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Bill Barrett Corp – ‘10-K’ for 12/31/08

On:  Tuesday, 2/24/09, at 11:12am ET   ·   For:  12/31/08   ·   Accession #:  1047469-9-1731   ·   File #:  1-32367

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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

Commission File No. 001-32367

BILL BARRETT CORPORATION
(Exact name of registrant as specified in its charter)

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

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

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

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

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    o

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

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

         The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant as of June 30, 2008 based on the $59.41 closing price of our common stock was $2,255,891,746.*

*

Without assuming that any of the registrant directors or executive officers, or the entity affiliated with a director that currently beneficially owns 7,159,440 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 January 30, 2009, the registrant had 45,131,023 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 2009 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant's fiscal year ended December 31, 2008.

Table of Contents

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;



•

natural gas and oil reserves;



•

realized oil and natural gas prices;



•

production;



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exploration and development drilling prospects, inventories, projects and programs;



•

the ability to obtain and the cost of financing;



•

ability to obtain permits and governmental approvals;



•

identified drilling locations;



•

changing regulatory environment;



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transportation and access to pipelines;



•

the ability of our hedge counterparties to fulfill their obligations;



•

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



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availability and costs of drilling rigs and field services;



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



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technology;



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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

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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," "us" or "our") was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop natural gas and oil 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 gas and oil in the Rocky Mountain region to profitably grow our reserves and production, primarily through internally generated projects.

        We have attempted to fulfill our strategy to profitably grow our reserves and production by drilling low-risk repeatable development wells and finding and developing gas and oil in the Rocky Mountain region. In addition to low-risk development drilling, we plan to continue evaluating our delineation and exploration prospects on our extensive acreage position of over 1.2 million net undeveloped acres. Our operating results reflect our development growth and exploration success on our properties.

        We began active natural gas and oil operations in March 2002 with the acquisition of properties in the Wind River Basin. 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 also acquired producing properties that had large undeveloped acreage positions associated with them. For example, in 2002, we completed two additional acquisitions that included 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 and around the Gibson Gulch field; and in May 2006, we added to our coalbed methane position in the Powder River Basin. In June 2007, we sold our Williston Basin properties. There were no major acquisitions or divestitures in 2008.

        We operate in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of our operations are conducted in the United States. Consequently, we currently report 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 as of December 31, 2008.

(1)

Our proved reserves were determined in accordance with Securities and Exchange Commission, or SEC, guidelines, using the market prices for natural gas (CIGRM price) and oil (WTI price) at December 31, 2008, which were $4.61 per MMBtu of natural gas and $41.00 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 105,862 net undeveloped acres that are subject to drill-to-earn agreements are not included.

(3)

Two gross operated wells in the Paradox Basin were placed on production in December 2008. Because these wells have not been on production long enough to adequately evaluate reservoir potential, no proved reserves were assigned to these wells as of December 31, 2008.

(4)

The Big Horn Basin has two gross non-operated wells with insignificant proven reserves.

Our Offices

        We were founded in 2002 and are 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 2008, we produced 77.6 Bcfe. Proved reserves grew from 119.1 Bcfe at year-end 2002 to 818.3 Bcfe at year-end 2008. Over the past three years, we replaced 362% of production through drilling and 375% of production in total, including acquisitions. From inception through December 31, 2008, we participated in the drilling of 1,772 gross wells, achieving a 98% success rate.

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•

Multi-year, low-risk, development drilling inventory.  We have assembled an inventory of approximately 3,100 locations in our core development areas in the Uinta, Piceance, Powder River and Wind 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 approximately 80% to 85% of our capital budget to these low-risk development projects.



•

High operatorship and control of capital program.  Based on our year-end 2008 proved reserves, we had a weighted-average working interest of 92% and operatorship of 98%. 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 approximately 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 90% of our properties are classified as unconventional resources, including basin-centered tight gas, CBM and 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 1,225,501 net undeveloped leasehold acres as of December 31, 2008, as well as an additional 105,862 net undeveloped acres that are subject to drill-to-earn agreements. We have multiple exploration projects in six different Rocky Mountain basins and along the Rockies' 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, 2008, we had $43.1 million in cash and cash equivalents. At December 31, 2008, the outstanding balance under our $592.8 million credit facility was $254.0 million. We are committed to maintaining a conservative financial position to preserve our financial flexibility. We have hedged approximately 70-75% of our currently estimated 2009 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 other sales points for which we have firm transport 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 2009. Because of capital market and near term commodity price outlook, we plan to align our 2009 capital expenditures with our anticipated cash flow from operations.

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Business Strategy

        Our strategy is to profitably grow our reserves and production by drilling low-risk, repeatable development wells and exploring for and 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% to 85% of our capital budget to our development projects. Our four core development areas have approximately 3,100 identified drilling locations as of December 31, 2008. In 2009, we plan to participate in the drilling of up to 144 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 2008, we operated approximately 97% 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.



•

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 a natural gas region in North America with significant remaining growth potential. 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 2008, 95% 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 historically higher pricing for selling natural gas. There is additional capacity proposed from the region by means of new pipelines and added compression to existing pipelines over the next several years as Rocky Mountain production increases.



•

Maintain financial flexibility and conservative financial position.  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. Because of capital market and near term commodity outlook, we plan to align our 2009 capital expenditures with our anticipated 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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Uinta Basin

        The Uinta Basin is located in northeastern Utah. Our development operations are conducted in the West Tavaputs area, and we are currently testing offsets and infill locations 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, 2008—328.8 Bcfe.



•

Producing wells—We held interests in 161 gross producing wells as of December 31, 2008.



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2008 net production—28.2 Bcfe.



•

Acreage—We held 191,885 net undeveloped acres as of December 31, 2008, along with 105,862 net acres that are subject to drill-to-earn agreements.



•

Capital budget—In 2008, our capital expenditures were $223.7 million in the Uinta Basin area to drill 75 gross wells and install compression and gathering facilities.

West Tavaputs

        We serve as operator of our interests in the West Tavaputs area. As of December 31, 2008, we had 753 drilling locations and 320.3 Bcfe of estimated proved reserves with a weighted average working interest of 96%. We are actively drilling our shallow program, which targets the gas-productive sands of the Wasatch and Mesaverde formations at depths down to 8,000 feet. We drilled 60 shallow wells in 2008 and plan to drill up to 16 shallow wells in 2009. The Wasatch and Mesaverde formations are currently being developed on 40-acre density following testing and analysis of 40-acre pilots in 2007 and 2008. Testing of 20-acre density pilots are also underway having drilled six 20-acre shallow wells in 2008.

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        With 3-D seismic, we also have 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 7 of 8 wells drilled thus far.

        Full development of the West Tavaputs area requires the completion of an Environmental Impact Statement, or EIS, which we initiated in February 2005. The Record of Decision, or ROD, on the EIS has been deferred pending the transition of the management of certain positions within the Bureau of Land Management, or BLM, and Department of Interior under President Obama's administration. Due to the transition, we believe it will be several months before the ROD could be obtained.

        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 the 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. In 2008, we drilled one gross well in Lake Canyon as we continued to evaluate the results from the six wells drilled in previous years.

        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. By the end of 2008 we had commenced the drilling of 14 wells with an average working interest of 60.7%, thus fulfilling both our 2007 and 2008 drilling obligations. Completion results to date indicate we can successfully extend the known limits of the field, as well as increase the well density inside the current field boundaries, as long as product prices support such activity.

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 the deep Manning Canyon area of this prospect. In 2008, we continued to acquire leasehold acreage, drilled a scientific well to gather data and drilled an exploration well to test this prospect. In 2009, we plan to drill our first horizontal well to test the Manning Canyon shale, and continue our evaluation of the shallower Juana Lopez shale with a second vertical core well.

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

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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, 2008—372.1 Bcfe.



•

Producing wells—We held interests in 424 gross producing wells as of December 31, 2008.



•

2008 net production—31.5 Bcfe.



•

Acreage—We held 10,295 net undeveloped acres as of December 31, 2008.



•

Capital budget—Our capital expenditures for 2008 were $249.8 million for participation in the drilling of 135 gross wells and to expand our compression and gathering facilities in the Piceance Basin.

        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 and 2008 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 Corporation'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, Colorado.

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, 2008—66.0 Bcfe.



•

Producing wells—We held interests in 666 gross producing wells as of December 31, 2008.



•

2008 net production—8.1 Bcfe.



•

Acreage—We held 77,397 net undeveloped acres as of December 31, 2008.



•

Capital budget—In 2008, our capital expenditures for the Powder River Basin were $36.9 million, which included participating in drilling 203 wells and acquisitions.

        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 coalbed well can range from five to 11 years depending on the coal seam.

        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."

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        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 that 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, 2008—50.8 Bcfe.



•

Producing wells—We held interests in 165 gross producing wells as of December 31, 2008.



•

2008 net production—9.6 Bcfe.



•

Acreage—We held 226,636 net undeveloped acres as of December 31, 2008.



•

Capital budget—For 2008, our operations in the Wind River Basin included recompletions and exploration drilling, and capital expenditures were $33.0 million.

        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 Colorado Interstate Gas ("CIG").

Cave Gulch

        The Cave Gulch field is a combination structural play and 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 existing wellbores, owned and operated by us, out of the shallower Lance and Fort Union formations.

        In January 2008, we signed a joint exploration agreement with two industry partners that provided for the drilling of at least two deep wells in 2008 on a partially promoted basis. The Cave Gulch 31-32 was drilled to 18,731 feet and tested approximately 1,000 Mcf/d from the Lakota and Muddy formations. We have moved up hole and are currently in the process of completing in the Frontier section with results expected in the first half of 2009. The East Bullfrog 23-6 well was recently completed in the Muddy and Lakota formations. Outside this joint exploration area, we are also planning on recompletion of the Frontier formation in the Bullfrog 33-19. This recompletion is expected to take place in the second half of 2009.

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 265,712 net undeveloped acres as of December 31, 2008.



•

Producing wells—We held interests in 2 gross producing wells as of December 31, 2008.

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•

Capital budget—Our capital expenditures for 2008 for the Paradox Basin were $30.6 million for participation in the drilling of six gross wells.

Yellow Jacket

        This prospect targets natural gas from the Gothic shale at depths of 4,500 to 6,500 feet. Through 2008, we had drilled four exploratory vertical science wells to gather rock property data, and three horizontal well bores. Two of these wells were placed on production in December 2008 with a third well waiting on completion of pipeline facilities. In 2009, we intend to drill at least seven exploratory tests using horizontal well bores in an attempt to further delineate this prospect. We serve as operator in this area and have an average working interest of 55%.

Green Jacket

        This prospect targets natural gas from the Hovenweep shale at depths of 4,500 to 6,500 feet and is directly adjacent to our Yellow Jacket prospect. We drilled one vertical science well in 2008, which was immediately converted into a horizontal wellbore, and is now waiting on completion plans. We plan to drill one horizontal exploratory well on this prospect in 2009. We 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 located on the flanks of salt diapirs. After sell down to an 80% working interest level, we drilled our first exploratory test on our Pine Ridge prospect in 2008. The well is currently waiting on the lifting of seasonal restrictions. Testing may only occur between July 5, 2009 and October 31, 2009. No further drilling activity is anticipated in 2009.

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 drilled four Cody Shale wells and completed and tested one of those wells. The Pulis 7-15 tested approximately 1,000 Mcf/d with 859 barrels of water per day over a 9 day flow period. In 2009, we plan to test the remaining three wells drilled in 2008 and, depending on the results of the vertical wells, drill one horizontal test in the Cody Shale.

Key Statistics

•

Acreage—We held 174,448 net undeveloped acres as of December 31, 2008.



•

Capital budget—Our capital expenditures for 2008 were $7.9 million for participation in the drilling of four gross wells.

Big Horn Basin

        The Big Horn Basin is located in north central Wyoming. We are in the initial phases of an exploration project targeting both structural-stratigraphic and basin-centered tight gas plays. Our working interest in this project is 50%. In 2008, we drilled and ran casing on one well to a depth of 10,705 feet in order to test the Fort Union Formation. We expect to complete and test this well in the second quarter of 2009.

Key Statistics

•

Acreage—We held 64,155 net undeveloped acres at December 31, 2008.

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•

Capital budget—In 2008, we spent $1.4 million for drilling one exploratory test in the Big Horn Basin.

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, 2008, 2007 and 2006 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 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., or NSAI. NSAI reviewed all of our reserve estimates at December 31, 2007 and 2008. 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.

(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, 2008, 2007 and 2006, which were $4.61 per MMBtu of gas and $41.00 per barrel of oil at December 31, 2008, $6.04 per MMBtu of gas and $92.50 per barrel of oil at December 31, 2007, and $4.46 per MMBtu of gas and $61.06 per barrel of oil at December 31, 2006. These prices were adjusted by lease for quality, transportation fees and regional price differences.

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        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 December 31, 2008, we revised our proved reserves upward by 146.4 Bcfe, excluding pricing revisions, primarily as a result of adding increased density proved undeveloped locations in the Piceance Basin and West Tavaputs area and improved production performance by wells located in each of our major producing basins: Wind River, Uinta, Powder River and Piceance. We revised our 2008 year-end proved reserves downward by 7.3 Bcfe, as year-end 2008 pricing was $4.61 per MMBtu and $41.00 per barrel of oil, relative to year-end 2007 pricing of $6.04 per MMBtu and $92.50 per barrel of oil. Year-end prices were adjusted by lease for quality, transportation fees and regional price differences. 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 area and continued improved performance of wells drilled in the West Tavaputs area and Piceance Basin. 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.

        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, 2008, 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, 2008, the estimate provided by NSAI was 6.3% below our reserve estimate. Our independent reserve engineers arrived at reserve estimates that were greater than 10% above or 10% below our estimates for approximately 54% of our wells. This represents approximately 56% of the total proved reserves covered in the review reports. At the material property

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level, the independent engineer reserve estimates ranged between 5.8% above our internal reserve estimates to 1.7% below our estimates in the year-end 2008 report. 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.

        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.



•

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.

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        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 2008 and 2007, we paid NSAI approximately $220,000 and $216,000, respectively, for reviewing our reserve estimates. We did not employ NSAI for other consulting services during either year. During 2008 and 2007, we did not employ Ryder Scott to review our reserves or provide other consulting services.

        On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management system, which is a widely accepted set of evaluation guidelines that are designed to support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers, or SPE, Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the current method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company's disclosures and financial statements.

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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:

(1)

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

(2)

Includes the effects of hedging transactions, which increased average natural gas prices by $0.56, $1.52 and $0.46 per Mcf in 2008, 2007 and 2006, respectively, and reduced average oil prices by $13.72, $1.31, and $5.90 per Bbl in 2008, 2007 and 2006, respectively.

(3)

The depreciation, depletion and amortization, or DD&A, per Mcfe for the years ended December 31, 2007 and 2006 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 $16.8 million, $10.2 million and $6.5 million for the years ended December 31, 2008, 2007 and 2006, respectively, which equates to a reduction to G&A of $0.22 per Mcfe, $0.17 per Mcfe and $0.12 per Mcfe, respectively. G&A expense excluding non-cash stock-based compensation is a non-GAAP measure. Non-cash stock-based compensation is combined with general and administrative expense for a total of $57.2 million, $42.2 million and $34.2 million for the years ended December 31, 2008, 2007 and 2006, respectively, in the Consolidated Statements 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, which may have higher or lower costs associated with equity grants.

Productive Wells

        The following table sets forth information at December 31, 2008 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

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deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

        The following table sets forth information as of December 31, 2008 relating to our leasehold acreage.

(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 105,862 net undeveloped acres that are subject to drill-to-earn agreements are not included.

        Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able to obtain extensions of the primary terms of our federal leases for the period 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,

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as of December 31, 2008, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

(1)

Includes 420,052 gross and 261,636 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.

(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 2008, we completed 196 gross (176.6 net) productive and no dry development wells and 17 gross (12.0 net) productive and no dry exploratory wells.

(2)

The exploratory dry hole category for the period ended December 31, 2008 excludes two scientific wells that were drilled for data gathering purposes that are included in exploration expense in the Consolidated Statement of Operations.

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Operations

General

        In general, we serve as operator of wells in which we have a greater than 50% working 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 the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority 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 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.

        During 2008, EnCana Oil & Gas and Sempra Energy Trading Corporation accounted for 16.7% and 16.6%, 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. 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. 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.

        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 natural gas prices. For a more detailed discussion, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."

        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, Uinta, Powder and Paradox 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

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capacity. These agreements are subject to the limitations discussed above in this paragraph. The following table sets forth information about material long-term firm transportation contracts for pipeline capacity and firm processing contracts, both of which typically require a demand charge and firm sales contracts.

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 our oil and natural gas production a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with counterparties that we believe are creditworthy. For additional information on our hedging activities, see "Item 7A. 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 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

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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 that 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 cool summers sometime 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;



•

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;

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•

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 permitting, 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, 2008, 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 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 is 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 or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

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        Comprehensive Environmental Response, Compensation and Liability Act.    The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "superfund" law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site, or site where the release occurred, and companies that disposed or arranged for the disposal of the hazardous substance. 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. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development.

        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.

        Climate Change.    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

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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 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.

        Homeland Security.    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, federal, state, local, 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;



•

wildlife management and protection;



•

property mitigation measures;



•

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.

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        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 or 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 that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in "first sales," which include all of our sales of our own production.

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

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Employees

        As of January 30, 2009, we had 274 full time equivalent employees. Of our 274 equivalent full time employees, 163 work in our Denver office and 111 are in our 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.

Offices

        As of December 31, 2008, 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 or deemed to be part of this Annual Report on Form 10-K.

Annual CEO Certification

        As required by New York Stock Exchange rules, on May 19, 2008 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.

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.

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        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.

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

        Coalbed methane or 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.

        Delineation.    The process of drilling wells away from, or that is removed from, a known point of well control.

        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 or EA.    An environmental assessment, a study that can be required pursuant to federal law prior to drilling a well.

        Environmental Impact Statement or 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.

        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.

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        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.

        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 or 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 or 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.

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        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.

        Record of Decision or ROD.    A document that authorizes or denies the activity analyzed by an Environmental Impact Statement and provides the basis for this decision.

        Resource Management Plan or RMP.    A document that describes the Bureau of Land Management's intended uses of lands that are under its jurisdiction.

        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.

        Shale gas.    Considered to be an unconventional accumulation of natural gas where the gas is recovered from extremely low permeability shales, generally through the use of horizontal drilling and massive hydraulic fracturing.

        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.

        Structural Play.    An accumulation of oil and gas in rock strata that has been folded or faulted.

        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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The continuing U.S. and global economic crisis could have a material adverse effect on our business and operations.

        Any or all of the following may occur as a result of the continuing crisis in the U.S. and world financial and securities markets:

•

We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower growth in our production and reserves than if we were able to spend more than our cash flow as we have in the past. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.



•

The economic slowdown has led and could continue to lead to lower demand for oil and natural gas by individuals and industries, which in turn has resulted and could continue to result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses.



•

The lenders under our credit facility may become more restrictive in their lending practices or unable or unwilling 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.



•

The losses incurred by financial institutions as well as the bankruptcy of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.



•

Our credit facility, which was amended on October 20, 2008 (the "Amended Credit Facility"), bears floating interest rates based on the London Interbank Offer Rate (LIBOR). Recently, as banks were reluctant to lend to each other to avoid risk, LIBOR had increased to unprecedented spread levels. This causes higher interest expense for unhedged levels of LIBOR-based borrowings.



•

Our Amended Credit Facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to calculate reserves pursuant to the Amended Credit Facility. It is feasible that the banks could reduce their price deck and our borrowing base could be reduced. This would reduce our funds available to borrow.



•

Pipeline companies may be unable to obtain funding for new pipelines, leading to an increased inability to transport gas out of our operating areas in the Rocky Mountains to markets with higher demand and higher prices. As a result, we could be faced with lower prices in the Rocky Mountain region due to increasing supplies and lower demand in the region compared to more populated and more heavily industrialized areas with higher demand. This would result in lower revenues for us and possibly losses.



•

Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.



•

Bankruptcies of purchasers of our natural gas and oil could lead to the delay or failure of us to receive the revenues from those sales.

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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 or at all, 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;



•

our ability to acquire, locate and produce new reserves;



•

global credit and securities markets; and



•

the ability and willingness of lenders and investors to provide capital and the cost of that capital.

        If our revenues or the borrowing base under our Amended 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 Amended 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 Amended 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.

Drilling for and producing oil and natural gas are risky 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 or other features;



•

pressures;



•

fires;



•

blowouts;



•

loss of drilling fluid circulation;



•

title problems;

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•

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 coalbeds 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. Coalbeds, 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 coalbed well can range from five to 11 years depending on the coal seam compared to up to 30 years for a non-coalbed 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.

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.

        Underground accumulations of oil and natural gas can not be measured 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.

        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 2008 at prices of $4.61 per MMBtu of gas and $41.00 per barrel of oil, relative to year-end 2007 prices of $6.04 per MMBtu and $92.50 per barrel of oil, was downward 7.3 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

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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—15. 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, 2008, 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 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. 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 or impacted by nearby coal mining activities.

        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. In addition, activities related to the mining of coal near our operations, including core-hole drilling to determine the aerial extent of coal deposits and the mining of coal, may introduce oxygen into our producing wells and compressors, causing production to be shut-in, or allow hydrocarbons to escape before they can be recovered. This would lead to a loss of reserves and revenues.

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

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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 2009, we plan to participate in the drilling of up to 163 gross wells depending on budgetary considerations.

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 and the amount of hydrocarbons. 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.

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.

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

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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 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 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 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, such as our delayed EIS in the West Tavaputs area, 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 future Rocky Mountain operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. Our properties located in Colorado are subject to the authority of the Colorado Oil and Gas Conservation Commission, or 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

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composition of the COGCC to reduce industry representation and to add the heads of the Colorado Department of Natural Resources, or CDNR, and the Colorado Department of Public Health and Environment, or 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 Division of Wildlife, or CDOW, 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. These rules become effective April 1, 2009 for the majority of our Colorado operations area. We believe the revised rules will cause additional costs and may cause delay in our operations in Colorado. The rules require consultation with the CDOW and CDPHE prior to drilling and completion operations in our Piceance Basin and for the portion of the Paradox Basin located in Colorado. The requirements for this consultation are open-ended and resulting permit restrictions remain subject to appeal by the CDOW, CDPHE and the surface owner. The CDOW may attempt to prohibit drilling and completion operations for some period corresponding to wildlife's use of the habitat. CDPHE may choose to impose costly conditions of approval and limit the areas that can be developed. If we are not able to avoid adverse requirements, our Piceance Basin and, if our Paradox Basin exploratory activities are successful, the Colorado portion of our Paradox Basin production and production growth would be reduced. In addition, the costs of these and the other proposed rules could add substantial increases in incremental well costs in our Colorado operations. The rules also would impact the ability and extend the time necessary to obtain drilling permits, which creates substantial uncertainty about our ability to obtain sufficient permits in a timely fashion in order to meet future drilling plans and thus production and capital expenditure targets. It is also possible that similar rules will be proposed in the other states in which we operate, further impacting our operations.

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 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.

        Natural gas prices in the Rocky Mountain region can fall 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

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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 that 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 remaining properties for reserve potential. 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.

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 our 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.

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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, we currently, and will likely 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.

        Our counterparties are typically financial institutions, who are lenders under our Amended Credit Facility. The risk that a counterparty may default on its obligations is heightened by the recent financial sector crisis and other 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. Current economic circumstances and the increased bankruptcies may further increase these risks.

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.

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

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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 Amended Credit Facility for a portion of our future capital needs. Our current Amended 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 Amended 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 Amended 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 Amended 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 Amended 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 17 banks. With the current turbulent credit markets, 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 and declining production and potentially losses.

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" including carbon dioxide and methane, may be contributing to warming of the Earth's 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 in Massachusetts, 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.

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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 have experienced and 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, including economic or other conditions that affect the demand for oil and natural gas;



•

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, 2008, we had 45,128,431 shares of common stock outstanding, excluding stock options. All of the outstanding shares are freely tradable, other than shares held 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 5,075,088 of our outstanding shares. This registration may be accomplished quickly by filing prospectus supplements under an automatically effective shelf registration statement. The resale of a large number of shares could cause our stock price to decline.

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;

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•

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. and Warburg Pincus Private Equity X, L.P. collectively own approximately 13.7% of our outstanding common stock. Accordingly, these related stockholders 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. and Warburg Pincus Private Equity X, L.P.

        Furthermore, conflicts of interest could arise in the future between us, and Warburg Pincus concerning, among other things, potential competitive business activities or business opportunities. None of our 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 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. In September 2008, we entered into a consent decree with the EPA pursuant to which we and our industry partner agreed to pay a fine of $240,000, of which we agreed to pay $140,000. The consent decree is subject to the approval of the United States federal court for the District of Utah.

        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:

        On January 30, 2009, the closing sales price for our common stock as reported by the NYSE was $22.11 per share.

        Holders.    On January 30, 2009, the number of holders of record of common stock was 397.

        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 Amended 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.    We did not have any issuer purchases of equity securities in the fourth quarter ended December 31, 2008.

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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 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.

Total Return Among Bill Barrett Corporation, the Standard & Poors 500 and the Standard and Poors MidCap 400-Energy Sector

(1)

December 10, 2004 was 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.

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Item 6.    Selected Financial Data

        The following table presents our selected historical financial data for the years ended December 31, 2008, 2007, 2006, 2005 and 2004. 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 consolidated 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, 2008, 2007 and 2006 and the balance sheet information as of December 31, 2008 and 2007 are derived from our audited financial statements included elsewhere in this report. The income statement information for the years ended December 31, 2005 and 2004 and the balance sheet information at December 31, 2006, 2005 and 2004 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.