstanding common stock. Accordingly, this stockholder may be able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. This concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors also may delay or prevent a change in our management or voting control. In addition, one of our directors is affiliated with Warburg Pincus Private Equity VIII, L.P.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus, on the other hand, concerning, among other things, potential competitive business activities or business opportunities. None of the institutional investors is restricted from competitive oil and natural gas exploration and production activities or investments, and our certificate of incorporation contains a provision that permits Warburg Pincus to participate in transactions relating to the acquisition, development and exploitation of oil and natural gas reserves without making such opportunities available to us.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 3. Legal Proceedings

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business and a matter with the Environmental Protection Agency (“EPA”). In September 2006, the EPA alleged that we and an industry partner failed to comply with air quality and emissions standards for equipment used at our North Hill Creek compressor station in the Uinta Basin of Utah. Discussions

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with the EPA to resolve these issues are continuing. We believe that our monetary sanctions related to this matter will be less than $100,000 based on our discussions with the EPA and our analysis of monetary sanctions in similar actions. However, potential fines of up to $32,500 per day are possible if we are not able to reach a settlement agreement with the EPA and all the allegations were determined to be accurate.

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

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

Not applicable.

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PART II

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

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 two most recent fiscal years as reported by the New York Stock Exchange, is as follows:

	High		Low
2006
First Quarter	$	40.85	$	29.00
Second Quarter		37.90		26.00
Third Quarter		31.60		23.35
Fourth Quarter		33.20		22.60
2007
First Quarter	$	32.94	$	24.76
Second Quarter		39.25		32.33
Third Quarter		40.45		32.12
Fourth Quarter		47.14		38.02

On February 15, 2008, the closing sales price for the common stock as reported by the NYSE was $45.84 per share.

Holders. On February 15, 2008, the number of holders of record of common stock was 380.

Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our credit facility prohibits the payment of cash dividends, no cash dividends will be paid on our common stock in the foreseeable future.

Issuer Purchases of Equity Securities.The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2007.

Issuer Purchases of Equity Securities

Period	Total Number of Shares(1)	Average Price Paid Per Share		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
October 1 – 31, 2007	—		—	—	—
November 1 – 30, 2007	—		—	—	—
December 1 – 31, 2007	638		42.75	—	—
Total	638	$	42.75	—	—

(1) Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of equity shares of common stock issued pursuant to our employee incentive plans.

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Stockholder Return Performance Presentation

As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:

1.     $100 was invested in our common stock at $25.00 per share on December 10, 2004 (the first full trading day following the effective date of our registration statement filed in connection with the initial public offering of our common stock), and $100 was invested in each of the Standard & Poors 500 Index, the Standard & Poors SmallCap 600 Index-Energy Sector and the Standard & Poors MidCap 400 Index-Energy Sector at the closing price on December 9, 2004.

2. Dividends are reinvested on the ex-dividend dates.

	December 10, 2004(1)		December 31, 2004		December 31, 2005		December 31, 2006		December 31, 2007(2)
BBG	$	100.00	$	127.96	$	154.44	$	108.84	$	167.48
S&P SmallCap 600-Energy	$	100.00	$	105.04	$	159.85	$	188.03	$	232.04
S&P MidCap 400-Energy	$	100.00	$	103.83	$	157.84	$	160.91	$	227.30
S&P 500	$	100.00	$	102.00	$	107.88	$	122.90	$	123.47

(1) December 10, 2004 was the first full trading day following the effective date of the Company’s registration statement filed in connection with the initial public offering of its common stock.

(2) In 2007, we were added to the Standard and Poors MidCap 400 Index and have, therefore, changed our comparative peer group to that index.

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Item 6. Selected Financial Data

The following table presents selected historical financial data of the Company for the years ended December 31, 2003, 2004, 2005, 2006 and 2007. 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 Financial Information

The consolidated income statement information for the years ended December 31, 2005, 2006 and 2007 and the balance sheet information as of December 31, 2006 and 2007 are derived from our audited financial statements included elsewhere in this report. The income statement information for the years ended December 31, 2003 and 2004 and the balance sheet information at December 31, 2003, 2004 and 2005 is derived from audited financial statements that are not included in this report. The information in this table should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included herein.

	Year Ended December 31,
	2003			2004			2005			2006			2007
	(in thousands, except per share data)
Statement of Operations Data:
Production revenues(1)	$	75,252		$	165,843		$	284,406		$	344,127		$	374,956
Other revenues		184			4,137			4,353			31,202			15,314
Operating expenses:
Lease operating expense		8,462			14,592			19,585			29,768			41,643
Gathering and transportation expense		3,646			5,968			11,950			15,721			23,163
Production tax expense		9,815			20,087			33,465			25,886			22,744
Exploration expense		3,655			12,661			10,930			9,390			8,755
Impairment, dry hole costs and abandonment expense		4,274			24,011			55,353			12,824			25,322
Depreciation, depletion and amortization		30,724			68,202			89,499			138,549			172,054
General and administrative expense		14,213			18,061			24,540			27,752			32,074
Non-cash stock-based compensation expense		3,637			3,031			3,212			6,491			10,154
Total operating expenses		78,426			166,613			248,534			266,381			335,909
Operating (loss) income		(2,990	)		3,367			40,225			108,948			54,361
Other income (expense):
Interest and other income		123			437			1,977			2,527			2,391
Interest expense		(1,431	)		(9,945	)		(3,175	)		(10,339	)		(12,754	)
Total other income and expense		(1,308	)		(9,508	)		(1,198	)		(7,812	)		(10,363	)
Income (loss) before income taxes		(4,298	)		(6,141	)		39,027			101,136			43,998
Provision for (benefit from) income taxes		(320	)		(875	)		15,222			39,125			17,244
Net income (loss)		(3,978	)		(5,266	)		23,805			62,011			26,754
Less deemed dividends on preferred stock		—			(36,343	)		—			—			—
Less cumulative dividends on preferred stock		(12,682	)		(18,633	)		—			—			—
Net income (loss) attributable to common stockholders	$	(16,660	)	$	(60,242	)	$	23,805		$	62,011		$	26,754
Income (loss) per common share(2):
Basic	$	(19.38	)	$	(15.40	)	$	0.55		$	1.42		$	0.61
Diluted	$	(19.38	)	$	(15.40	)	$	0.55		$	1.40		$	0.60
Weighted average number of common shares outstanding, basic(3)		859.4			3,912.3			43,238.3			43,694.8			44,049.7
Weighted average number of common shares outstanding, diluted		859.4			3,912.3			43,439.6			44,269.4			44,677.5

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	Year Ended December 31,
	2003			2004			2005			2006			2007
	(in thousands)
Selected Cash Flow and Other Financial Data:
Net income (loss)	$	(3,978	)	$	(5,266	)	$	23,805		$	62,011		$	26,754
Depreciation, depletion, impairment and amortization		30,724			68,202			89,499			138,549			172,054
Other non-cash items		7,786			26,887			71,168			37,765			40,938
Change in assets and liabilities		(659	)		(2,941	)		(202	)		(1,427	)		11,707
Net cash provided by operating activities	$	33,873		$	86,882			184,270			236,898			251,453
Capital expenditures(4)	$	186,327		$	347,520	(5)	$	347,427	(5)	$	501,161	(5)	$	443,678	(5)

(1) Revenues are net of effects of hedging transactions.

(2) All per share information has been adjusted to reflect the 1-for-4.658 reverse common stock split effected upon the completion of our initial public offering in December 2004.

(3) The weighted average number of common shares outstanding used in the loss per share calculation are computed pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 128Earnings Per Share. The weighted average common shares outstanding for the year ended December 31, 2004 does not include the 6,594,725 Series A or the 51,951,418 Series B preferred stock that were converted into a total of 26,387,679 common shares upon the completion of our initial public offering in December 2004.

(4) Excludes future reclamation liability accruals of $2.9 million, $7.1 million, $10.7 million, $6.3 million and $1.3 million in 2003, 2004, 2005, 2006 and 2007, respectively, and includes exploration, dry hole and abandonment costs, which are expensed under successful efforts accounting, of $6.1 million, $36.2 million, $23.6 million, $21.0 and $29.0 million in 2003, 2004, 2005, 2006 and 2007, respectively. Also includes furniture, fixtures and equipment costs of $1.8 million in 2003, $2.1 million in 2004, $2.6 million in 2005, $2.4 million in 2006 and $4.6 million in 2007.

(5) Not deducted from the amount is $8.8 million, $13.8 million, $92.3 million and $96.5 million of proceeds received principally from the sale of interests in oil and gas properties during the years ended December 31, 2004, 2005, 2006 and 2007, respectively.

	As of December 31,
	2003		2004		2005		2006		2007
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	16,034	$	99,926	$	68,282	$	41,322	$	60,285
Other current assets		19,613		37,964		73,036		97,185		71,142
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment		307,920		549,182		737,992		951,132		1,182,664
Other property and equipment, net of depreciation		1,539		2,983		7,956		11,967		10,865
Oil and natural gas properties held for sale, net of accumulated depreciation, depletion, amortization and impairment		—		—		—		75,496		2,303
Other assets		2,663		6,103		1,679		10,299		2,428
Total assets	$	347,769	$	696,158	$	888,945	$	1,187,401	$	1,329,687
Current liabilities	$	46,156	$	62,106	$	132,798	$	119,795	$	139,568
Long-term debt		58,900		—		86,000		188,000		274,000
Other long-term liabilities		4,387		14,320		39,364		123,209		142,608
Stockholders’ equity		238,326		619,732		630,783		756,397		773,511
Total liabilities and stockholders’ equity	$	347,769	$	696,158	$	888,945	$	1,187,401	$	1,329,687

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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 “Item 1A. Risk Factors” and the “Cautionary Note Regarding Forward-Looking Statements”, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Overview

We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. On December 15, 2004, we completed our initial public offering in which 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. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices. Approximately 96% of our December 2007 production volume 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”). In May 2006, we acquired properties in the Powder River Basin consisting of approximately 84,300 gross (52,000 net) acres of oil and gas leasehold interests of coal bed methane properties in the Powder River Basin of Wyoming. In June 2007, we sold our Williston Basin properties. A summary of our significant property acquisitions is as follows:

Primary Locations of Acquired Properties	Date Acquired	Purchase Price
		(in millions)
Wind River Basin	March 2002	$	74
Uinta Basin	April 2002		8
Wind River, Powder River and Williston Basins	December 2002		62
Powder River Basin	March 2003		35
Piceance Basin	September 2004		137
Powder River Basin	May 2006		79

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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.

Our acquisitions were financed with a combination of funding from equity investments in us, our credit facility, cash flow from operations and, in the case of the Piceance Basin properties, a bridge loan that we repaid in December 2004 with a portion of the proceeds from our initial public offering.

As of December 31, 2007, we had 558 Bcfe of estimated net proved reserves with a Standardized Measure of $941 million (at $6.04 CIGRM and $92.50 WTI). As of December 31, 2006, we had 428 Bcfe of estimated net proved reserves with a Standardized Measure of $529 million (at $4.46 CIGRM and $61.06 WTI), while at December 31, 2005, we had 341 Bcfe of estimated net proved reserves with a Standardized Measure of $782 million (at $7.72 CIGRM and $61.04 WTI).

The average sales prices received for natural gas, before the effects of hedging contracts, for the years ended December 31, 2005, 2006 and 2007 were $7.73 per Mcf, $5.94 per Mcf and $4.37 per Mcf, respectively, and $53.69 per Bbl, $59.39 per Bbl and $61.18 per Bbl, respectively, for oil.

Higher oil and natural gas prices over the past several years 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, particularly in the Rockies, 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 we received in 2007. In addition, we hedge 50%-70% of our expected production on a forward 12-month basis. 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 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.

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Results of Operations

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

	Year Ended December 31, 2005		Year Ended December 31, 2006		2005 to 2006 Increase (Decrease)					Year Ended December 31, 2007		2006 to 2007 Increase (Decrease)
					Amount			Percent				Amount			Percent
	(in thousands)
Operating Results:
Operating Revenues
Oil and gas production	$	284,406	$	344,127	$	59,721		21	%	$	374,956	$	30,829		9	%
Other		4,353		31,202		26,849		617	%		15,314		(15,888	)	(51	)%
Operating Expenses
Lease operating expense		19,585		29,768		10,183		52	%		41,643		11,875		40	%
Gathering and transportation expense		11,950		15,721		3,771		32	%		23,163		7,442		47	%
Production tax expense		33,465		25,886		(7,579	)	(23	)%		22,744		(3,142	)	(12	)%
Exploration expense		10,930		9,390		(1,540	)	(14	)%		8,755		(635	)	(7	)%
Impairment, dry hole costs and abandonment expense		55,353		12,824		(42,529	)	(77	)%		25,322		12,498		97	%
Depreciation, depletion and amortization		89,499		138,549		49,050		55	%		172,054		33,505		24	%
General and administrative expense		24,540		27,752		3,212		13	%		32,074		4,322		16	%
Non-cash stock-based compensation expense(1)		3,212		6,491		3,279		102	%		10,154		3,663		56	%
Total operating expenses	$	248,534	$	266,381	$	17,847		7	%	$	335,909	$	69,528		26	%
Production Data:
Natural gas (MMcf)		36,287		47,928		11,641		32	%		57,678		9,750		20	%
Oil (MBbls)		523		696		173		33	%		586		(110	)	(16	)%
Combined volumes (MMcfe)		39,425		52,104		12,679		32	%		61,194		9,090		17	%
Daily combined volumes (Mmcfe/d)		108		143		35		32	%		168		25		17	%
Average Prices(2):
Natural gas (per Mcf)	$	7.16	$	6.40	$	(0.76	)	(11	)%	$	5.89	$	(0.51	)	(8	)%
Oil (per Bbl)		46.68		53.50		6.82		15	%		59.87		6.37		12	%
Combined (per Mcfe)		7.21		6.60		(0.61	)	(8	)%		6.13		(0.47	)	(7	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.50	$	0.57	$	0.07		14	%	$	0.68	$	0.11		19	%
Gathering and transportation expense		0.30		0.30		0.00		0	%		0.38		0.08		27	%
Production tax expense		0.85		0.50		(0.35	)	(41	)%		0.37		(0.13	)	(26	)%
Depreciation, depletion and amortization(3)		2.27		2.69		0.40		18	%		2.87		0.18		7	%
General and administrative expense(4)		0.62		0.53		(0.09	)	(15	)%		0.52		(0.01	)	(2	)%

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $27.8 million, $34.2 million and $42.2 million for the years ended December 31, 2005, 2006 and 2007, respectively, in the Consolidated Statement of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful, because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, who may have higher or lower costs associated with equity grants.

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(2) Average prices shown in the table are net of the effects of our realized hedging transactions. As a result of our realized hedging transactions, natural gas production revenues were reduced by $20.7 million for the year ended 2005 and increased by $22.2 million and $87.7 million for the years ended December 31, 2006 and 2007, respectively. Oil production revenues were reduced by $3.7 million, $4.1 million and $0.8 million for the years ended December 31, 2005, 2006 and 2007, respectively. Before the effect of hedging contracts, the average price we received for natural gas in 2007 was $4.37 per Mcf compared with $5.94 per Mcf in 2006 and $7.73 per Mcf in 2005, and the average price we received for oil in 2007 was $61.18 per Bbl compared to $59.39 per Bbl in 2006 and $53.69 per Bbl in 2005.

(3) The depreciation, depletion and amortization (“DD&A”) per Mcfe as calculated based on the DD&A expense and MMcfe production data presented in the table for the years ended December 31, 2006 and 2007 is $2.66 and $2.81, respectively. However, the DD&A rates per Mcfe for the years ended December 31, 2006 and 2007 of $2.69 and $2.87, as presented, exclude production of 473 MMcfe and 1,198 MMcfe, respectively, associated with our properties that were classified as held for sale in the Powder River and Williston Basins and the properties that remain held for sale in the DJ Basin, as these were not depleted during portions of 2006 and all of 2007.

(4) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Consolidated Statements of Operations, were $0.70, $0.66 and $0.69 for the years ended December 31, 2005, 2006 and 2007, respectively.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Production Revenues. Production revenues increased from $344.1 million for the year ended December 31, 2006 to $375.0 million for the year ended December 31, 2007 due to a 17% increase in production, offset by a decrease in natural gas prices after the effect of realized hedges. The 2007 average CIGRM first-of-market price was 29% lower than in 2006. The net decrease in prices on a per Mcfe basis lowered production revenues by approximately $24.9 million, while production increases added approximately $55.8 million of production revenues, after natural production declines, so that new production from our drilling program more than offset natural production declines. Significant decreases in product prices significantly reduce our revenues from existing properties. See “—Quantitative and Qualitative Disclosure about Market Risk.”

Total production volumes for the 2007 calendar year of 61.2 Bcfe increased 17% from 2006 with increases in production from the Uinta and Piceance Basins, which increased 57% and 43%, respectively. The increase in production was partially offset by decreases in the Williston Basin of 52% (which we sold on June 22, 2007), the Wind River Basin of 36% and the Powder River Basins of 17%. Unscheduled third party plant downtime, pipeline curtailments, compressor maintenance and intentional well shut-ins due to low gas daily prices in the Rocky Mountain region resulted in production volumes being approximately 3.0 Bcf lower than well capacity for the year ended December 31, 2007. Additional information concerning production is in the following table.

	Year Ended December 31, 2006			Year Ended December 31, 2007			% Increase/(Decrease)
	Oil	Natural Gas	Total	Oil	Natural Gas	Total	Oil		Natural Gas		Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)		(MMcf)		(MMcfe)
Uinta Basin	43	16,195	16,453	49	25,536	25,830	14	%	58	%	57	%
Piceance Basin	193	13,377	14,535	292	19,031	20,783	51	%	42	%	43	%
Wind River Basin	46	11,156	11,432	36	7,156	7,372	(22	)%	(36	)%	(36	)%
Powder River Basin	—	7,002	7,002	—	5,828	5,828	—		(17	)%	(17	)%
Williston Basin(1)	389	145	2,479	184	74	1,178	(53	)%	(49	)%	(52	)%
Other	25	53	203	25	53	203	—		—		—
Total	696	47,928	52,104	586	57,678	61,194	(16	)%	20	%	17	%

(1) Includes production from Williston Basin properties through the closing date of the sale on June 22, 2007.

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The production increase in the Uinta Basin reflects our continued exploration and development activities in the West Tavaputs and Blacktail Ridge fields. During the year ended December 31, 2007, we had initial sales on 36 new gross wells. The production increase in the Piceance Basin is the result of our continued development activities, with initial sales on 81 new gross wells. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2007, with no significant drilling or recompletion activities to offset these declines. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane well and production of natural gas while dewatering occurs. This was partially offset by initial sales on 123 new gross wells for the year ended December 31, 2007. As of December 31, 2007, we had 121 net operated coal bed methane wells in the dewatering stage.

Hedging Activities. In 2007, we hedged approximately 63% of our natural gas volumes and 53% of our oil volumes, resulting in gas revenues of $87.7 million, offset by a reduction in oil revenues of $0.8 million. In 2006, approximately 43% of our natural gas volumes and 39% of our oil volumes were hedged, resulting in an increase in gas revenues of $22.2 million, offset by a reduction in oil revenues of $4.1 million.

Other Operating Revenues. Other operating revenues decreased from $31.2 million for the year ended December 31, 2006 to $15.3 million for the year ended December 31, 2007. Other operating revenues for 2006 consisted of gains realized from joint exploration agreements entered into and other property sales in the Powder River, Wind River and DJ Basins. Other operating revenues for 2007 primarily consisted of a gain realized on the sale of the Williston Basin properties, along with gains realized from joint exploration agreements entered into in the Paradox and Uinta Basins.

Lease Operating Expense. The increase in lease operating expense from $0.57 per Mcfe in 2006 compared to $0.68 in 2007, is primarily the result of increased expenses in the Powder River, Wind River and Piceance Basins. Lease operating expense increased in the Powder River Basin from $1.05 per Mcfe in 2006 to $1.65 per Mcfe in 2007 due to substantially higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. Lease operating expenses, on a per-unit basis, in the Powder River Basin were also adversely affected by the basin-wide pipeline curtailments. As of December 31, 2007, we had 121 net operated coal bed methane wells in the dewatering stage. Lease operating expense increased in the Wind River Basin from $0.60 per Mcfe in 2006 to $0.97 per Mcfe in 2007 due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields, while actual lease operating expenses have remained relatively stable. Lease operating expense increased in the Piceance Basin from $0.36 per Mcfe in 2006 to $0.51 per Mcfe in 2007 as a result of higher than expected water transportation and disposal costs. The following table displays the lease operating expense per Mcfe by basin:

	Year Ended December 31, 2006				Year Ended December 31, 2007		% Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(% per Mcfe)
Uinta Basin	$	5,805	$	0.35	$	10,715	$	0.41	17	%
Piceance Basin		5,172		0.36		10,680		0.51	42	%
Powder River Basin		7,363		1.05		9,614		1.65	57	%
Wind River Basin		6,861		0.60		7,131		0.97	62	%
Williston Basin		3,730		1.50		2,732		2.32	55	%
Other		837		4.12		771		3.80	(8	)%
Total	$	29,768		0.57	$	41,643		0.68	19	%

Lease operating expense declined from $0.79 per Mcfe in the first half of 2007 to $0.58 per Mcfe in the second half of 2007 as a result of efficiencies gained after the installation of a water management system in the Piceance Basin, an overall reduction in field overtime, fewer workovers in all fields, as well as increased production.

49

Gathering and Transportation Expense. Gathering and transportation expense increased from $0.30 per Mcfe in 2006 to $0.38 per Mcfe in 2007 due to additional long-term firm transportation and firm processing contracts entered into throughout 2007. We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital expenditure program in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Uinta and Piceance Basins to avoid possible production curtailments that may arise due to limited processing capacity. Included in the above gathering and transportation expense is $0.07 and $0.09 per Mcfe of transportation expense along with $0.01 and $0.06 per Mcfe of processing expense from long-term contracts for the years ended December 31, 2006 and 2007, respectively.

Production Tax Expense. Total production taxes decreased from $25.9 million in 2006 to $22.7 million in 2007. Although our production volumes and production revenues increased, our overall production taxes decreased, because a larger portion of our revenues came from areas with lower tax rates, such as the Piceance and Uinta Basins as compared to the Wind River and Powder River Basins. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 7.9% for 2006 and for 2007. Production taxes are primarily based on the wellhead values of production and the tax rates that vary across the different areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect.

Exploration Expense. Exploration costs decreased from $9.4 million in 2006 to $8.8 million in 2007. Exploration costs for 2006 consisted of $8.1 million for seismic programs, principally in the Montana Overthrust, Wind River, Paradox and DJ Basins, and $1.3 million for delay rentals and other costs. Exploration costs for 2007 consisted of $7.3 million for seismic programs, principally in the Montana Overthrust, Paradox and Big Horn Basins, along with $1.5 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased from $12.8 million in 2006 to $25.3 million in 2007. During 2006, impairment expense was $1.2 million, abandonment expenses were $1.6 million and dry hole costs were $10.0 million for wells drilled primarily in the Uinta and Williston Basins. During 2007, impairment expense was $2.3 million, abandonment expenses were $2.7 million and dry holes and partial dry holes in the Wind River (non-operated), Paradox and Uinta Basins were $12.6 million. In addition, we also expensed $7.7 million related to two wells in the Montana Overthrust area that were tested and determined to be non-commercial in the zones below the Cody Shale; thus, a proportionate share of the well costs were expensed.

We evaluated the impairment of our oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated fair value, we will adjust the carrying amount of the properties to fair value through a charge to impairment expense. For our Tri-State properties within the DJ Basin, based upon our fair value analysis, we recognized a $2.3 million non-cash impairment charge in 2007. We sold these properties in early 2008.

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We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of December 31, 2007 pending determination of whether the wells will be assigned proved reserves. The following table does not include $8.6 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2007:

	Time Elapsed Since Drilling Completed
	0-3 Months		4-6 Months		7-12 Months		> 12 Months		Total
	(in thousands)
Wells for which drilling has been completed	$	29,315	$	19,317	$	12,523	$	12,421	$	73,576

The majority of the $12.4 million of exploratory well costs that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to 24 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) was $172.1 million in 2007 compared to $138.5 million in 2006. Of the increase, $22.6 million is due to an increase in production, excluding the properties held for sale in the Williston and DJ Basins, and $11.0 million is due to an increased DD&A rate for 2007. During 2006, the weighted average depletion rate was $2.69 per Mcfe. During 2007, the weighted average depletion rate was $2.87 per Mcfe. The DD&A rates for 2006 and 2007 exclude production of 473 MMcfe and 1,198 MMcfe, respectively, associated with our properties held for sale in the Powder River and Williston Basins and the properties that remain held for sale in the DJ Basin, as these were not depleted during portions of 2006 and all of 2007. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased from $27.8 million in 2006 to $32.1 million in 2007. This increase is primarily due to increased personnel required for our capital program and production levels. As of December 31, 2007, we had 155 full-time employees in our corporate office compared to 138 as of December 31, 2006. However, on a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, decreased from $0.53 per Mcfe in 2006 to $0.52 per Mcfe in 2007 due to increased production.

Non-cash charges for stock-based compensation were $10.2 million in 2007 compared to $6.5 million in 2006. Non-cash stock-based compensation for 2006 and 2007 is related to vesting of our stock option plans and nonvested equity shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation is primarily due to the additional equity awards that were granted during the later part of 2006 and in 2007, including a new performance-based share program that was approved on May 9, 2007.

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The components of non-cash stock-based compensation for 2006 and 2007 are shown in the following table.

	Year Ended December 31,
	2006		2007
	(in thousands)
Restricted common stock	$	38	$	—
Stock options and nonvested equity shares of common stock		5,938		9,372
Shares issued for 401(k) plan		515		619
Shares issued for directors’ fees		—		163
Total	$	6,491	$	10,154

Interest Expense. Interest expense increased to $12.8 million in 2007 from $10.3 million in 2006. The increase is due to higher average outstanding balances under our credit facility during 2007 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the year ended December 31, 2007 was $196.0 million compared to $158.9 million in 2006.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use and, as a result, we had not capitalized any interest expense until the third quarter of 2006. The weighted average interest rates, including interest and commitment fees paid on the unused portion of our credit facility, amortization of deferred financing costs and the effects of interest rate hedges, used to capitalize interest for the years ended December 31, 2006 and 2007 was 7.1%. We capitalized interest costs of $1.0 million and $1.6 million for the years ended December 31, 2006 and 2007, respectively.

Income Tax Expense. Our effective tax rates were 38.7% and 39.2% in 2006 and 2007, respectively. For both the 2006 and 2007 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees, and SFAS No. 123 (revised 2004),Share-Based Payment (“SFAS No. 123R”), that is not deductible for income tax purposes. Due to the tax deductions being created by our drilling activities, we expect that we will incur cash income tax liabilities relating only to the alternative minimum tax (“AMT”) in the next year. We have a significant deferred tax asset associated with net operating loss carryforwards (“NOLs”). It is more likely than not that we will use these NOLs to offset and minimize current tax liabilities, including AMT, in future years.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Production Revenues. Production revenues increased from $284.4 million for the year ended December 31, 2005 to $344.1 million for the year ended December 31, 2006 due to an increase in production, offset by decreases in natural gas prices. Production increases from the development of existing properties added approximately $83.7 million of production revenues, which were partially offset by lower natural gas prices that decreased revenues by $24.0 million. Significant decreases in product prices significantly reduce our revenues from existing properties. See “— Quantitative and Qualitative Disclosure about Market Risk”.

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Total production volumes for the 2006 calendar year increased 32% from 2005 with increases in production from the Uinta, Williston and Piceance Basins, which increased 115%, 3% and 179% respectively. The increase in production was partially offset by decreases in the Wind River and Powder River Basins, which decreased 27% and 17%, respectively, from 2005. Additional information concerning production is in the following table.

	Year Ended December 31,
	2005			2006
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)
Wind River Basin	68	15,157	15,565	46	11,156	11,432
Uinta Basin	8	7,612	7,660	43	16,195	16,453
Powder River Basin	—	8,405	8,405	—	7,002	7,002
Williston Basin	376	149	2,405	389	145	2,479
Piceance Basin	45	4,937	5,207	193	13,377	14,535
Other	26	27	183	25	53	203
Total	523	36,287	39,425	696	47,928	52,104

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2006. This decrease in production is partially offset by our new deep Lakota discovery well, the Bullfrog 33-19, which had first production in June 2006. The production increase in the Uinta Basin is due to development activities in West Tavaputs, including the exploration success of the Peters Point 4-12D-13-16 Deep well, which was put on production in November 2006, along with first production from our initial Lake Canyon discovery wells. Furthermore, the completion of a third party gas processing facility in mid-August 2006 increased our gross takeaway capacity in the West Tavaputs field by approximately 20 MMcf/d. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane well and production of natural gas while dewatering occurs, which are partially offset by the production from the properties we acquired from CH4 in early May 2006. In late August 2006, we sold the majority of the then producing properties acquired in the CH4 acquisition. As of December 31, 2006, we had 127 net operated coal bed methane wells in the dewatering stage. The production increase in the Piceance Basin is the result of our continued development activities.

Hedging Activities. In 2006, we hedged approximately 43% of our natural gas volumes and 39% of our oil volumes, resulting in an increase in gas revenues of $22.2 million, offset by a reduction in oil revenues of $4.1 million. In 2005, we hedged approximately 50% of our natural gas volumes and 49% of our oil volumes, resulting in a reduction in both natural gas and oil revenues of $20.7 million and $3.6 million respectively.

Other Operating Revenues. Other operating revenues increased from $4.4 million for the year ended December 31, 2005 to $31.2 million for the year ended December 31, 2006. The increase is primarily due to gains realized on joint exploration agreements and other property sales in the Powder River, Paradox, Williston, Wind River, Big Horn, Montana Overthrust, Uinta and DJ Basins.

Lease Operating Expense and Gathering and Transportation Expense. Our lease operating expense increased to $0.57 per Mcfe in 2006 compared to $0.50 in 2005, while our gathering and transportation expense remained consistent at $0.30 per Mcfe in 2006. The increase in lease operating expense is primarily due to an increase in the Powder River Basin from $0.60 per Mcfe in 2005 to $1.05 per Mcfe in 2006. This increase on a per Mcfe basis in the Powder River Basin is due to natural production declines in our mature fields and the higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. As of December 31, 2006, we had 127 net operated coal bed methane wells in the dewatering stage. Lease operating expense also increased in the Williston Basin from $1.10 per Mcfe in 2005 to $1.50 per Mcfe in 2006 as a result of the high volumes of water being produced from wells put onto production in 2006.

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We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital budget in future years. Included in the above gathering and transportation expense per Mcfe is $0.05 and $0.07 of transportation expense from long-term contracts for the years ended December 31, 2005 and 2006, respectively.

Production Tax Expense. Total production taxes decreased from $33.5 million in 2005 to $25.9 million in 2006. Although we realized higher production revenues from the increase in our production volumes, our overall production taxes decreased as a larger portion of our revenues were generated from areas with lower tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments decreased from 10.8% in 2005 to 7.9% in 2006. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas that we operate. As the ratio of our production changes from area to area, our production rate will either increase or decrease depending on the quantities produced from each area and the production tax rates in effect in each individual area.

Exploration Expense. Exploration expense decreased from $10.9 million in 2005 to $9.4 million in 2006. Exploration expense for 2005 includes $9.4 million for seismic programs principally in the Uinta, Wind River and Big Horn Basins and Montana Overthrust, and $1.5 million for delay rentals and other costs. Exploration expense for 2006 included $8.1 million for seismic programs, principally in the Montana Overthrust, Wind River, Paradox, and DJ Basins, and $1.3 million for delay rentals and other costs.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense decreased from $55.3 million in 2005 to $12.8 million in 2006. During 2005, impairment expense was $42.7 million, dry hole costs were $11.1 million for dry holes in the Wind River, Green River, Uinta and Williston Basins, and abandonment expense was $1.5 million. The impairment expense is the result of a $29.5 million impairment charge in the Cooper Reservoir field, an $11.3 million impairment charge in the Talon field, and a $1.9 million impairment charge in the East Madden field, all of which are located in the Wind River Basin. During the quarter ended June 30, 2005, production from existing and recently drilled infill wells in the Cooper Reservoir field declined more rapidly than anticipated, indicating well interference and limited opportunities to increase well density. In the Talon and East Madden fields, production from exploratory wells was at a rate that was not economic based on the capital investment. During 2006, impairment expense was $1.2 million, dry hole costs were $10.0 million for dry holes primarily in the Uinta and Williston Basins, and abandonment expense was $1.6 million. The impairment expense in 2006 related to our Cedar Camp and Tumbleweed properties within the Uinta Basin based upon our fair value analysis. We sold these properties in December 2006. Included in $10.0 million of dry hole costs for 2006 is $3.5 million related to the #1DLB, an exploration well located in the Lake Canyon area of the Uinta Basin. This well, which was completed in April 2006, was tested and determined to be commercial in the Wasatch formation and non-commercial in the zones below the Wasatch; thus, a proportionate share of the well cost is being expensed.

The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of December 31, 2006 pending determination of whether the wells will be assigned proved reserves. The following table does not include $18.6 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2006:

	Time Elapsed Since Drilling Completed
	0-3 Months		4-6 Months		7-12 Months		> 12 Months		Total
	(in thousands)
Wells for which drilling has completed	$	11,453	$	11,501	$	6,821	$	21,179	$	50,954

Depreciation, Depletion and Amortization. DD&A expense was $138.5 million in 2006 compared to $89.5 million in 2005. In 2006, $27.7 million of the increase was due to the 32% increase in production and $21.3

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million was due to an increased DD&A rate for 2006. In 2005, the weighted average DD&A rate was $2.27 per Mcfe compared to $2.69 per Mcfe in 2006. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. In 2006, the relationship of capital expenditures, proved reserves and production from certain producing areas yielded a higher depletion rate than 2005. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased $3.2 million from $24.5 million in 2005 to $27.8 million in 2006. This increase was primarily due to increased personnel required to support our capital program and production levels. As of December 31, 2006, we had 138 full-time employees in our corporate office compared to 127 as of December 31, 2005. We also incurred $0.4 million of nonrecurring expenses during the year ended December 31, 2006 as a result of exploring financing options. On a per unit of production basis, general and administrative expense, excluding non-cash stock based compensation, decreased from $0.62 per Mcfe in 2005 to $0.53 per Mcfe in 2006.

Non-cash stock-based compensation expense included in general and administrative expense increased from $3.2 million in 2005 to $6.5 million in 2006. Non-cash stock-based compensation for 2005 and 2006 is related to vesting of the restricted common stock issued to management and employees upon our formation, our stock option plans and nonvested equity shares of common stock issued to employees. The increase in non-cash stock-based compensation expense is primarily due to the increased number of equity awards that were granted during the later part of 2005 and in 2006. Equity awards to employees generally were made in the first quarter of 2006 and were not made in the first quarter of 2005 because of the awards previously made in connection with our initial public offering in December 2004. The increase is also due to the acceleration of vesting of share-based awards for certain of our officers who left us during 2006. Additionally, we amended our 401(k) Plan on January 1, 2006 to increase our match of the employees’ contribution from 4% up to 6%, of which 50% of the match is made with our common stock.

The components of non-cash stock-based compensation for 2005 and 2006 are shown in the following table.

	Year Ended December 31,
	2005		2006
	(in thousands)
Restricted common stock	$	489	$	38
Stock options and nonvested equity shares of common stock		2,723		5,938
Shares issued for 401(k) plan		—		515
Total	$	3,212	$	6,491

Restricted common stock, which was issued to our founding management and employees of the Company on January 30, 2002, was subject to dual vesting provisions of: (1) one share vesting for every $141.62355 received from investors in Series B Preferred Stock (“dollar vesting”), and (2) 20% vesting upon purchase and an additional 20% vesting each year for four years after purchase (“time vesting”). These restricted shares vest at the later to occur of time vesting and dollar vesting. As of January 31, 2006, the restricted common stock was 100% dollar vested and 100% time vested and the remaining compensation expense was fully recognized.

Interest Expense. Interest expense increased $7.1 million to $10.3 million in 2006 compared to $3.2 million in 2005. The increase was due to higher debt levels during 2006 to fund exploration and development activities and a lack of a need to draw on our credit facility until the third quarter of 2005 due to the availability of the proceeds from our initial public offering in December 2004. As a result, the interest expense during the year of 2005 was primarily comprised of debt commitment fees and amortization of deferred financing costs. The

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weighted average outstanding balances under our credit facility for the years ended December 31, 2005 and 2006 were $23.4 million and $158.9 million, respectively.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. Until the third quarter of 2006, we had not capitalized any interest expense. The weighted average interest rate used to capitalize interest for the current year was 7.1%, including interest and commitment fees paid on the unused portion of the credit facility and amortization of deferred financing costs. We capitalized interest costs of $1.0 million for the year ended December 31, 2006.

Income Tax Expense. Our effective tax rate was 38.7% in 2006 and 39.0% in 2005. Our effective tax rates for 2006 and 2005 differ from the federal and state statutory rates primarily because of the amount of stock-based compensation expense recorded for financial statement purposes under APB Opinion No. 25 and SFAS No. 123R that is not deductible for income tax purposes. These non-deductible permanent differences caused our effective tax rate to be higher than the rate that would have been effective if the costs would have been deductible. All of our income tax benefits and liabilities to date are deferred. While we have net operating loss carryforwards and deductions from our drilling activities, we are subject to the federal alternative minimum tax (“AMT”) and state income tax. We expect to incur cash payments associated with these taxes within the next year.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been sales and other issuances of equity securities, net cash provided by operating activities, bank credit facilities, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the exploration, development and acquisition of natural gas and oil properties. As we pursue profitable reserve and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing.

At December 31, 2007, our balance sheet reflected a cash and cash equivalents balance of $60.3 million with a balance of $274.0 million outstanding under our credit facility. At December 31, 2007, the borrowing base under our credit facility was $385.0 million. We are in the process of obtaining an increase in our borrowing base and expect a significant increase based on our year-end 2007 proved reserves and hedge position.

Cash Flow from Operating Activities

Net cash provided by operating activities was $184.3 million, $236.9 million and $251.5 million in 2005, 2006 and 2007, respectively. The increases in net cash provided by operating activities were primarily due to an increase in oil and gas revenues, along with the changes in current assets and liabilities, which was offset by increased expenses, as discussed above in “—Results of Operations”. Changes in current assets and liabilities reduced cash flow from operations by $0.02 million and $1.4 million in 2005 and 2006, respectively, and increased cash flow from operations by $11.7 million in 2007.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “—Quantitative and Qualitative Disclosure About Market Risk” below.

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To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices, we have entered into financial commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. At December 31, 2007, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2008, 2009 and 2010 production. Our natural gas and oil derivative financial instruments are accounted in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.

In addition to financial transactions, we are a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

All derivative instruments, other than those that meet the normal purchase and sales exceptions as mentioned above, are recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Realized gains and losses on cash flow hedges are transferred from comprehensive income, recognized in earnings and included within oil and gas production revenues in the Consolidated Statements of Operations as the associated production occurs. Unrealized gains and losses from the change in the fair value and realized gains and losses of derivative instruments that do not qualify as cash flow hedges, as well as the ineffective portion of hedge derivatives are reported in earnings in the Consolidated Statements of Operations.

At December 31, 2007, the estimated fair value of all of our derivative instruments was a net asset of $7.9 million comprised of current and noncurrent assets and liabilities. We will reclassify the appropriate amounts to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of December 31, 2007 to be reclassified from other comprehensive income to net income in the next 12 months would be approximately $5.6 million for our cash flow hedges. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our cash flow hedges will occur by the end of the originally specified time periods. Ineffectiveness related to our derivative instruments was de minimis.

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The Company has in place the following swap contracts and cashless collars (purchased put options and written call options) as of December 31, 2007 in order to hedge a portion of our natural gas and oil production for 2008, 2009 and 2010. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Price		Weighted Average Ceiling Price		Weighted Average Fixed Price		Index Price(1)	Fair Market Value
										(in thousands)
Cashless Collars:
2008
Natural gas	12,810,000	MMBtu	$	6.50	$	10.00		N/A	CIGRM	$	8,202
Oil	192,150	Bbls	$	70.48	$	81.62		N/A	WTI	$	(2,533	)
2009
Oil	18,250	Bbls	$	75.00	$	100.00		N/A	WTI	$	(16	)
Swap Contracts:
2008
Natural gas	34,325,000	MMBtu		N/A		N/A	$	6.77	CIGRM	$	12,282
Natural gas	7,160,000	MMBtu		N/A		N/A	$	6.80	PEPL	$	1,119
Oil	210,450	Bbls		N/A		N/A	$	73.84	WTI	$	(3,972	)
2009
Natural gas	21,710,000	MMBtu		N/A		N/A	$	7.01	CIGRM	$	(2,708	)
Oil	136,875	Bbls		N/A		N/A	$	74.41	WTI	$	(1,763	)
2010
Natural gas	10,360,000	MMBtu		N/A		N/A	$	6.78	CIGRM	$	(2,672	)

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains and PEPL refers to Panhandle Eastern Pipe Line Company price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

The following table includes all hedges entered into subsequent to December 31, 2007 through February 15, 2008.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Price	Weighted Average Ceiling Price	Weighted Average Fixed Price		Index Price
Swap Contracts:
2008
Natural gas	610,000	MMBtu	N/A	N/A	$	7.25	CIGRM
Natural gas	549,000	MMBtu	N/A	N/A	$	7.28	PEPL
2009
Natural gas	5,900,000	MMBtu	N/A	N/A	$	7.47	CIGRM
Natural gas	3,285,000	MMBtu	N/A	N/A	$	7.56	PEPL
2010
Natural gas	900,000	MMbtu	N/A	N/A	$	7.76	CIGRM
Natural gas	2,736,000	MMbtu	N/A	N/A	$	7.63	PEPL

By removing the price volatility from a portion of our natural gas and oil production for 2008, 2009 and 2010, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

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Capital Expenditures.

Our capital expenditures are summarized in the following tables:

	Year Ended December 31,
Basin/Area	2005		2006		2007
	(in millions)
Uinta	$	82.2	$	120.0	$	166.4
Piceance		129.5		138.2		180.3
Powder River		28.7		148.0		39.3
Wind River		58.3		35.3		10.5
Other		48.7		59.7		47.2
Total	$	347.4	$	501.2	$	443.7

	Year Ended December 31,
	2005	2006		2007
	(in millions)
Acquisitions of proved and unevaluated properties and other real estate	28.2	159.3	(1)	23.9
Drilling, development, exploration and exploitation of natural gas and oil properties	293.1	318.5	(2)	383.4
Geologic and geophysical costs and exploratory dry holes and abandonment costs	23.6	21.0		31.8
Furniture, fixtures and equipment	2.5	2.4		4.6
Total(3)	347.4	501.2		443.7

(1) Includes $36.8 million of non-cash deferred tax liability associated with the difference between the tax basis of the properties acquired in the CH4 acquisition and the book basis attributed to the properties under the purchase method of accounting.

(2) Includes related gathering and facilities, but excludes exploratory dry holes, which are expensed under successful efforts accounting as exploration expense.

(3) For the years ended December 31, 2005, 2006 and 2007, we received $13.8 million, $87.6 million and $96.5 million, respectively, of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.

Unevaluated properties increased $15.1 million to $236.3 million at December 31, 2007, including $2.0 million related to unevaluated properties in the DJ Basin and Hingeline Prospect that are currently classified as held for sale at December 31, 2007, from $221.2 million at December 31, 2006, including $18.2 million related to unevaluated properties in the Williston and DJ Basins that were classified as held for sale. The increase is principally from increases in leasehold acquisitions and wells in progress resulting from increased development and exploratory drilling activity during the year ended December 31, 2007.

Excluding material acquisitions, our current capital budget for 2008 is $550-600 million, of which we plan to spend approximately $440-485 million for development drilling and facilities, and up to $110 million on exploration drilling, leasehold acquisitions, geologic and geophysical costs, equipment and other costs. While we may reallocate capital among our areas of activity, our approved budget provides that we plan to spend $230-240 million in the Piceance, $220-240 million in the Uinta, $35-40 million in the Wind River, $35-40 million in the Powder River and up to $75 million in other areas. Based upon our current natural gas and oil price expectations and our hedge position for 2008, we anticipate that our operating cash flow and available borrowing capacity under our credit facility will be sufficient to fund our capital expenditures at current levels for the next twelve months. We also may seek to issue other debt securities to repay amounts outstanding under our credit facility. Currently, credit markets are turbulent, which may limit our access to them or require us to pay higher costs. Also, future cash flows are subject to a number of variables, including our level of natural gas and oil production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts to maintain planned levels of capital expenditures.

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The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow, availability of financing and other factors both within and outside our control.

Financing Activities

Credit Facility.On March 17, 2006, we amended our credit facility (the “Amended Credit Facility”). The Amended Credit Facility, which matures on March 17, 2011, had commitments of $400.0 million, which were expanded to $545.0 million as of November 6, 2007 with the addition of new lenders, and had an initial borrowing base of $280.0 million. Based on mid-year 2007 reserves and our hedge position, the borrowing base was increased to $385.0 million on November 6, 2007. Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge position, and estimated future cash flows from those reserves. We expect that the borrowing base will be increased significantly based on our year-end 2007 proved reserves and hedge position. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.0% to 1.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. We pay commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of our proved reserves, and the pledge of all of the stock of our subsidiaries. For information concerning the effect of changes in interest rates on interest payments under this facility, see “—Quantitative and Qualitative Disclosure About Market Risk—Interest Rate Risks” below.

As of December 31, 2006 and 2007, borrowings under the Amended Credit Facility totaled $188.0 and $274.0 million, respectively. The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods.

In December 2006, we entered into two interest rate derivative contracts to manage our exposure to changes in interest rates. The first contract was a floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. Under the swap, we will make payments to (or receive payments from) the contract counterparty when the variable rate of one-month LIBOR falls below (or exceeds) the fixed rate of 4.70%. Under the collar, we will make payments to (or receive payments from) the contract counterparty when the variable rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. Our interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133. Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. Ineffectiveness related to such derivative instruments was de minimis.

During the year ended December 31, 2007, we had received $0.1 million in settlement payments with respect to our interest rate hedges, which were deducted from interest expense during the year. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods and as of December 31, 2007, based on current projected interest rates, the net amount to be reclassified from accumulated other comprehensive income to net income during 2008 would be a net, after-tax reduction of approximately $0.1 million. At December 31, 2007, the estimated fair value of the interest rate derivatives was a net liability of $0.3 million.

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Contractual Obligations.A summary of our contractual obligations as of and subsequent to December 31, 2007 is provided in the following table.

	Payments Due By Year
	2008		2009		2010		2011		2012		After 2013		Total
	(in thousands)
Long-term debt(1)	$	—	$	—	$	—	$	274,000	$	—	$	—	$	274,000
Other commitments for developing oil and gas properties		17,786		—		—		—		—		—		17,786
Office and office equipment leases and other		1,873		1,925		1,922		465		—		—		6,185
Firm transportation and processing agreements		22,514		23,291		23,365		23,479		23,596		131,532		247,777
Asset retirement obligations(2)(3)		801		5,247		1,401		1,800		1,160		25,440		35,849
Derivative liability(4)		2,408		4,656		2,672		—		—		—		9,736
Total	$	45,382	$	35,119	$	29,360	$	299,744	$	24,756	$	156,972	$	591,333

(1) Amount does not include future commitment fees, interest expense, or other fees on our credit facility because the credit facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “—Critical Accounting Policies and Estimates,” below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(3) Amount includes asset retirement obligations of $0.05 million associated with the DJ Basin, which is currently classified as held for sale.

(4) Derivative liabilities represent the fair value of liabilities for oil and gas commodity derivatives and interest rate derivatives as of December 31, 2007. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market risk. See “Critical Accounting Policies and Estimates,” below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

We have entered into contracts that provide firm processing rights and firm transportation capacity on pipeline systems. The remaining terms on these contracts range from 1 to 11 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us.

In addition to the commitments above, we have commitments for the purchase of facilities equipment as of and subsequent to December 31, 2007 for a total of $7.3 million.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under

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different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Properties

Our natural gas and oil exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the property has proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. If it is determined that these properties will not yield proved reserves, the related costs are expensed in the period in which that determination is made. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated properties are assessed periodically on a property-by-property basis and any impairment in value is charged to expense. Unevaluated properties whose acquisition costs are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unevaluated properties are subsequently determined to be productive, the related costs are transferred to proved oil and gas properties. Proceeds, up to an amount equal to the total carrying amount, from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss. We will record a gain on the sale of a partial interest in unevaluated leases for amounts equal to the excess of proceeds over our total carrying amount of such leases.

We review our proved natural gas and oil properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our gas and oil properties and compare these future cash flows to the carrying amount of the gas and oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the natural gas and oil properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate

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commensurate with the risk associated with realizing the expected cash flows projected. In 2005, we recorded impairment expense of $42.7 million related to the evaluated costs of the Talon, East Madden and Cooper Reservoir fields in Wyoming’s Wind River Basin. In 2006, we recorded impairment expense of $1.2 million related to our Cedar Camp and Tumbleweed properties within the Uinta Basin. In 2007, we recorded impairment expense of $2.3 million related to our Tri-State properties within the DJ Basin.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

Our investment in natural gas and oil properties includes an estimate of the future costs associated with dismantlement, abandonment and restoration of our properties. These costs are recorded as provided in SFAS No. 143,Accounting for Asset Retirement Obligations. The present value of the future costs are added to the capitalized costs of our oil and gas properties and recorded as a long-term liability. The capitalized cost is included in the natural gas and oil property costs that are depleted over the life of the assets.

The recognition of an asset retirement obligation (“ARO”) requires that management make numerous estimates, assumptions and judgments regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense.

The provision for depletion of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Oil is converted to natural gas equivalents, Mcfe, at the rate of one barrel to six Mcf. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which incorporate assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Oil and Gas Reserve Quantities

Our estimate of proved reserves is based on the 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. Our proved reserves are reviewed on a well-by-well basis by an independent engineering firm.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when reviewing our reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

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Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and natural gas liquids eventually recovered.

As of December 31, 2005, we revised our proved reserves downward by 24.7 Bcfe, excluding pricing revisions, primarily as a result of a reduction in proved undeveloped reserves in the Piceance Basin due to the use of completion techniques performed from January through September 2005 that yielded results lower than our expectations as of December 31, 2004. Completion techniques used in subsequent periods have yielded more favorable results, which are reflected in upward revisions in 2006 and 2007 reserve estimates in this area. The downward revision in the Piceance Basin in 2005 was 25.6 Bcfe. In this basin, 31% of the proved wells forecast as of December 31, 2004 were 25% below forecast as of December 31, 2005. The reserve variance between the independent reserve engineers and us as of December 31, 2004 for this basin was 13 Bcfe with the independent engineer at the lower estimate. The downward revision in the Powder River Basin in 2005 was 9.6 Bcfe. In this basin, 36% of the proved wells forecast as of December 31, 2004 were 25% below forecast as of December 31, 2005. The reserve variance between the independent reserve engineers and us as of December 31, 2004 for this basin was 3.8 Bcfe with the independent engineer at the lower estimate. An upward revision of 8.1 Bcfe occurred in the Uinta Basin in the West Tavaputs Field in 2005. In this basin, 31% of the proved wells forecast as of December 31, 2004 were 25% above forecast as of December 31, 2005. The reserve variance between the independent reserve engineers and BBC as of December 31, 2004 was 2.1 Bcfe with the independent engineer at the lower estimate.

During 2005, reviews of proved oil and gas properties in the Wind River Basin indicated a decline in the recoverability of their carrying value and the need for an impairment in the Cooper Reservoir, Talon and East Madden fields in the total amount of $42.7 million. We undertook a drilling program in Cooper Reservoir in 2003 and 2004 with the expectation of a specific economic reserve level. Actual reserve levels were less than our expectations which led to an impairment in the field in 2005. The impairments in the Talon and East Madden fields were the result of unsuccessful exploration programs.

As of December 31, 2006, we revised our proved reserves upward by 12.4 Bcfe, excluding pricing revisions. This revision was primarily the result of increased performance of wells drilled during the last half of 2005 and the first half of 2006. The pricing revision at year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil, relative to year-end 2005 prices of $7.72 per MMBtu and $61.04 per barrel of oil, was downward 33.8 Bcfe. These prices were adjusted by lease for quality, transportation fees and regional price differences.

As of December 31, 2007, we revised our proved reserves upward by 34.8 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped locations in the West Tavaputs field and continued improved performance of wells drilled in the West Tavaputs and Piceance fields. We also revised our 2007 year-end proved reserves upward by 19.4 Bcfe, as year-end 2007 pricing was $6.04 per MMBtu and $92.50 per barrel of oil, relative to year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil. These prices were adjusted by lease for quality, transportation fees and regional price differences.

Revenue Recognition

We record revenues from the sales of natural gas and oil when in the month that delivery to the customer has occurred and title has transferred. This occurs when natural gas or oil has been delivered to a pipeline or a tank lifting has occurred. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. However, differences have been insignificant.

We may have an interest with other producers in certain properties, in which case we use the sales method to account for natural gas imbalances. Under this method, revenue is recorded on the basis of natural gas actually

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sold by the Company. In addition, we record revenue for our share of natural gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. We also reduce revenue for other owners’ natural gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. Our remaining over- and under-produced gas balancing positions are considered in our proved reserves. Gas imbalances as of December 31, 2006 and 2007 were not significant.

Derivative Instruments and Hedging Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas and oil production by reducing our exposure to price fluctuations. We also enter into derivative contracts to mitigate the risk of interest rate fluctuations. For the year ended December 31, 2007, these transactions included swaps and cashless collars. We account for these activities pursuant to SFAS No. 133, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. SFAS No. 133 requires a company to formally document, at the inception of a hedge, the hedging relationship and the entity’s risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.

We may use derivative financial instruments which have not been designated as hedges under SFAS No. 133 because they still protect us from changes in commodity prices. These instruments, if used, will be marked to market with the resulting changes in fair value recorded in earnings.

As of December 31, 2007, the fair value of all of our derivative instruments was a net asset of $7.9 million, comprised of current and noncurrent assets and liabilities. The deferred income tax effect on the fair value of derivatives at December 31, 2007 totaled $3.0 million, which is recorded in current and noncurrent deferred tax liabilities.

Income Taxes and Uncertain Tax Positions

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the

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differences between financial statement and income tax reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

Effective January 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48,Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109 (“FIN No. 48”). In accordance with FIN No. 48, we recognize the benefit of a tax position, if that position is more likely than not of being sustained in an audit, based on the technical merits of the position. As a result of the implementation of FIN No. 48, we recognized a $0.2 million liability for unrecognized tax benefits.

Stock-based Compensation

The Company accounts for stock-based compensation in accordance with SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS No. 123R”), which revises SFAS No. 123,Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees. This statement requires us to record expense associated with the fair value of stock-based compensation. However, for awards granted before we were a public company (i.e. those granted prior to April 16, 2004, which is defined by SFAS No. 123R as the date we became a public company as a result of filing our Form S-1 registration statement with the SEC) we continue to use the minimum value method described under APB Opinion No. 25. For awards granted after we were a public company (i.e. those granted subsequent to April 16, 2004), and for new, modified, repurchased, or cancelled awards on or subsequent to our adoption of SFAS No. 123R on October 1, 2004, we recognized share-based employee compensation cost based on the fair value as computed under SFAS No. 123R.

The Company continues to account for certain stock options under the original provisions of APB Opinion No. 25 because those options were issued prior to April 16, 2004. Under APB Opinion No. 25, we recognize compensation expense only to the extent that the exercise price of the options granted exceed the market value of the underlying common stock on the date of grant. In total, we recorded non-cash stock-based compensation of $3.2 million, $6.5 million, and $9.9 million in 2005, 2006 and 2007, respectively, for option grants, option modifications, nonvested equity shares of common stock and nonvested performance-based equity shares of common stock.

Acquisitions

The establishment of our initial asset base since our founding in January 2002 has included material acquisitions of natural gas and oil properties, which have been accounted for using the purchase method of accounting.

Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill is assessed for impairment at least annually. In each of our acquisitions to date we have determined that the purchase price did not exceed the fair value of the net assets acquired. Therefore, no goodwill was recorded.

There are various assumptions we made in determining the fair values of acquired assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the natural gas and oil properties acquired. To determine the fair values of these properties, we prepare estimates of natural gas and oil reserves. These estimates are based on work performed by our engineers and that of outside consultants. The fair value of reserves acquired in an acquisition must be based on our estimates of future natural

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gas and oil prices and not the prices at the time of the acquisition. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They also are based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the acquisition based upon our cost of capital.

We also apply these same general principles in arriving at the fair value of unevaluated properties acquired in an acquisition. These unevaluated properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing probable and possible reserves, we apply a risk-weighting factor to probable and possible volumes to reduce the estimated reserve volumes. Additionally, we increase the discount factor, compared to proved reserves, to recognize the additional uncertainties related to determining the value of probable and possible reserves.

New Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. Where applicable, SFAS No. 157 simplifies and codifies fair value related guidance previously issued within U.S. generally accepted accounting principles. Although SFAS No. 157 does not require any new fair value measurements, its application may, for some entities, change current practice. SFAS No. 157 was effective for the Company beginning January 1, 2008. Although additional disclosure may be required about the information used to develop fair value measurements, the adoption of SFAS No. 157 is not expected to have a material impact on our financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. SFAS No. 159 was effective for the Company beginning January 1, 2008; however, the Company does not expect to elect the fair value option for any eligible financial instruments or other items.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS 141R”), which replaces FASB Statement No. 141,Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We expect SFAS No. 141R will have an impact on our consolidated financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after the effective date.

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Quantitative and Qualitative Disclosure About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collars contracts in place in during 2007, our annual income before income taxes, including hedge settlements, for the year ended December 31, 2007 would have decreased by approximately $3.1 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.3 million for each $1.00 per barrel change in crude oil prices.

We periodically enter into and anticipate entering into financial hedging activities with respect to a portion of our projected natural gas and oil production through various financial transactions which hedge the future prices received. These transactions may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. These financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. We do not hold or issue derivative instruments for speculative trading purposes.

In addition to financial transactions, we are a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

For the calendar year 2008, we currently have financial hedges in place for 55,454,000 MMBtu of natural gas production and 402,600 Bbls of oil production. We also have hedges in place for 30,895,000 MMBtu of natural gas production and 155,125 Bbls of oil production for 2009 and 13,996,000 MMBtu of natural gas production for 2010. These hedges are summarized in the tables presented above under “—Cash Flow from Operating Activities.”

Commodity Hedges

Commodity Swaps

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production in 2008, 2009 and 2010. The weighted average price we will receive in 2008 for natural gas is $6.77 per MMBtu for a CIGRM price and $6.83 for a PEPL price, $7.11 per MMBtu for a CIGRM price and $7.56 for

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a PEPL price in 2009, and $6.86 per MMBtu for a CIGRM price and $7.63 for a PEPL price in 2010. The weighted average price we will receive for oil is $73.84 per Bbl for 2008 and $74.41 per Bbl for 2009. The tables presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operating Activities,” provide the deliveries associated with these arrangements as of February 15, 2008.

In a swap transaction, the counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price.

Commodity Collars

Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2008 and 2009. The weighted average minimum, or floor, price we will receive in 2008 is $6.50 per MMBtu for a CIGRM price. The weighted average maximum, or ceiling, price we will receive in 2008 for a CIGRM price is $10.00 per MMBtu, respectively. We have also fixed the minimum price we will receive on a portion of our oil production in 2008 and 2009. We will receive a weighted average floor price of $70.48 and $75.00 per Bbl for a WTI price in 2008 and 2009, respectively, and a weighted average ceiling price of $81.62 and $100.00 per Bbl, respectively. The price collars also allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under “—Cash Flow from Operating Activities” provide the deliveries and floor and ceiling prices associated with these various arrangements as of December 31, 2007.

In a collar transaction, the counterparty is required to make a payment to us for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. We are required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the fixed ceiling price is below the settlement price. Neither party is required to make a payment if the settlement price falls between the fixed floor and ceiling price.

Interest Rate Risks

At December 31, 2007, we had debt outstanding of $274.0 million, which bears interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred on this debt for the years ended December 31, 2006 and 2007 was 7.1% and 6.3%, respectively. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2007 would have resulted in an estimated $2.0 million increase in interest expense assuming a similar average debt level to the year ended December 31, 2007.

Interest Rate Hedges

Through interest rate derivative contracts, we have attempted to mitigate exposure to changes in interest rates. We entered into an interest rate swap for a notional amount of $10 million for a fixed LIBOR rate of 4.70%. We also entered into an interest rate collar for a notional amount of $10 million in which the interest rate has fixed minimum and maximum LIBOR rates of 4.50% and 4.95%, respectively.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The information required by this item is included above in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk”.

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Item 8. Financial Statements and Supplementary Data

The information required by this item is included below in “Item 15. Exhibits, Financial Statement Schedules”.

Item 9. Changes in and Disagreements with Accountants and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined in Securities Exchange Act Rules 13a-15(d) and 15d-15(e), were, as of December 31, 2007, effective.

Management’s Report on Internal Control Over Financial Reporting.Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the company’s assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of the company’s management and directors; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.

Our independent registered public accounting firm has issued an attestation report on our internal controls over financial reporting. That report immediately follows this report.

/S/    FREDRICK J. BARRETT	/S/    ROBERT W. HOWARD
Fredrick J. Barrett Chairman and Chief Executive Officer February 26, 2008	Robert W. Howard Chief Financial Officer February 26, 2008

Changes in Internal Controls.There has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Bill Barrett Corporation

Denver, Colorado

We have audited the internal control over financial reporting of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007 of the Company and our report dated February 26, 2008, expressed an unqualified opinion on those financial statements.

/s/  Deloitte & Touche LLP

Denver, Colorado

February 26, 2008

71

Item 9B. Other Information

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information regarding our directors and executive officers will be included in an amendment to this Form 10-K or in the “Directors and Executive Officers” section of the proxy statement for the 2008 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

Item 11. Executive Compensation

Information regarding executive compensation will be included in an amendment to this Form 10-K or in the “Executive Compensation” section of the proxy statement for the 2008 annual meeting of stockholders in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the “Beneficial Owners of Securities” section of the proxy statement for the 2008 annual meeting of stockholders in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

Equity Compensation Plan Information

The following table provides aggregate information presented as of December 31, 2007 with respect to all compensation plans under which equity securities are authorized for issuance.

Plan Category	(a) Number of Securities to Be Issued Upon Exercise of Outstanding Options, Warrants and Rights	(b) Weighted Averaged Exercise Price of Outstanding Options, Warrants and Rights			(c) Number of Securities Remaining Available for Future Issuance (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by shareholders	3,481,962	$	28.25	(1)	1,686,791
Equity compensation plans not approved by shareholders	—		—		—
Total	3,481,962	$	28.25		1,686,791

(1) The weighted average exercise price relates to the 2,917,862 outstanding options included in column (a). It does not relate to the 564,100 nonvested equity shares of common stock (restricted stock) that also are included in column (a) but that do not contain an exercise price.

Item 13. Certain Relationships and Related Transactions and Director Independence

Information regarding certain relationships and related transactions will be included in an amendment to this Form 10-K or in the “Transactions Between the Company and Related Parties” and “Directors and Executive Officers” section of the proxy statement for the 2008 annual meeting of stockholders in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

72

Item 14. Principal Accounting Fees and Services

Information regarding principal accountant fees and services will be included in an amendment to this Form 10-K or in the “Fees to Independent Auditors” section of the proxy statement for the 2008 annual meeting of stockholders in either case, to be filed within 120 days after December 31, 2007, and is incorporated by reference to this report.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

See “Item 8. Financial Statements and Supplementary Data” on page F-1(a)

(a)(3) Exhibits.

Exhibit Number	Description of Exhibits
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
3.2	Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 by the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.2	Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.3	Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.4	Form of Rights Agreement concerning Shareholder Rights Plan, which includes, as Exhibit A thereto, the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and, as Exhibits B thereto, the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5	Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to the Company’s Registration Statement on Form 8-A.]
4.6	Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to the Company’s Registration Statement on Form 8-A.]
10.1(a)	Second Amended and Restated Credit Agreement, dated March 17, 2006, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 22, 2006.]

73

Exhibit Number	Description of Exhibits
10.1(b)	First Amendment to Second Amended and Restated Credit Agreement dated as November 6, 2007 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated November 7, 2007.]
10.2	Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.3(a)*	Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers. [Incorporated by reference to Exhibit 10.10(a) to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.3(b)*	Schedule of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.4*	Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.5(a)*	Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.5(b)*	Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b) to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.6*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to Amendment No. 3 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on September 22, 2004.]
10.7*	Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.8	Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.9	Regulatory Sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.10*	Form of Change in Control Severance Protection Agreement, revised as of November 16, 2006, for named executive officers. [Incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.]
10.11*	2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]

74

Exhibit Number	Description of Exhibits
10.12*	Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.]
10.13*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
14	Code of Business Conduct and Ethics [Incorporated by reference to Exhibit 14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.]
21.1	Subsidiaries of the Registrant. [Incorporated by reference to Exhibit 21.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.]
23.1**	Consent of Deloitte & Touche LLP.
23.2**	Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.
31.1**	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2**	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32**	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.

* Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3).

** Filed herewith.

75

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act Of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BILL BARRETT CORPORATION
Date: February 26, 2008	By:	/S/    FREDRICK J. BARRETT
		Fredrick J. Barrett Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act Of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/S/    FREDRICK J. BARRETT         Fredrick J. Barrett	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	February 26, 2008
/S/    ROBERT W. HOWARD         Robert W. Howard	Chief Financial Officer (Principal Financial Officer)	February 26, 2008
/S/    JOSEPH N. JAGGERS         Joseph N. Jaggers	Director; Chief Operating Officer and President	February 26, 2008
/S/    DAVID R. MACOSKO         David R. Macosko	Vice President—Accounting (Principal Accounting Officer)	February 26, 2008
/S/    JAMES M. FITZGIBBONS         James M. Fitzgibbons	Director	February 26, 2008
/S/    RANDY A. FOUTCH         Randy A. Foutch	Director	February 26, 2008
/S/    JEFFREY A. HARRIS         Jeffrey A. Harris	Director	February 26, 2008
/S/    JIM W. MOGG         Jim W. Mogg	Director	February 26, 2008
/S/    PHILIPPE S. E. SCHREIBER         Philippe S. E. Schreiber	Director	February 26, 2008
/S/    RANDY STEIN         Randy Stein	Director	February 26, 2008
/S/    MICHAEL E. WILEY         Michael E. Wiley	Director	February 26, 2008

76

FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

Bill Barrett Corporation
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets, December 31, 2006 and 2007	F-3
Consolidated Statements of Operations, for the years ended December 31, 2005, 2006 and 2007	F-4
Consolidated Statements of Stockholders’ Equity and Comprehensive Income, for the years ended December 31, 2005, 2006 and 2007	F-5
Consolidated Statements of Cash Flows, for the years ended December 31, 2005, 2006 and 2007	F-6
Notes to Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Bill Barrett Corporation Denver, Colorado

We have audited the accompanying consolidated balance sheets of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Bill Barrett Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/  Deloitte & Touche LLP

Denver, Colorado

February 26, 2008

F-2

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

	As of December 31,
	2006			2007
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	41,322		$	60,285
Accounts receivable, net of allowance for doubtful accounts of $284 and $303 as of December 31, 2006 and 2007, respectively		56,280			50,380
Prepayments and other current assets		2,697			3,425
Derivative assets		38,208			17,337
Total current assets		138,507			131,427
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		1,114,536			1,472,834
Unevaluated oil and gas properties, excluded from amortization		202,946			231,521
Oil and gas properties held for sale, net, excluded from amortization		75,496			2,303
Furniture, equipment and other		14,696			16,113
		1,407,674			1,722,771
Accumulated depreciation, depletion, amortization and impairment		(369,079	)		(526,939	)
Total property and equipment, net		1,038,595			1,195,832
Deferred Financing Costs, Derivative Assets and Other		10,299			2,428
Total	$	1,187,401		$	1,329,687
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	69,519		$	84,773
Amounts payable to oil and gas property owners		13,933			22,209
Production taxes payable		22,348			24,819
Derivative liability, deferred income taxes and other current liabilities		13,995			7,767
Total current liabilities		119,795			139,568
Note Payable to Bank		188,000			274,000
Asset Retirement Obligations		29,224			35,003
Liabilities Associated with Assets Held for Sale		3,374			45
Deferred Income Taxes		89,730			99,149
Other Noncurrent Liabilities		881			8,411
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 44,141,453 and 44,760,955 shares issued and outstanding at December 31, 2006 and 2007, respectively, with 254,524 and 564,100 shares subject to restrictions, respectively		44			44
Additional paid-in capital		727,486			742,492
(Accumulated deficit) Retained earnings		(504	)		26,205
Treasury stock, at cost: zero shares at December 31, 2006 and December 31, 2007		—			—
Accumulated other comprehensive income		29,371			4,770
Total stockholders’ equity		756,397			773,511
Total	$	1,187,401		$	1,329,687

See notes to consolidated financial statements.

F-3

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2005			2006			2007
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	284,406		$	344,127		$	374,956
Other		4,353			31,202			15,314
Total operating and other revenues		288,759			375,329			390,270
Operating Expenses:
Lease operating expense		19,585			29,768			41,643
Gathering and transportation expense		11,950			15,721			23,163
Production tax expense		33,465			25,886			22,744
Exploration expense		10,930			9,390			8,755
Impairment, dry hole costs and abandonment expense		55,353			12,824			25,322
Depreciation, depletion and amortization		89,499			138,549			172,054
General and administrative expense		27,752			34,243			42,228
Total operating expenses		248,534			266,381			335,909
Operating income		40,225			108,948			54,361
Other Income and Expense:
Interest and other income		1,977			2,527			2,391
Interest expense		(3,175	)		(10,339	)		(12,754	)
Total other income and expense		(1,198	)		(7,812	)		(10,363	)
Income before Income Taxes		39,027			101,136			43,998
Provision for Income Taxes		15,222			39,125			17,244
Net Income	$	23,805		$	62,011		$	26,754
Net Income Per Common Share, Basic	$	0.55		$	1.42		$	0.61
Net Income Per Common Share, Diluted	$	0.55		$	1.40		$	0.60
Weighted Average Common Shares Outstanding, Basic		43,238,312			43,694,781			44,049,662
Weighted Average Common Shares Outstanding, Diluted		43,439,634			44,269,445			44,677,467

See notes to consolidated financial statements.

F-4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

For the years ended December 31, 2005, 2006, and 2007

	Convertible Preferred Stock		Common Stock		Additional Paid-In Capital			(Accumulated Deficit) Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Compre- hensive Income
	(in thousands)
Balance—December 31, 2004	$	—	$	43	$	709,578		$	(86,320	)	$	—		$	(3,569	)	$	619,732
Exercise of options		—		1		7,149			—			(5,180	)		—			1,970		$	—
Tax benefit from option exercises		—		—		1,227			—			—			—			1,227			—
Stock-based compensation		—		—		3,211			—			—			—			3,211			—
Other		—		—		(20	)		—			—			—			(20	)		—
Comprehensive income:
Net income		—		—		—			23,805			—			—			23,805			23,805
Effect of derivative financial instruments, net of $11,243 of taxes		—		—		—			—			—			(19,142	)		(19,142	)		(19,142	)
Total comprehensive income																				$	4,663
Balance—December 31, 2005	$	—	$	44	$	721,145		$	(62,515	)	$	(5,180	)	$	(22,711	)	$	630,783
Exercise of options		—		—		9,644			—			(5,059	)		—			4,585			—
Stock-based compensation		—		—		6,944			—			—			—			6,944			—
Retirement of treasury stock		—		—		(10,239	)		—			10,239			—			—			—
Other		—		—		(8	)		—			—			—			(8	)		—
Comprehensive income:
Net income		—		—		—			62,011			—			—			62,011			62,011
Effect of derivative financial instruments, net of $30,775 of taxes		—		—		—			—			—			52,082			52,082			52,082
Total comprehensive income																				$	114,093
Balance—December 31, 2006	$	—	$	44	$	727,486		$	(504	)	$	—		$	29,371		$	756,397
Cumulative effect of adoption of Financial Accounting Standards Board Interpretation No. (FIN) 48		—		—		—			(45	)		—			—			(45	)	$	—
Exercise of options and shares exchanged for exercise and tax withholding		—		—		7,602			—			(3,319	)		—			4,283		$	—
Stock-based compensation		—		—		10,723			—			—			—			10,723			—
Retirement of treasury stock		—		—		(3,319	)		—			3,319			—			—			—
Comprehensive income:
Net income		—		—		—			26,754			—			—			26,754			26,754
Effect of derivative financial instruments, net of $14,604 of taxes		—		—		—			—			—			(24,601	)		(24,601	)		(24,601	)
Total comprehensive income																				$	2,153
Balance—December 31, 2007	$	—	$	44	$	742,492		$	26,205		$	—		$	4,770		$	773,511

See notes to consolidated financial statements.

F-5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2005			2006			2007
	(in thousands)
Operating Activities:
Net Income	$	23,805		$	62,011		$	26,754
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		89,499			138,549			172,054
Deferred income taxes		15,222			38,631			17,270
Impairments, dry hole costs and abandonment expense		55,353			12,824			25,322
Stock compensation and other non-cash charges		3,226			7,089			11,284
Amortization of deferred financing costs		1,175			556			482
Gain on sale of properties		(3,808	)		(21,335	)		(13,420	)
Change in operating assets and liabilities:
Accounts receivable		(24,811	)		(320	)		5,900
Prepayments and other assets		(1,891	)		4,335			(875	)
Accounts payable, accrued and other liabilities		1,700			3,904			(4,065	)
Amounts payable to oil and gas property owners		14,307			(5,764	)		8,276
Production taxes payable		10,493			(3,582	)		2,471
Net cash provided by operating activities		184,270			236,898			251,453
Investing Activities:
Additions to oil and gas properties, including acquisitions		(314,965	)		(438,476	)		(414,925	)
Additions of furniture, equipment and other		(3,720	)		(3,177	)		(4,640	)
Proceeds from sale of properties		13,842			78,339			96,450
Net cash used in investing activities		(304,843	)		(363,314	)		(323,115	)
Financing Activities:
Proceeds from debt		146,000			151,000			164,000
Principal payments on debt		(60,000	)		(55,495	)		(78,000	)
Proceeds from sale of common stock		2,979			4,929			5,098
Deferred financing costs and other		(50	)		(978	)		(473	)
Net cash provided by financing activities		88,929			99,456			90,625
(Decrease) Increase in Cash and Cash Equivalents		(31,644	)		(26,960	)		18,963
Beginning Cash and Cash Equivalents		99,926			68,282			41,322
Ending Cash and Cash Equivalents	$	68,282		$	41,322		$	60,285

See notes to consolidated financial statements.

F-6

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2005, 2006 and 2007

1. Organization

Bill Barrett Corporation (the “Company”, “we” or “us”), a Delaware corporation, is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil. Since its inception on January 7, 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying consolidated financial statements include the accounts of Bill Barrett Corporation and its wholly-owned subsidiaries (collectively, the “Company”, “we”, “us” or “our”). These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated.

Use of Estimates. Preparation of the Company’s financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses for the reporting period. Actual results could differ from those estimates.

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to volumes of natural gas and oil reserves used in calculating depletion, the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future abandonment obligations, impairments of undeveloped properties, valuing deferred tax assets and estimating fair values of derivative instruments.

Cash Equivalents. The Company considers all highly liquid investments with a remaining maturity of three months or less when purchased to be cash equivalents.

Oil and Gas Properties. The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use, and as a result, the Company had not capitalized any interest expense until the third quarter of 2006. The weighted average interest rate, including interest and commitment fees paid on the unused portion of the Company’s credit facility, amortization of deferred financing costs and the effects of

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interest rate hedges, used to capitalize interest was 7.1% for the years ended December 31, 2006 and 2007. The Company capitalized interest costs of $1.0 million and $1.6 million for the years ended December 31, 2006 and 2007, respectively.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated properties are assessed periodically on a property-by-property basis and any impairment in value is charged to expense. If the unevaluated properties are subsequently determined to be productive, the related costs are transferred to proved oil and gas properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered.

Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market, on a first-in, first-out basis.

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company’s natural gas and oil producing activities, including net capitalized costs associated with properties held for sale as of December 31, 2007 of $0.3 million in total proved properties (excluded from amortization) and $2.0 million in total unevaluated properties, both of which are net of $2.2 million of accumulated depreciation, depletion, amortization and impairment (see Note 4 for further information on properties held for sale):

	As of December 31,
	2006			2007
	(in thousands)
Proved properties	$	346,619		$	369,976
Wells and related equipment and facilities		736,007			974,005
Support equipment and facilities		86,932			123,020
Materials and supplies		2,258			6,132
Total proved oil and gas properties		1,171,816			1,473,133
Accumulated depreciation, depletion, amortization and impairment		(363,587	)		(521,691	)
Total proved oil and gas properties, net	$	808,229		$	951,442
Unevaluated properties	$	139,689		$	106,996
Wells and equipment in progress		81,473			126,529
Total unevaluated oil and gas properties, excluded from amortization	$	221,162		$	233,525

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Net changes in capitalized exploratory well costs for the years ended December 31, 2005, 2006 and 2007 are reflected in the following table (in thousands):

	Year Ended December 31,
	2005			2006			2007
	(in thousands)
Beginning of period	$	19,940		$	61,530		$	69,596
Additions to capitalized exploratory well costs pending the determination of proved reserves		209,847			211,290			227,290
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(157,158	)		(192,337	)		(193,618	)
Exploratory well costs charged to dry hole costs and abandonment expense (1)		(11,099	)		(10,887	)		(21,054	)
End of period	$	61,530		$	69,596		$	82,214

(1) Excludes expired leasehold abandonment expense of $1.2 million, $0.7 million and $2.0 million, along with impairment expense of $42.7 million, $1.2 million and $2.3 million for the years ended December 31, 2005, 2006 and 2007, respectively.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of gross wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.

	Year Ended December 31,
	2005		2006		2007
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	58,113	$	48,417	$	69,793
Capitalized exploratory well costs that have been capitalized for a period greater than one year		3,417		21,179		12,421
End of period balance	$	61,530	$	69,596	$	82,214
Number of exploratory wells that have costs capitalized for a period greater than one year		24		173		75

As of December 31, 2007, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling are $12.4 million. The majority of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, the Company drills wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to 24 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.

In addition to its wells in the Powder River Basin, the Company has three wells that have been capitalized for greater than one year. These wells, which are located in the Paradox and DJ Basins, are either in a testing phase or are waiting on pipeline.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying

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amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

During the years ended December 31, 2005, 2006 and 2007, the Company recognized non-cash impairment charges of $42.7 million, $1.2 million and $2.3 million, respectively, included within impairment, dry hole costs and abandonment expense. The impairment expense during 2005 is comprised of a $29.5 million impairment charge in the Cooper Reservoir field, $11.3 million impairment charge in the Talon field and $1.9 million impairment charge in the East Madden field. We undertook a drilling program in Cooper Reservoir in 2003 and 2004 with the expectation of a specific economic reserve level. Actual reserve levels were less than our expectations which led to an impairment in the field in 2005. The impairments in the Talon and East Madden fields were the result of unsuccessful exploration programs. The impairment expense during 2006 is a $1.2 million impairment charge to our Cedar Camp and Tumbleweed properties within the Uinta Basin. These properties were held for sale as of September 30, 2006 and were subsequently sold during the fourth quarter of 2006. The carrying amount of these properties was adjusted to fair value, which may be determined based upon recent sales prices of comparable properties or the present value of future cash flows, net of operating and development costs, discounted at various rates consistent with current market conditions at which similar types of properties are being traded. During 2007, the Company recognized a $2.3 million non-cash impairment charge in the quarter ended June 30, 2007 on the Tri-State exploration project in the DJ Basin, which is currently held for sale. These properties were subsequently sold in early 2008 for an immaterial gain.

The provision for depreciation, depletion and amortization (“DD&A”) of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Oil is converted to natural gas equivalents, Mcfe, at the rate of one barrel to six Mcf. Taken into consideration in the calculation of DD&A are estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

Furniture, Equipment and Other. Land and other office and field equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Leasehold improvements are amortized over the lesser of five years or the life of the lease. Maintenance and repairs are expensed when incurred. Depreciation of other property and equipment is computed using the straight-line method over their estimated useful lives of three to ten years. Upon retirement or disposition of assets, the costs and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, reflected in results of operations.

Accounts Payable and Accrued Liabilities. Accounts payable and accrued expenses are comprised of the following:

	As of December 31,
	2006		2007
	(in thousands)
Accrued drilling and facility costs	$	39,570	$	58,005
Accrued lease operating and gathering and transportation expenses		4,308		6,036
Accrued general and administrative expenses		6,002		7,358
Trade payables		11,923		8,444
Other		7,716		4,930
Total accounts payable and accrued liabilities	$	69,519	$	84,773

Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued

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when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2006 and 2007, the Company has not accrued for nor been fined or cited for any environmental violations that would have a material adverse effect upon capital expenditures, operating results or the competitive position of the Company.

Revenue Recognition. The Company records revenues from the sales of natural gas and crude oil when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.

The Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2006 and 2007 were not significant.

Comprehensive Income. Comprehensive income consists of net income and the effective component of derivative instruments classified as cash flow hedges. Comprehensive income is presented net of income taxes in the Consolidated Statements of Stockholders’ Equity and Comprehensive Income.

Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its gas and oil production by reducing its exposure to price fluctuations. The Company also enters into derivative contracts to mitigate the risk of interest rate fluctuations.

The Company accounts for such activities pursuant to SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.

The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the entity’s risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness, and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.

The Company may utilize derivative financial instruments which have not been designated as hedges under SFAS No. 133 because they still protect the Company from changes in commodity prices or interest rate fluctuations. These instruments are marked to market with the resulting changes in fair value recorded in earnings.

Deferred Financing Costs. Costs incurred in connection with the execution or modification of the Company’s credit facility are capitalized and amortized over the life of the facility, which approximates the effective interest method.

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Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.

On January 1, 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN No. 48”),Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109(“SFAS No. 109”). This interpretation introduces a new approach that changes how enterprises recognize and measure tax benefits associated with tax positions and how enterprises disclose uncertainties related to income tax positions in their financial statements. See Note 8 for further discussion of the effect of adopting FIN No. 48 on the Company’s consolidated financial statements.

Asset Retirement Obligations. The Company accounts for its asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligations. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the accompanying Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the accompanying Consolidated Statements of Operations.

Repurchases and Retirements of Capital Stock. The Company records treasury stock contributions at cost. Upon retirement of treasury shares, the excess of purchase or contribution cost over associated common stock par value is allocated to additional paid-in capital. The allocation to additional paid-in capital is based on the per-share amount of capital in excess of par value for all shares.

Stock-Based Compensation. The Company accounts for stock-based compensation in accordance with SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS No. 123R”), which revises SFAS No. 123,Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments.

For awards granted before we were a public company (i.e. those granted prior to April 16, 2004, which is defined by SFAS No. 123R as the date we became a public company as a result of filing our Form S-1 registration statement with the SEC) we continue to use the minimum value method described under APB Opinion No. 25. For awards granted after we were a public company (i.e. those granted subsequent to April 16, 2004), and for new, modified, repurchased, or cancelled awards on or subsequent to our adoption of SFAS No. 123R on October 1, 2004, we recognized share-based employee compensation cost based on the fair value as computed under SFAS No. 123R.

The Company continues to account for certain stock options under the original provisions of APB Opinion No. 25 because those options were issued prior to April 16, 2004, when we were considered a nonpublic entity as

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defined by SFAS No. 123R. Because those options were accounted for under the minimum-value method, the calculated fair value is not comparable to those options issued subsequent to April 16, 2004, in which a fair-value-based method was then used. Therefore, pro forma disclosures for stock options granted while we were a nonpublic company accounted for using the minimum-value method have not been included pursuant to SFAS No. 123R. See Note 10 for additional disclosures about stock-based compensation.

Earnings Per Share. Basic net income per common share of stock is calculated by dividing net income attributable to common stock by the weighted average of common shares outstanding during each period. Diluted net income attributable to common stockholders is calculated by dividing net income attributable to common stockholders by the weighted average of common shares outstanding and other dilutive securities. Net income attributable to common stock is calculated by reducing net income by dividends earned on preferred securities.

The following table sets forth the calculation of basic and diluted earnings per share:

	Year Ended December 31,
	2005		2006		2007
	(in thousands, except per share amounts)
Net income	$	23,805	$	62,011	$	26,754
Adjustments to net income for dilution		—		—		—
Net income adjusted for the effect of dilution	$	23,805	$	62,011	$	26,754
Basic weighted-average common shares outstanding in period		43,238.3		43,694.8		44,049.7
Add dilutive effects of stock options and nonvested equity shares of common stock		201.3		574.6		627.8
Diluted weighted-average common shares outstanding in period		43,439.6		44,269.4		44,677.5
Basic income per common share	$	0.55	$	1.42	$	0.61
Diluted income per common share	$	0.55	$	1.40	$	0.60

The weighted-average number of common shares outstanding used in the income per share calculation is computed pursuant to SFAS No. 128.

Industry Segment and Geographic Information. The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the United States. Consequently, the Company currently reports a single industry segment.

New Accounting Pronouncements. In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements regarding fair value measurement. Where applicable, this statement simplifies and codifies fair value related guidance previously issued within GAAP. Although this statement does not require any new fair value measurements, its application may, for some entities, change current practice. SFAS No. 157 was effective for the Company beginning January 1, 2008. Although additional disclosure may be required about the information used to develop fair value measurements, the adoption of SFAS No. 157 is not expected to have a material impact on our financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. This statement was effective for the Company beginning January 1, 2008; however, the Company does not expect to elect the fair value option for any eligible financial instruments or other items.

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In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS 141R”), which replaces FASB Statement No. 141,Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs, and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We expect SFAS No. 141R will have an impact on our consolidated financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after the effective date.

3. Supplemental Disclosures of Cash Flow Information:

Supplemental cash flow information is as follows:

	Year Ended December 31,
	2005		2006		2007
	(in thousands)
Cash paid for interest (net of amount capitalized)	$	1,903	$	9,625	$	11,260
Cash paid for income taxes, net of refunds received		—		500		22
Supplemental disclosures of non-cash investing and financing activities:
Exchange of oil and gas properties for equipment and other properties		—		9,304		—
Assumption of debt and deferred tax liability—Powder River Basin properties acquisition purchase price allocation		—		43,298		—
Reduction of deferred tax liability—Powder River Basin properties acquisition purchase price allocation		—		—		1,635
Current liabilities that are reflected in investing activities		17,889		6,818		65,340
Net change in asset retirement obligations		10,854		6,612		(340	)
Treasury stock acquired for employee stock option exercises		5,180		5,059		3,319
Retirement of treasury stock		—		10,239		3,319

4. Acquisitions, Disposition, and Property Held for Sale

Acquisitions

On May 8, 2006, the Company acquired 100% of the outstanding stock of CH4 Corporation, a Delaware corporation (“CH4”), for $74.2 million in cash and agreed to pay $6.5 million of indebtedness of CH4. The acquisition was funded with borrowings under the Company’s credit facility. The primary assets of CH4 consisted of approximately 84,300 gross (52,000 net) acres of oil and gas leasehold interests in coal bed methane properties in the Powder River Basin of Wyoming and an estimated 11.0 Bcfe of proved reserves.

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The CH4 acquisition was recorded using the purchase method of accounting, and the results of operations from the CH4 properties acquired are included with the results of the Company from the May 6, 2006 date of closing. The total purchase price of the transaction was allocated to the assets acquired and the liabilities assumed based on fair values at the acquisition date. The Company finalized the purchase price allocation during the quarter ended June 30, 2007 as all amounts related to receivables and payables were determined with certainty. The table below summarizes the final allocation (in thousands):

Purchase Price:
Cash paid, net of cash received	$	72,547
Debt assumed		6,495
Total	$	79,042
Allocation of Purchase Price:
Working capital	$	(327	)
Proved oil and gas properties		40,164
Unevaluated oil and gas properties		74,888
Other non-current assets		122
Deferred income taxes		(35,168	)
Asset retirement obligation		(637	)
Total	$	79,042

Pro forma financial information is not provided as the CH4 acquisition was not considered a material business combination to the Company, and the results of operations from those properties are insignificant.

Dispositions

In August 2006, the Company completed the sale of approximately 17,000 net acres of certain coalbed methane properties that were acquired with the CH4 acquisition. Proceeds from the sale were $30.7 million and a loss of $0.1 million was recorded due to various purchase price adjustments incurred in the normal course of business.

In December 2006, the Company completed the sale of the Cedar Camp and Tumbleweed properties, within the Uinta Basin, which were previously classified as held for sale at September 30, 2006. Total proceeds from the sale were $3.8 million, which resulted in a gain of $0.1 million, which is included in other operating revenues in the Consolidated Statement of Operations.

The Company also entered into joint exploration agreements and completed other property sales in the Powder River, Paradox, Williston, Wind River, Big Horn, Montana Overthrust, DJ, and Uinta Basins resulting in gains recognized of $30.5 million for the year ended December 31, 2006, which is included in other operating revenues in the Consolidated Statement of Operations. Under EITF 03-13,Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations, we determined that these sales did not qualify for discontinued operations reporting.

On June 22, 2007, the Company completed the sale of its oil and gas properties in the Williston Basin. This transaction had an effective date of May 1, 2007. The Company received approximately $81.4 million in cash proceeds and recognized a $10.0 million pre-tax gain after various purchase price adjustments incurred in the normal course of business. This gain is included in other operating revenues in the Consolidated Statement of Operations. Through the closing date of the sale on June 22, 2007, total production volumes associated with the Williston Basin properties of 1.2 Bcfe were included in the Company’s financial statements. In addition, the Company also completed the sale of a portion of its unevaluated properties in the DJ Basin. The Company received approximately $0.5 million in cash proceeds and recognized a $0.2 million pre-tax gain, which is

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included in other operating revenues in the Consolidated Statement of Operations. The remaining DJ Basin properties were classified as held for sale at December 31, 2007. See “—Property Held for Sale” below.

The Company also entered into joint exploration agreements and completed other property sales in the Powder River, Paradox, Big Horn, and Wind River Basins resulting in gains recognized of $3.1 million for the year ended December 31, 2007, which is included in other operating revenues in the Consolidated Statement of Operations.

Property Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and completion of the sale is probable and expected to occur within one year. Upon classification as held-for-sale, long-lived assets are no longer depreciated or depleted and a loss is recognized, if any, based upon the excess of carrying value over fair value less costs to sell. Previous losses may be reversed up to the original carrying value as estimates are revised; however, gains are recognized only upon disposition.

During 2006, the Company decided to divest its Tri-State exploration project in the DJ Basin. In addition, the Company began actively marketing its Hingeline Prospect in the Uinta Basin during the quarter ended September 30, 2007. In accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, these properties are carried at the lower of historical cost or fair value less cost to sell and were reclassified to oil and gas properties held for sale on the Consolidated Balance Sheet. Any liabilities related to those properties were also reclassified to liabilities associated with assets held for sale on the Consolidated Balance Sheet. Under EITF 03-13, we determined that these sales do not qualify for discontinued operations reporting.

Subsequent to December 31, 2007, substantially all remaining properties held for sale in the DJ Basin were sold for an immaterial gain.

The following table presents the assets and liabilities associated with the oil and gas properties held for sale in the DJ Basin and Hingeline Prospect as of December 31, 2007 (in thousands):

Proved oil and gas properties	$	298
Unevaluated oil and gas properties		2,005
Noncurrent liabilities		45

For the year ended December 31, 2007, total production volumes associated with the DJ Basin properties held for sale were 20 MMcfe. There are no producing properties within the Hingeline Prospect.

5. Note Payable to Bank

On March 17, 2006, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility had commitments of $400.0 million, which were expanded to $545.0 million as of November 6, 2007, and had an initial borrowing base of $280.0 million. Based on mid-year 2007 reserves and hedge position, the borrowing base was increased to $385.0 million on November 6, 2007. Future borrowing bases will be computed based on proved natural gas and oil reserves and hedge position. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.0% to 1.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. The average annual interest rate incurred on this debt was 7.1% and 6.3% for the years ended December 31, 2006 and 2007, respectively. The Company pays commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the

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stock of our subsidiaries. The Amended Credit Facility also contains certain financial covenants. We have complied with all financial covenants for all periods.

As of December 31, 2007, borrowings outstanding under the Amended Credit Facility totaled $274.0 million.

6. Asset Retirement Obligations

The Company accounts for its asset retirement obligations in accordance with SFAS No. 143,Accounting for Asset Retirement Obligations. This statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset.

A reconciliation of our asset retirement obligations for the years ended December 31, 2005, 2006 and 2007, which includes $0.05 million associated with assets held for sale in 2007, are as follows (in thousands):

	Year Ended December 31,
	2005			2006			2007
	(in thousands)
Beginning of period	$	11,806		$	23,733		$	32,598
Liabilities incurred		2,429			3,433			3,829
Liabilities settled		(203	)		(1,586	)		(3,599	)
Accretion expense		1,276			2,593			2,999
Revisions to estimate		8,425			4,425			22
End of period	$	23,733		$	32,598		$	35,849
Less: current asset retirement obligations		—			—			801
Long-term asset retirement obligations	$	23,733		$	32,598		$	35,048

7. Fair Value of Derivatives and Other Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 5, approximates the fair value due to its floating rate structure.

Oil and Gas Commodity Hedges

The Company periodically uses financial derivative instruments to achieve a more predictable cash flow from its natural gas and oil production by reducing its exposure to price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices we receive for a portion of our natural gas and oil production. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s natural gas and oil derivative financial instruments are accounted for in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.

In addition to financial transactions, the Company is a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

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All derivative instruments, other than those that meet the normal purchase and sales exceptions as mentioned above, are recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Realized gains and losses on cash flow hedges are transferred from comprehensive income and recognized in earnings and included within oil and gas production revenues in the Consolidated Statements of Operations as the associated production occurs. Unrealized gains and losses from the change in the fair value and realized gains and losses of derivative instruments that do not qualify as cash flow hedges, as well as the ineffective portion of hedge derivatives are reported in earnings in the Consolidated Statements of Operations.

At December 31, 2007, the estimated fair value of all of our derivative instruments was a net asset of $7.9 million comprised of current and noncurrent assets and liabilities. The Company will reclassify the appropriate amounts to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of December 31, 2007 to be reclassified from other comprehensive income to net income in the next 12 months would be approximately $5.6 million for our cash flow hedges. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. The Company anticipates that all originally forecasted transactions related to our cash flow hedges will occur by the end of the originally specified time periods. Ineffectiveness related to our derivative instruments was de minimis.

The Company was a party to various swap and collar contracts for natural gas based on Colorado Interstate Gas Rocky Mountains (“CIGRM”) and Panhandle Eastern Pipe Line Co. (“PEPL”) indices that settled during the years ended December 31, 2006 and 2007. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $22.2 million and $87.7 million in 2006 and 2007, respectively. The Company also was a party to various swap and collar contracts for oil based on a West Texas Intermediate (“WTI”) index, recognizing a reduction to oil production revenues related to these contracts of $4.1 million and $0.8 million in 2006 and 2007, respectively.

Interest Rate Derivative Contracts

In December 2006, the Company entered into two interest rate derivative contracts to manage the Company’s exposure to changes in interest rates. The first contract was a floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. The Company’s interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133. Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. Ineffectiveness related to the Company’s interest rate derivative instruments was de minimis.

Under the swap, the Company will make payments to, or receive payments from, the contract counterparty when the variable rate of one-month LIBOR falls below, or exceeds, the fixed rate of 4.70%. Under the collar, the Company will make payments to, or receive payments from, the contract counterparty when the variable LIBOR rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. The payment dates of both the swap and the collar match exactly with the interest payment dates of the corresponding portion of our Amended Credit Facility.

During the year ended December 31, 2007, the Company received $0.1 million in settlement payments, which were deducted from interest expense during the year. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods and as of December 31, 2007, based on current projected interest rates, the amount to be reclassified from other comprehensive income to net income in the next 12 months would be a net, after-tax reduction of approximately $0.1 million. At December 31, 2007, the estimated fair value of the interest rate derivatives was a net liability of $0.3 million.

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8. Income Taxes

The expense for income taxes consists of the following:

	Year Ended December 31,
	2005		2006		2007
	(in thousands)
Current:
Federal	$	—	$	460	$	432
State		—		34		7
Deferred:
Federal		14,629		36,353		15,804
State		593		2,278		1,001
Total	$	15,222	$	39,125	$	17,244

Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 35% to pretax income from continuing operations as a result of the following:

	Year Ended December 31,
	2005		2006		2007
	(in thousands)
Income tax expense at the federal statutory rate	$	13,659	$	35,392	$	15,400
State income taxes, net of federal tax effect		593		2,278		978
Non-deductible stock-based compensation		797		942		344
Other, net		173		513		522
Income tax expense	$	15,222	$	39,125	$	17,244

F-19

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at December 31, 2006 and 2007 are presented below:

	December 31,
	2006			2007
	(in thousands)
Current:
Deferred tax assets (liabilities):
Derivative instruments	$	(14,233	)	$	(5,561	)
Accrued expenses		589			167
Bad debt expense		—			113
Prepaid expenses		(317	)		(286	)
Other		—			214
Total current deferred tax assets (liabilities)	$	(13,961	)	$	(5,353	)
Long-term:
Deferred tax assets:
Net operating loss carryforward	$	28,434		$	21,496
Start-up/organization costs, net		33			—
Long-term derivative instruments		—			2,730
Stock-based compensation		1,395			3,208
Deferred rent		328			403
Minimum tax credit carryforward		459			721
Other		100			106
Less valuation allowance		(1,635	)		—
Total long-term deferred tax assets		29,114			28,664
Deferred tax liabilities:
Oil and gas properties		(115,641	)		(127,813	)
Long-term derivative instruments		(3,203	)		—
Other		—			—
Total long-term deferred tax liabilities		(118,844	)		(127,813	)
Net long-term deferred tax liabilities	$	(89,730	)	$	(99,149	)

At December 31, 2007, the Company had approximately $61.7 million of federal tax net operating loss carryforwards which expire through 2023. The Company has a federal alternative minimum tax (“AMT”) credit carryforward of $0.7 million, which has no expiration date.

At December 31, 2007, the Company’s balance sheet reflected net deferred tax liabilities of $104.5 million, of which $2.8 million pertains to the tax effects of derivative instruments reflected in other comprehensive income.

On July 13, 2006, the FASB issued FIN No. 48, which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN No. 48 also prescribes a recognition threshold and measurement standard for the financial statement recognition and measurement of an income tax position taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption. In addition, FIN No. 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

F-20

The Company adopted the provisions of FIN No. 48 on January 1, 2007, and has commenced analyzing filing positions in all of the federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in these jurisdictions. As a result of the implementation of FIN No. 48, the Company recognized a $0.2 million liability for unrecognized tax benefits. There was a cumulative adjustment of $0.05 million to the beginning balance of retained earnings and a corresponding decrease to deferred income tax liabilities of $0.15 million. Subsequent to the implementation of FIN No. 48, the Company did not record a change to the above balance of unrecognized tax benefits. Of the $0.2 million balance of unrecognized tax benefits at December 31, 2007, $0.05 million represents the amount of unrecognized tax benefits that, if recognized, would unfavorably affect the effective income tax rate.

A rollforward of changes in the Company’s unrecognized tax benefits is shown below (in thousands).

Balance at January 1, 2007	$	195
Additions based on tax positions related to the current year
Additions for tax positions of prior years		—
Reductions for tax positions of prior years		—
Settlements		—
Balance at December 31, 2007	$	195

The Company anticipates that no uncertain tax positions will be recognized within the next twelve-month period.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of the date of adoption of FIN No. 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state and local jurisdictions. The Company is subject to U.S. federal, state and local income tax examinations by these tax authorities for years beginning in 2002 and forward.

9. Stockholders’ Equity

Common and Preferred Stock. The Company’s authorized capital structure consists of 75,000,000 shares of $0.001 per share par value preferred stock and 150,000,000 shares of $0.001 per share par value common stock. In October 2004, 150,000 shares of $0.001 per share par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. At December 31, 2007, the Series A Junior Participating Preferred Stock was the Company’s only designated preferred stock, and the remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of Preferred Stock.

Holders of all classes of stock are entitled to vote on matters submitted to stockholders, except that, when issued, each share of Series A Junior Participating Preferred Stock will entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.

The Series A Junior Participating Preferred Stock will be issued pursuant to the Company’s shareholder rights plan if a stockholder acquires shares in excess of the thresholds set forth in the plan. The Series A Junior Participating Preferred Stock ranks junior to all series of preferred stock with respect to dividends and specified liquidation events. Dividends on this series are cumulative and do not bear interest, however, no dividend payment, or payment-in-kind, may be made to holders of common stock without declaring a dividend on this series equal to 1,000 times the aggregate per share amount declared on common stock. Upon the occurrence of specified liquidation events, the holders of this series will be entitled to receive an aggregate amount per share

F-21

equal to 1,000 times the aggregate amount to be distributed per share to holders of shares of common stock plus an amount equal to any accrued and unpaid dividends. Upon consolidation, merger or combination in which shares of common stock are exchanged for or changed into other securities or other assets, each share of this series will be similarly exchanged into an amount per share equal to 1,000 times that into which each share of common stock is exchanged. The number of Series A Junior Participating Preferred Stock will be proportionately changed in the event the Company declares or pays a common stock dividend or effects a stock split of common stock.

Treasury Stock. The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of share-based awards or for other reasons. As of December 31, 2007, all treasury stock held by the Company was retired.

The following table reflects the activity in the Company’s common and treasury stock:

	Year Ended December 31,
	2005	2006		2007
Common Stock Outstanding:
Shares at beginning of period	43,323,270	43,695,286		44,141,453
Exercise of common stock options	366,664	462,227		329,307
Shares issued for 401(k) plan	—	16,883		18,341
Shares issued directors’ fees	—	—		4,126
Shares issued for nonvested equity shares of common stock	5,352	252,817		403,800
Shares retired	—	(285,760	)	(136,072	)
Shares at end of period	43,695,286	44,141,453		44,760,955
Treasury Stock:
Shares at beginning of period	—	124,024		—
Treasury stock acquired	124,024	161,736		107,391
Treasury stock retired	—	(285,760	)	(107,391	)
Shares at end of period	124,024	—		—

F-22

Accumulated Other Comprehensive Income (Loss). The Company follows the provisions of SFAS No. 130,Reporting Comprehensive Income, which establishes standards for reporting comprehensive income (loss). The components of accumulated other comprehensive income (loss) and related tax effects for the years ended December 31, 2005, 2006 and 2007 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive loss—December 31, 2004		(5,665	)		2,096			(3,569	)
Unrealized change in fair value of hedges		(53,490	)		19,792			(33,698	)
Reclassification adjustment for realized losses on hedges included in net income		23,105			(8,549	)		14,556
Accumulated other comprehensive loss—December 31, 2005	$	(36,050	)	$	13,339		$	(22,711	)
Unrealized change in fair value of hedges		96,882			(35,999	)		60,883
Reclassification adjustment for realized gains on hedges included in net income		(14,025	)		5,224			(8,801	)
Accumulated other comprehensive income—December 31, 2006	$	46,807		$	(17,436	)	$	29,371
Unrealized change in fair value of hedges		(126,223	)		47,018			(79,205	)
Reclassification adjustment for realized gains on hedges included in net income		87,018			(32,414	)		54,604
Accumulated other comprehensive income—December 31, 2007	$	7,602		$	(2,832	)	$	4,770

10. Equity Incentive Compensation Plans and Other Employee Benefits

The Company maintains various stock-based compensation plans as discussed below. Under the fair value recognition provisions of SFAS 123R, stock-based compensation is measured at the grant date based on the value of the awards and the value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

Stock Options and Nonvested Equity Shares. In January 2002, the Company adopted a stock option plan to benefit key employees, directors and non-employees. This plan was amended and restated in its entirety by the Amended and Restated 2002 Stock Option Plan (the “2002 Option Plan”). The aggregate number of shares that the Company may issue under the 2002 Option Plan may not exceed 1,642,395 shares of the Company’s common stock. Options granted under the 2002 Option Plan expire up to ten years from the grant date. The options vest 40% on the first anniversary of the date of grant and 20% on the following three subsequent anniversaries of the date of grant.

In December 2003, the Company adopted its 2003 Stock Option Plan (the “2003 Option Plan”) to benefit key employees, directors and non-employees. In April 2004, the 2003 Option Plan was approved by the Company’s stockholders. The aggregate number of shares that the Company may issue under the 2003 Option Plan may not exceed 42,936 shares of the Company’s common stock. Options granted under the 2003 Option Plan expire up to ten years from the date of grant with an exercise price not less than 100% of the fair market value, as defined in the 2003 Option Plan, of the underlying common shares on the date of grant. Options granted under the 2003 Option Plan vest 25% on the first four anniversaries of the date of grant.

On December 1, 2004, our shareholders approved the 2004 Stock Incentive Plan (the “2004 Incentive Plan”) for the purpose of enhancing our ability to attract and retain officers, employees, directors and consultants and to provide such persons with an interest in the Company parallel to our stockholders. The 2004 Incentive Plan provides for the grant of stock options (including incentive stock options and non-qualified stock options) and other awards (including performance units, performance shares, share awards, restricted stock, restricted stock units, and stock appreciation rights, or SARs). The maximum number of awards that may be granted under the

F-23

2004 Incentive Plan is 4,900,000. In addition, the maximum number of awards that may be granted to a participant in any one year is 1,225,000. Options granted thus far under the 2004 Incentive Plan generally expire seven years from the date of grant and vest 25% on the first four anniversaries of the date of grant. Unless terminated earlier by our board of directors, the 2004 Incentive Plan will terminate on June 30, 2014. Upon an event constituting a “change in control” (as defined in the 2004 Incentive Plan) of the Company, all options will become immediately exercisable in full. In addition, in such an event, performance units will become immediately vested and restrictions on restricted stock awards will lapse.

Our compensation committee may grant awards on such terms, including vesting and payment forms, as it deems appropriate in its discretion, however, no award may be exercised more than 10 years after its grant (five years in the case of an incentive stock option granted to an eligible individual who possesses more than 10% of the total combined voting power of all classes of stock of the Company). The purchase price or the manner in which the exercise price is to be determined for shares under each award will be determined by the compensation committee and set forth in the agreement. However, the exercise price per share under each award may not be less than 100% of the fair market value of a share on the date the award is granted (110% in the case of an incentive stock option granted to an eligible individual who possesses more than 10% of the total combined voting power of all classes of stock of the Company).

Currently, our practice is to issue new shares upon stock option exercise, and we do not expect to repurchase any shares in the open market or issue treasury shares to settle any such exercises. For years ended December 31, 2005, 2006 and 2007, we did not pay cash to repurchase any stock option exercises.

In accordance with SFAS No. 123R, the fair value of each share-based option award under all of our plans is estimated on the date of grant using a Black-Scholes pricing model that incorporates the assumptions noted in the following table. Volatilities associated with expected terms where the Company did not have enough historical data of our own stock, expected volatilities were estimated based on an average of volatilities of similar sized Rocky Mountain oil and gas companies whose common stock is or has been publicly traded for a minimum of five years and other similar sized oil and gas companies who recently became publicly traded. For expected terms where we did have adequate historical data of our own stock, we estimated expected volatilities based upon historical volatility of the Company’s common stock. For options granted when we were a nonpublic company, we adopted the minimum value method under SFAS No. 123, which uses 0% volatility. Given our stage of growth and requirement for capital investment, we used a 0% expected dividend yield, which is comparable to most of our peers in the industry. The expected terms range from 1.25 years to 5.0 years based on 25% of each grant’s vesting on each anniversary date and factoring in potential blackout dates and historic exercises, with a weighted average of 2.9 years. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect on the date of grant. We estimated a 4% annual compounded forfeiture rate based on historical employee turnover and actual forfeitures for 2005 and 2006 and 6% for 2007.

	Year Ended December 31,
	2005		2006		2007
Weighted Average Volatility	39	%	36	%	41	%
Expected Dividend Yield	0	%	0	%	0	%
Weighted Average Expected Term (in years)	2.9		2.7		2.9
Weighted Average Risk-free Rate	3.7	%	4.3	%	4.7	%

F-24

A summary of share-based option activity under all the Company’s plans as of December 31, 2007, and changes during the year then ended, is presented below:

	Shares		Weighted-average Exercise Price		Weighted-average remaining contractual term	Aggregate intrinsic value
Outstanding at January 1, 2007	2,429,069		$	26.35
Granted	932,000			32.01
Exercised	(329,307	)		23.09
Forfeited or expired	(113,900	)		32.53
Outstanding at December 31, 2007	2,917,862		$	28.25	5.11	$	39,740,739
Vested, or expected to vest, at December 31, 2007 through the life of the options	2,816,496		$	28.15	5.09		38,628,422
Vested and exercisable at December 31, 2007	1,228,424		$	24.60	4.29	$	21,208,840

The per share weighted-average grant-date fair value of awards granted for the years ended December 31, 2005, 2006 and 2007 was $9.54, $7.26 and $10.13, respectively, and the total intrinsic value of awards exercised during the same periods was $8.6 million, $4.5 million and $4.3 million, respectively. The aggregate intrinsic value in the preceding table represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $41.87 on December 31, 2007. Related to stock option exercises, we received $3.0, $4.9 and $5.1 million for the years ended December 31, 2005, 2006 and 2007, respectively.

A summary of the Company’s nonvested equity shares of common stock as of December 31, 2007, and changes during the year then ended, is presented below:

	Shares	Weighted-average Grant Date Fair Value
Outstanding at January 1, 2007	254,524	$	34.22
Granted	176,000		30.13
Vested	65,543		34.17
Forfeited or expired	25,881		32.25
Outstanding at December 31, 2007	339,100	$	32.26
Vested, or expected to vest, at December 31, 2007 through the life of the option	318,754	$	32.26
Vested and exercisable at December 31, 2007	—	$	—

We recorded non-cash stock-based compensation related to share-based option and nonvested equity share awards of $3.2 million, $6.4 million, and $8.0 million for the years ended December 31, 2005, 2006 and 2007, respectively. Included in the $3.2 million and $6.4 million of stock-based compensation for the years ended December 31, 2005 and 2006, respectively, is $0.3 million and $0.9 million related to the modification of equity awards for certain employees in which their vesting terms were accelerated. For the year ended December 31, 2005, the Company recognized a tax benefit of $1.2 million that was charged to stockholder’s equity for the exercise of stock options. For the years ended December 31, 2006 and 2007, the Company did not recognize an excess tax benefit related to the exercise of stock options in accordance with SFAS No. 123R. As of December 31, 2007, there was $20.0 million of total compensation costs related to nonvested stock option and nonvested equity shares of common stock grants that is expected to be recognized over a weighted-average period of 2.6 years.

F-25

Performance Share Plan.On May 9, 2007, the Compensation Committee of the Board of Directors of the Company approved a performance share program pursuant to the Company’s 2004 Stock Incentive Plan for the Company’s officers and other senior employees pursuant to which vesting of awards is contingent upon meeting various Company-wide performance goals. Upon commencement of the program and during each year of the program, the Compensation Committee will meet to approve target and stretch goals for certain operational or financial metrics that are selected by the Committee for the upcoming year and to determine whether metrics for the prior year have been met. These performance-based awards contingently vest over a period up to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for between 25 percent and 50 percent of the original shares to vest based on meeting performance goals. Twenty-five percent of the total grant will vest for metrics met at the target level, and an additional 25 percent of the total grant will vest for performance met at the stretch level. If the actual results for a metric are between the target levels and the stretch levels, the vested number of shares will be adjusted on a prorated basis of the actual results compared to the target and stretch goals. In any event, the total number of common shares that could become vested will not exceed the original number of performance shares granted. At the end of four years, any shares that have not vested will be forfeited. A total of 250,000 shares under the 2004 Stock Incentive Plan were set aside for this program.

For the year ended December 31, 2007, the performance goals consisted of annual production growth (weighted at 30%), additions to our natural gas and oil reserves (weighted at 30%), finding and development costs (weighted at 30%), and general and administrative expenses (weighted at 10%). The weighting is determined by the Compensation Committee. Each metric is independent so that vesting can occur for one or more metrics even if the goals are not achieved for other metrics. Also for the year ending December 31, 2007, the Compensation Committee requires that an initial threshold level for finding and development costs be met before any of the performance shares will vest. In future years of the program, the Compensation Committee may impose initial threshold levels based on this or other metrics.

As new goals are established each year, a new grant date and a new fair value are created for financial reporting purposes for those shares that could potentially vest in the upcoming year. Compensation cost is recognized based upon the probability that the performance goals will be met. If such goals are not met, no compensation cost is recognized and any previously recognized compensation cost is reversed. During the year ended December 31, 2007, the Company granted 227,800 performance-based nonvested equity shares of common stock at a weighted-average grant date fair value of $37.21. As of December 31, 2007, the Company determined that 30% of the total grant related to the year ended December 31, 2007 would vest. Accordingly, the Company recorded non-cash stock-based compensation related to performance-based nonvested equity share awards of $1.9 million for the year ended December 31, 2007. As of December 31, 2007, there were $0.5 million of total compensation costs that are expected to be recognized through February 2008, which represents the remaining time vesting requirement.

A summary of the Company’s nonvested performance-based equity shares of common stock as of December 31, 2007, and changes during the year then ended, is presented below:

	Shares		Weighted-average Grant Date Fair Value
Outstanding at January 1, 2007	—		$	—
Granted	227,800			37.21
Vested	—			—
Forfeited or expired	(2,800	)		37.21
Outstanding at December 31, 2007	225,000		$	37.21
Vested, or expected to vest, at December 31, 2007 through the life of the shares	63,450		$	37.21
Vested and exercisable at December 31, 2007	—		$	—

F-26

Director Fees. Beginning with the quarter ended June 30, 2007, the Company’s directors may elect to receive their annual retainer and meeting fees in the form of the Company’s common stock issued pursuant to the Company’s 2004 Stock Incentive Plan. After each quarter, shares with a value equal to the fees payable for that quarter, calculated using the closing price on the last trading day before the end of the quarter, will be delivered to each outside director who elected before that quarter to receive shares for payment of the director fees. For the year ended December 31, 2007, the Company issued 4,126 shares of common stock for payment of the director fees and recognized $0.2 million of non-cash stock-based compensation associated with those shares.

Other Employee Benefits-401(k) Savings. The Company has an employee directed 401(k) savings plan (the “401(k) Plan”) for all eligible employees over the age of 21. Employees become eligible the quarter following the beginning of their employment. Under the 401(k) Plan, employees may make voluntary contributions based upon a percentage of their pretax income. Through December 31, 2005, the Company matched 100% of the employee contribution, up to 4% of the employee’s pretax income.

Beginning on January 1, 2006, the Company amended the 401(k) Plan to match 100% of the employee contribution, up to 6% of the employee’s pretax income, with 50% of the match made with the Company’s common stock. The Company’s cash contributions and shares of common stock are fully vested upon the date of match. The Company made matching cash contributions of $0.6 million, $0.5 million, and $0.6 million for the years ended December 31, 2005, 2006 and 2007, respectively, and common stock contributions of $0.6 million for the year ended December 31, 2007.

11. Transactions with Related Parties

A director of the Company (who served until May 2006) is a managing director of a company affiliated with the company which wholly owns the counterparty to a portion of the natural gas swaps noted in Note 7 above, the company that was the sole lead arranger and administrative agent for the senior subordinated credit and guaranty agreement as discussed in Note 5 above, and the company that was the lead underwriter in the Company’s initial public offering.

In management’s opinion, the terms obtained in the above transactions were provided on terms at least as favorable to the Company as could be obtained from non-related sources.

12. Significant Customers and Other Concentrations

Significant Customers. During 2005, ONEOK Inc., Xcel Energy Inc., and OGE Energy Resources Inc. accounted for 20.3%, 10.3%, and 10.0%, respectively, of the Company’s oil and gas production revenues. During 2006, Sempra Energy Trading Corporation, Xcel Energy Inc., and ONEOK Inc. accounted for 21.3%, 10.0%, and 9.7%, respectively, of the Company’s oil and gas production revenues. During 2007, Sempra Energy Trading Corporation, Encana Oil & Gas, and United Energy Trading accounted for 20.6%, 15.7%, and 8.7%, respectively, of the Company’s oil and gas production revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Concentrations of Market Risk. The future results of the Company’s oil and gas operations will be affected by the market prices of oil and gas. The availability of a ready market for crude oil, natural gas and liquid products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from purchasers of oil and gas production and amounts due from joint venture

F-27

partners for their respective portions of operating expense and exploration and development costs. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long-term. Trade receivables are generally not collateralized. The Company analyzes customers’ and joint venture partners’ historical credit positions and payment history prior to extending credit.

Concentrations of Credit Risk. Derivative financial instruments that hedge the price of oil and gas and interest rate levels are generally executed with major financial or commodities trading institutions which expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The credit worthiness of counterparties is subject to continuing review and full performance is anticipated. The Company’s policy is to execute financial derivatives only with major financial institutions.

13. Commitments and Contingencies

Transportation Demand and Firm Processing Charges. The Company has entered into contracts which provide firm transportation capacity on pipeline systems and firm processing charges. The remaining terms on these contracts range from 1 to 13 years and require the Company to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by the Company. The Company paid $1.7 million, $3.7 million and $5.5 million of transportation demand charges for the years ended December 31, 2005, 2006 and 2007, respectively. The Company paid $0.7 million and $3.7 million of firm processing charges in 2006 and 2007, respectively, and did not incur firm processing charges in 2005. All transportation costs including demand charges and processing charges are included in gathering and transportation expense in the Consolidated Statement of Operations.

Future minimum transportation demand and firm processing charges as of and subsequent to December 31, 2007 are as follows (in thousands):

2008	$	22,514
2009		23,291
2010		23,365
2011		23,479
2012		23,596
Thereafter		131,532
Total	$	247,777

Lease Obligations and Other Commitments. The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Office lease expense for the years ended December 31, 2005, 2006 and 2007 was $0.9 million, $1.4 million and $1.4 million, respectively. Additionally, the Company has entered into various long-term agreements for telecommunication service. The Company also has commitments for developing oil and gas properties of $17.8 million for 2008, which are included in the minimum payment schedule below.

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Future minimum annual payments under such leases and agreements as of and subsequent to December 31, 2007 are as follows (in thousands):

	Other Commitments		Office & Equipment Leases
2008	$	17,786	$	1,873
2009		—		1,925
2010		—		1,922
2011		—		465
2012		—		—
Thereafter		—		—
Total	$	17,786	$	6,185

In addition to the commitments above, the Company has commitments for the purchase of facilities equipment as of and subsequent to December 31, 2007 for a total of $7.3 million.

14. Supplementary Oil and Gas Information (unaudited)

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent unit-of-production were as follows:

	Year Ended December 31,
	2005		2006		2007
	(in thousands, except amortization data)
Acquisition costs:
Unproved properties	$	25,689	$	126,091	$	23,635
Proved properties		1,288		33,138		2,008
Exploration costs		218,586		224,189		250,687
Development costs		95,236		114,593		162,502
Asset retirement obligation		10,650		6,272		982
Total costs incurred	$	351,449	$	504,283	$	439,814
Depletion per Mcfe of production	$	2.20	$	2.60	$	2.78

Supplemental Oil and Gas Reserve Information. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2005, 2006, and 2007 that were prepared by internal petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission and were reviewed by independent petroleum engineering firms, Ryder Scott Company and Netherland, Sewell & Associates, Inc. (“NSAI”) in 2005 and 2006 and reviewed by NSAI in 2007.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e. prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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Analysis of Changes in Proved Reserves. The following table sets forth information regarding the Company’s estimated net total proved and proved developed oil and gas reserve quantities, including 126 MMcf of gas and gas equivalent units relating to properties held for sale in the DJ Basin:

	Oil (MBbls)		Gas (MMcf)		Equivalent Units (MMcfe)
Proved reserves:
Balance, December 31, 2004	5,738		257,876		292,304
Purchases of oil and gas reserves in place	5		3,274		3,304
Extension, discoveries and other additions (1)	1,130		96,223		103,004
Revisions of previous estimates (1)	(414	)	(14,598	)	(17,082	)
Sales of reserves (1)	(102	)	(517	)	(1,130	)
Production	(523	)	(36,286	)	(39,424	)
Balance, December 31, 2005	5,834		305,972		340,976
Purchases of oil and gas reserves in place	—		19,529		19,529
Extension, discoveries and other additions	3,063		129,309		147,687
Revisions of previous estimates	252		(23,000	)	(21,488	)
Sales of reserves	—		(6,152	)	(6,152	)
Production	(696	)	(47,932	)	(52,108	)
Balance, December 31, 2006	8,453		377,726		428,444
Purchases of oil and gas reserves in place	1		2,673		2,679
Extension, discoveries and other additions	1,021		169,618		175,744
Revisions of previous estimates	322		52,231		54,163
Sales of reserves	(5,989	)	(6,257	)	(42,191	)
Production	(586	)	(57,678	)	(61,194	)
Balance, December 31, 2007	3,222		538,313		557,645
Proved developed reserves:
December 31, 2005	4,283		182,777		208,475
December 31, 2006	5,006		218,902		248,938
December 31, 2007	2,090		317,298		329,838

(1) In 2006, the Company reclassified 14,362 MMcfe and 601 MMcfe of 2005 proved reserves from “Revisions of previous estimates” to “Extension, discoveries and other additions” and “Sales of Reserves,” respectively. “Revisions of previous estimates” decreased by 3,262 MBbls of oil and increased by 4,609 MMcf of gas. “Extension, discoveries and other additions” increased by 3,162 MBbls of oil and decreased by 4,609 MMcf of gas. “Sales of reserves” increased by 100 MBbls of oil. As this is a reclassification between categories within proved reserves, there is no change to ending reserves as of December 31, 2005.

At year-end 2005, the Company revised its proved reserves downward by 24.7 Bcfe, excluding pricing revisions, primarily as a result of a reduction in proved undeveloped reserves in the Piceance Basin due to the use of completion techniques performed from January through September 2005 that yielded results lower than the Company’s expectations at year-end 2004. Completion techniques used in subsequent periods have yielded more favorable results, which are reflected in upward revisions in 2006 and 2007 reserve estimates in this area. The downward revision in the Piceance Basin in 2005 was 25.6 Bcfe. In this basin, 31% of the proved wells forecast at year-end 2004 were 25% below forecast at year-end 2005. The reserve variance between the independent reserve engineers and the Company at year-end 2004 for this basin was 13 Bcfe with the independent engineer at the lower estimate. The downward revision in the Powder River Basin in 2005 was 9.6 Bcfe. In this basin, 36% of the proved wells forecast at year-end 2004 were 25% below forecast at year-end 2005. The reserve variance between the independent reserve engineers and BBC at year-end 2004 for this basin was 3.8 Bcfe with the independent engineer at the lower estimate. An upward revision of 8.1 Bcfe occurred in the Uinta Basin in the

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West Tavaputs Field in 2005. In this basin, 31% of the proved wells forecast at year-end 2004 were 25% above forecast at year-end 2005. The reserve variance between the independent reserve engineers and BBC at year-end 2004 was 2.1 Bcfe with the independent engineer at the lower estimate.

During 2005, reviews of proved oil and gas properties in the Wind River Basin indicated a decline in the recoverability of their carrying value and the need for an impairment in the Cooper Reservoir, Talon and East Madden fields in the total amount of $42.7 million. The Company undertook a drilling program in Cooper Reservoir in 2003 and 2004 with the expectation of a specific economic reserve level. Actual reserve levels were less than the Company’s expectations, which led to an impairment in the field in 2005. The impairments in the Talon and East Madden fields were the result of unsuccessful exploration programs.

At year-end 2006, the Company revised its proved reserves upward by 12.4 Bcfe, excluding pricing revisions. This revision was primarily the result of increased performance of wells drilled during the last half of 2005 and the first half of 2006. The pricing revision at year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil, relative to year-end 2005 prices of $7.72 per MMBtu and $61.04 per barrel of oil, was downward 33.8 Bcfe. These prices were adjusted by lease for quality, transportation fees and regional price differences.

At year-end 2007, the Company revised its proved reserves upward by 34.8 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped locations in the West Tavaputs field and continued improved performance of wells drilled in the West Tavaputs and Piceance fields. The Company also revised its 2007 year-end proved reserves upward by 19.4 Bcfe due to pricing, as year-end 2007 pricing was $6.04 per MMBtu and $92.50 per barrel of oil, relative to year-end 2006 at prices of $4.46 per MMBtu of gas and $61.06 per barrel of oil. These prices were adjusted by lease for quality, transportation fees and regional price differences.

Standardized Measure. Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69,Disclosures about Oil and Gas Producing Activities. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. Year-end calculations were made using prices of $61.04, $61.06 and $92.50 per Bbl for oil and $7.72, $4.46, and $6.04 per Mmbtu for gas for 2005, 2006, and 2007, respectively. These prices are adjusted for transportation and quality and basis differentials. The Company also records an overhead expense of $100 per month per operated well in the calculation of its future cash flows.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

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A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:

	December 31,
	2005			2006			2007
	(in thousands)
Future cash inflows	$	2,882,165		$	2,201,106		$	3,667,661
Future production costs		(638,004	)		(601,502	)		(861,344	)
Future development costs		(362,424	)		(418,126	)		(554,410	)
Future income taxes		(487,992	)		(168,959	)		(510,554	)
Future net cash flows		1,393,745			1,012,519			1,741,353
10% annual discount		(611,267	)		(483,233	)		(800,107	)
Standardized measure of discounted future net cash flows	$	782,478		$	529,286		$	941,246

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and natural gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from its oil and natural gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas and changes in governmental regulations or taxation.

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows:

	Year Ended December 31,
	2005			2006			2007
	(in thousands)
Standardized measure of discounted future net cash flows, beginning of period	$	466,109		$	782,478		$	529,286
Sales of oil and gas, net of production costs and taxes		(243,717	)		(253,645	)		(203,970	)
Extensions, discoveries and improved recovery, less related costs		303,751			178,726			379,243
Quantity revisions		(130,275	)		(43,902	)		142,748
Price revisions		396,299			(474,739	)		262,362
Net changes in estimated future development costs		(25,191	)		62,574			(39,606	)
Accretion of discount		59,206			104,960			60,281
Purchases of reserves in place		11,260			33,518			3,454
Sales of reserves		(1,138	)		(9,671	)		(79,752	)
Changes in production rates (timing) and other		87,349			(44,614	)		76,286
Net changes in future income taxes		(141,175	)		193,601			(189,086	)
Standardized measure of discounted future net cash flows, end of period	$	782,478		$	529,286		$	941,246

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15. Quarterly Financial Data (unaudited)

The following is a summary of the unaudited financial data for each quarter presented. The income before income taxes, net income, and net income per common share for each of the quarters for the years ended December 31, 2006 and 2007.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share data)
Year ended December 31, 2006:
Total revenues	$	97,774	$	82,611	$	104,412	$	90,532
Less: costs and expenses		61,716		67,005		68,835		68,825
Operating income	$	36,058	$	15,606	$	35,577	$	21,707
Income before income taxes		35,236		13,311		33,074		19,515
Net income		22,134		8,210		20,701		10,966
Net income per common share, basic		0.51		0.19		0.47		0.25
Net income per common share, diluted		0.50		0.19		0.47		0.25
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share data)
Year ended December 31, 2007:
Total revenues	$	98,380	$	100,653	$	82,255	$	108,982
Less: costs and expenses		72,968		82,040		79,693		101,208
Operating income	$	25,412	$	18,613	$	2,562	$	7,774
Income before income taxes		23,069		16,050		499		4,380
Net income		14,184		9,858		233		2,479
Net income per common share, basic		0.32		0.22		0.01		0.06
Net income per common share, diluted		0.32		0.22		0.01		0.06

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