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

On:  Wednesday, 2/23/11, at 11:31am ET   ·   For:  12/31/10   ·   Accession #:  1193125-11-43180   ·   File #:  1-32367

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  As Of               Filer                 Filing    For·On·As Docs:Size             Issuer                      Filing Agent

 2/23/11  Bill Barrett Corp                 10-K       12/31/10   41:7.1M                                   Donnelley … Solutions/FA

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                Independent Petroleum Engineer                                   
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                Dated February 3, 2011                                           
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                Executive Officer                                                
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                Financial Officer                                                
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

For the fiscal year ended December 31, 2010

or

For the transition period from                     to                    

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.     x  Yes    ¨  No

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    ¨  No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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).     ¨  Yes    x  No

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010 based on the $30.77 closing price of the registrant’s common stock on the New York Stock Exchange was $1,267,385,616.*

As of January 28, 2011, the registrant had 46,876,131 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 2011 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant’s fiscal year ended December 31, 2010.

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:

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 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

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this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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PART I

BUSINESS

General

Bill Barrett Corporation (“we,” “our” or “us”) explores for and develops oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value through profitable growth in reserves and production, which will include investing in and profitably developing key existing development programs as well as growth through exploration and acquisitions. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas, natural gas liquids (“NGLs”) and oil production at market prices and the settlement of commodity hedges.

We were formed in January 2002 and are incorporated in the State of Delaware. We began active natural gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin of Wyoming. Also in 2002, we completed two additional acquisitions of properties in the Uinta (Utah), Wind River (Wyoming), Powder River (Wyoming) and Williston (North Dakota, South Dakota and Montana) Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired properties in and around the Gibson Gulch field in the Piceance Basin of Colorado. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. We received net proceeds of $347.3 million after deducting underwriting fees and other offering costs. We completed an acquisition in May 2006 of coalbed methane properties located in the Powder River Basin. In June 2007, we completed the sale of our Williston Basin properties.

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.”

The following table provides information regarding our operations by basin as of December 31, 2010:

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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.

Areas of Operation

Piceance Basin

The Piceance Basin is located in northwestern Colorado. We began operations in the Gibson Gulch area of the Piceance Basin on September 1, 2004, with the purchase of producing and undeveloped properties.

Key Statistics

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The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend at depths of approximately 7,500 feet. Through 2006, we drilled on a 20-acre well density. Beginning in 2007, we commenced drilling on 10-acre density and our year-end reserves include proved reserves associated with 10-acre density. Our natural gas production in this basin is currently gathered through our own gathering system and EnCana Oil & Gas Corporation’s gathering system and delivered to markets through a variety of pipelines, including pipelines owned by Questar Pipeline Company, Northwest Pipeline, Colorado Interstate Gas, TransColorado Pipeline, Wyoming Interstate Gas Company and Rockies Express Pipeline LLC. The energy content of our Piceance gas is 1.13 British Thermal Units (“BTUs”) per mcf and the natural gas is processed at an Enterprise Products Partners L.P. plant in Meeker, Colorado. We have the option annually to elect to process liquids with Enterprise Products Partners L.P. and receive the value of NGLs for a portion of our production. In 2010 and 2011, we have elected the liquids option and are receiving OPIS (“Oil Price Information Service”) Mt. Belvieu prices for our NGLs, which are currently priced at a premium to natural gas on an energy equivalent basis.

Uinta Basin

The Uinta Basin is located in northeastern Utah. Our development operations are conducted in the West Tavaputs area, and the Lake Canyon/Blacktail Ridge area. We also have a position in several exploration prospects in the Uinta Basin.

Key Statistics

West Tavaputs

The Record of Decision (“ROD”) for the West Tavaputs Environmental Impact Statement (“EIS”) was issued on July 29, 2010. The ROD authorized full field development consistent with agreements reached with environmental stakeholders in the area. The EIS was initiated in February 2005. Issuance of a favorable ROD represents the culmination of over five years of efforts by us, the U.S. Department of the Interior and the US

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Bureau of Land Management (“BLM”) and various cultural, wildlife and wilderness interest groups toward the responsible development of natural gas within the project area. With no appeals or protests received during the final appeals period, the BLM began issuing permits for drilling pursuant to the EIS in September 2010.

We serve as operator of our interests in the West Tavaputs area. As of December 31, 2010, we had identified 698 potential drilling locations and 386.9 Bcfe of estimated proved reserves with a weighted average working interest of 97%. We are actively drilling our shallow program, which targets the gas-productive sands of the Wasatch and Mesaverde formations at depths down to 7,600 feet on average. We drilled 18 shallow wells in 2010, 10 since the issuance of the ROD, and completed 19 wells. In 2011, we plan to drill up to 97 shallow wells and complete 77 wells. The Wasatch and Mesaverde formations currently are being developed on 40-acre density in the Peter’s Point Unit on the eastern side of the field, following testing and analysis of 40-acre pilots in 2007 and 2008. Throughout 2011, a 20-acre pilot program will be initiated in the Peter’s Point Unit. In 2008 and 2009, we conducted 20-acre density pilots in the Prickly Pear unit on the western side of the field. We believe that results of these pilots have proved encouraging and activity in 2011 will be on 20-acre density. As of December 31, 2010, we were in the process of drilling 2 gross (1.6 net) wells and were waiting to complete 9 gross (8.7 net) wells in the West Tavaputs area.

Our natural gas production in this basin is currently gathered through our own gathering systems and delivers into Questar Pipeline Company and Three Rivers Gathering, LLC. Gas delivered into Questar Pipeline is processed by Questar Transportation Services Company, and gas delivered into Three Rivers Gathering can be processed by QEP Field Services Co and Chipita Processing LLC. Gas can then be marketed through a variety of pipelines including Questar Pipeline Company, Northwest Pipeline, CIG, and Wyoming Interstate Gas Company.

Blacktail Ridge/Lake Canyon

Blacktail Ridge. In December 2006, we entered into an exploration and development agreement with the Ute Indian Tribe of the Uintah and Ouray Reservation, (“Ute Tribe”), and the Ute Development Corporation to explore for and develop oil and natural gas on approximately 51,000 of the Ute Tribe’s net undeveloped acres located in Duchesne County, Utah. Pursuant to this agreement, we serve as operator and have the right to earn a minimum of a 50% working interest in all formations. To earn these interests, we were required to drill five Wasatch formation wells in 2007 followed by eight Wasatch wells per year thereafter. The Ute Tribe has an option to participate in all drilled wells up to a 50% working interest. The Ute Tribe is subject to working interest adjustments in any infill drilling, pending its participation in previous acreage earning wells. 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.

In 2009, we negotiated with the Ute Tribe a suspension of the eight well drilling obligation for that year. One well of the 2009 obligation was drilled in 2008 and the remaining seven wells will now be drilled in 2012. In 2010 and 2011, we were again obligated to drill eight Wasatch wells in each year. In 2010, we drilled 17 wells which fulfilled our 2010 program, and four of those wells can be carried forward to fulfill our drilling obligation in 2011. 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. We currently are focused on developing interior field locations on 160 acre density and are considering an 80 acre infill pilot. As of December 31, 2010, we were in the process of drilling 1 gross (0.5 net) well and were waiting to complete 3 gross (2.0 net) wells within the Blacktail Ridge area. Our gas production is gathered and processed by a third party, and our oil production is sold and trucked to the Salt Lake area to be refined.

Lake Canyon. In 2004, we and an industry partner entered into a drill-to-earn exploration and development agreement with the Ute Tribe and Ute Development Corporation to explore for and develop oil and natural gas on approximately 125,000 of the Ute Tribe’s net undeveloped acres that are located in Duchesne and Wasatch Counties, Utah. Pursuant to this agreement, we had 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

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to a 25% interest in the shallower Green River formations. The exploration and development agreement was amended in October, 2009 to allow for the suspension of the 2009 drilling schedule due to our inability to secure easements and permits to access the property. In 2010, we further amended the exploration and development agreement to provide for combined interests of the partners in all depths. This allows the drilling of a single wellbore and commingling of production rather than requiring that we and our industry partner drill separate wells, which should improve the economics of new wells. Further, the amendment calls for us to operate a northern block (consisting of 19,781 net tribal acres) with a 75% working interest, and for our partner to operate a southern block, where we retain a 25% working interest. The Ute Tribe has an option to participate in a 25% working interest in wells drilled pursuant to the agreement. The amended agreement also provides for us and our industry partner to drill at least four obligation wells each in 2010 and two obligation wells each from 2011 through 2015 with an additional requirement of 14 optional wells being drilled at some point between 2011 and 2015. As of December 31, 2010, we were not in the process of drilling any wells in the Lake Canyon area. Through December 31, 2010, we had drilled a total of 9 gross (7 net) wells under the exploration and development agreement, including 4 gross (3 net) wells in 2010, and earned 7,099 gross (4,113 net) acres in this prospect. Our gas production is gathered and processed by a third party, and our oil production is sold and trucked to the Salt Lake area to be refined.

Hornfrog

At our Hornfrog natural gas prospect located southeast of West Tavaputs, we continue to produce from two wells completed in September 2010. One of the two wells continues to indicate production similarities to West Tavaputs. We intend to drill four wells in the area in 2011 as part of a drill-to-earn program for 55% working interest in up to 30,700 gross acres, subject to the resolution of a dispute between our farmout partner and third parties.

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. We also have a position in several exploration projects not related to coalbed methane wells.

Key Statistics

Coalbed Methane

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,

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stabilizes and then begins declining. The average life of a coalbed well can range from five to 11 years depending on the coal seam.

Our natural gas production in this basin is gathered through 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

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.

McRae Gap

We are in the process of assessing the Niobrara shale oil potential in our 90,800 net acre McRae Gap prospect along the southern flank of the Wind River basin. Casing was set on our first exploration well, the NMGU 11H-29-34-87, in November 2010 at a measured depth of 11,686 feet after drilling almost 3,200 feet of lateral section. Due to environmental stipulations, completion work will not commence on this well until the third quarter of 2011. We serve as operator and maintain a 75% working interest in the prospect, with the remaining working interest being earned through a carried working interest by an industry partner.

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. In 2011, we intend to market a portion of our working interest in our

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prospects within the Paradox Basin to one or more third parties. Further drilling activity will depend on the results of the marketing efforts.

Key Statistics

Yellow Jacket

This prospect targets natural gas from the Gothic shale at depths of 4,500 to 6,500 feet. Through 2010, we had drilled four exploratory vertical wells to gather rock property data, and nine horizontal well bores. Eight of these wells were on production at various times in 2010. Impairment charges were taken against producing wells during 2009 due to sub-economic performance. In 2010, we re-acquired the working interest from our industry partner and now serve as operator with an average working interest close to 100%.

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. This well was production tested in early 2009 and recorded as a dry hole in 2010. We serve as operator in this area where we have a working interest close to 100%.

Salt Flank

We have an 80% working interest in our Salt Flank exploration prospect where we are targeting natural gas in stratigraphic and structural traps located on the flanks of salt diapirs. Our first exploration well was tested in 2009 and declared a dry hole due to insufficient gas volumes.

Other Exploration Prospects

In addition to the exploration prospects described above, the following is a description of activities that occurred during 2010 and that are planned for 2011 for the following basins. Historically, we have assembled large acreage positions and recovered a portion of our costs by selling an interest to industry partners. We typically retain at least a 50% interest and operatorship.

Big Horn Basin—Red Point

The Big Horn Basin is located in north central Wyoming. We are targeting both structural-stratigraphic and basin-centered tight gas exploratory plays. Our working interest in this prospect is 58%. We held 63,906 net undeveloped acres at December 31, 2010. In 2010, we hooked up our Sellers Draw well in an attempt to evaluate the Mesaverde potential in a pre-existing well-bore. Production from the well was limited and short lived, and the related costs were recorded as dry hole expense in 2010. We are marketing part of our working interest in this prospect, and any further drilling activity will depend on the results of this sell down effort.

Deseret Basin

The Deseret Basin is a shale gas prospect that targets the Phosphoria Formation in parts of northern Utah, western Wyoming and southeastern Idaho. We have assembled over 191,791 net acres in the basin. During 2010,

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we acquired 20 square miles of 3D seismic, and drilled, cored and tested the Phosphoria in the vertical McKinnon 33-32-11-7 stratigraphic test well drilled to 9,654 feet to test the shale gas potential. While core and test results are still being analyzed, we are actively marketing the prospect to potential industry partners. We serve as operator in this area where we currently have a working interest of 100%.

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, 2010, 2009 and 2008 based on reserve reports prepared by us and audited in their entirety by outside independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our estimates independently audited, we are required by our revolving credit agreement with our lenders to have an independent third party engineering firm perform an annual audit of our estimated reserves. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc., or NSAI, audited all of our reserves estimates at December 31, 2010, 2009 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 third party petroleum engineers. However, in the aggregate, the independent third party 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, since January 1, 2010.

The data in the above table represent 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 reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See “Item 1A. Risk Factors.”

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 locations on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas can be claimed only where it can be demonstrated with reasonable certainty that there is continuity of

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economic production from the existing productive formation. Proved undeveloped reserves are included when they are scheduled to be drilled within five years.

At December 31, 2010, our proved undeveloped reserves were 583.2 Bcfe, all of which were scheduled to be drilled within five years. At December 31, 2009, our proved undeveloped reserves were 484.6 Bcfe. During 2010, 83.2 Bcfe or 17.2% of our December 31, 2009 proved undeveloped reserves (130 wells) were converted into proved developed reserves requiring $160.2 million of drilling and completion capital and $28.1 million of facilities capital. These wells produced 16.7 Bcfe in 2010. An additional 4.2 Bcfe were removed from the proved undeveloped reserves category because they were either traded or sold or they exceeded the five year limit for proved undeveloped reserves. Positive engineering and pricing revisions added 75.7 Bcfe to the proved undeveloped reserves category. The positive engineering revision in the Gibson Gulch area of the Piceance Basin included 24.7 Bcfe resulting from the addition of proved undeveloped reserves in locations greater than one direct spacing unit from economic producers. Production from the Gibson Gulch area is from a very large, basin-centered gas accumulation containing reservoirs with no apparent downdip water. The reasonable certainty for economic reserves from these locations is supported by geologic, engineering and economic data in addition to well productivity across the Gibson Gulch area and across the Piceance Basin. Positive pricing revisions occurred in all of our producing areas due to the pricing change from $3.04 per MMBtu CIG for the year ended December 31, 2009 to $3.95 per MMBtu for the year ended December 31, 2010 and $57.65 per Bbl WTI for the year ended December 31, 2009 to $75.96 per Bbl for the year ended December 31, 2010. The proved undeveloped reserves from December 31, 2009 that remain in the proved undeveloped reserves category at December 31, 2010 are 380.5 Bcfe. The December 31, 2010 proved undeveloped reserves of 583.2 Bcfe result from adding the December 31, 2009 remaining proved undeveloped reserves of 380.5 Bcfe to the proved undeveloped reserves generated in 2010 from the 2009 and 2010 drilling program (127.0 Bcfe) and the positive engineering and pricing revisions (75.7 Bcfe). The 127.0 Bcfe were the result of estimating reserves with reasonable certainty of economic production when drilled on undrilled acreage in development spacing areas that were directly offsetting new economic producers.

The majority of production from the Gibson Gulch area of the Piceance Basin is from the discontinuous fluvial sands of the Williams fork formation. The resource is consistent across the Gibson Gulch area and results in low variability of estimated ultimate recoveries. The 2010 results of proved undeveloped drilled wells in offsets two spacing areas from economic producing wells were positive and supported a third offset in the proved undeveloped reserve category as of December 31, 2010 (39 wells, 24.7 Bcfe). New technologies were not used to support these reserves. The opportunity to use this data to prove more than one direct offset from economic producers is the result of a change in definition for undeveloped oil and gas reserves included in the SEC’s “Modernization of Oil and Gas Reporting” and applied in our December 31, 2009 and December 31, 2010 reserve reports. The proved undeveloped reserves added in the Gibson Gulch area at December 31, 2010 were 124.7 Bcfe, of which 24.7 Bcfe were attributed to the addition of a third offsetting proved undeveloped spacing area from economic producers.

At December 31, 2010, we revised our proved reserves upward by 39.8 Bcfe, excluding pricing revisions, due to improved production performance in Gibson Gulch area and in the Wind River Basin and the addition of 24.7 Bcfe of reserves from third proved undeveloped spacing areas added in the Gibson Gulch area. A positive revision of 27.4 Bcfe occurred due to the positive pricing changes described above.

At December 31, 2009, our proved undeveloped reserves were 484.6 Bcfe, all of which were scheduled to be drilled within five years. At December 31, 2008, our proved undeveloped reserves were 383.2 Bcfe. During 2009, 82.5 Bcfe or 22% of our December 31, 2008 proved undeveloped reserves (71 wells) were converted into proved developed reserves requiring $81.7 million of drilling and completion capital and $9.5 million of facilities capital. An additional 7 Bcfe were removed from the proved undeveloped reserves category because they exceeded the five year limit for proved undeveloped reserves, 29.3 Bcfe were added to the proved undeveloped reserves category due to engineering revisions primarily resulting from increased performance in the Gibson Gulch area and 28.5 Bcfe were sub-economic and were removed from the proved undeveloped reserves category

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due to the pricing change from $4.60 per MMBtu CIG at December 31, 2008 to $3.04 per MMBtu for the year ended December 31, 2009. The proved undeveloped reserves from December 31, 2008 that remained in the proved undeveloped reserves category at December 31, 2009 were 294.4 Bcfe. The December 31, 2009 proved undeveloped reserves of 484.6 Bcfe resulted from adding the December 31, 2008 remaining proved undeveloped reserves (294.4 Bcfe) to the proved undeveloped reserves generated in 2009 (190.2 Bcfe). Of the 190.2 Bcfe of proved undeveloped reserves generated in 2009, 103.7 Bcfe were the result of estimating reserves with reasonable certainty of economic production when drilled on undrilled acreage in development spacing areas that were directly offsetting new economic producers resulting from our 2008 and 2009 capital drilling programs. The remaining 86.3 Bcfe were the result of estimating reserves with reasonable certainty of economic production when drilled on development spacing areas that are second offsets (instead of direct offsets) from economic producers in the Gibson Gulch area of the Piceance Basin. The proved undeveloped reserves added in the Gibson Gulch area at December 31, 2009 were 170.0 Bcfe, of which 86.3 Bcfe are attributed to the addition of a second offsetting proved undeveloped spacing areas from economic producers.

At December 31, 2009, we revised our proved reserves upward by 101.5 Bcfe, excluding pricing revisions, due to improved production performance in Gibson Gulch, West Tavaputs and Blacktail Ridge and the increased revenue associated with the recovery of NGLs and reduced drilling and completion costs in the Gibson Gulch area. Also included in the engineering revisions is the addition of 64 Bcfe from second proved undeveloped spacing areas added in Gibson Gulch. The total reserves from the second spacing areas in Gibson Gulch was 86.3 Bcfe, of which 64 Bcfe was in the engineering revision category and 22.3 Bcfe was in the extension and discoveries category resulting from drilling and completion operations in 2009.

At December 31, 2008, we revised our 2008 year-end 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 use our internal reserves estimates rather than the estimates from independent third party 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 third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance to the independent third party 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 third party engineers. These differences are investigated by us and the independent third party engineers and discussed with the independent third party 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.

The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, includes but is not limited to the following:

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Within our company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is Lynn Boone Henry. Ms. Henry is our Senior Vice President—Planning and Reserves and has been responsible for the reserves since 2003. Ms. Henry attended the Colorado School of Mines and graduated in 1982 with a Bachelor of Science degree in Chemical and Petroleum Refining Engineering. She attended the University of Oklahoma and graduated in 1985 with a Master of Science degree in Petroleum Engineering. Ms. Henry has been involved in evaluations and the estimation of reserves and resources for 24 years. She has managed the technical reserve process at a company level for ten years.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical person primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein is Dan Paul Smith. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. He is a Registered Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering.

NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI’s audit report does not state the degree of its concurrence with the accuracy of our estimate for the proved reserves attributable to our interest in any specific basin, property or well.

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

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The reserves audit 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. The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.

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 to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its respective employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI’s estimates of reserves and future cash inflows for the subject properties. During 2010 and 2009, we paid NSAI approximately $230,000 and $252,000, respectively, for auditing our reserves estimates. We did not employ NSAI for other consulting services during either year.

On December 31, 2008, the SEC published final rules and interpretations updating its oil and gas reserves reporting requirements called “Modernization of Oil and Gas Reporting.” Many of the revisions were 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,

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or SPE, Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules related to using a 12-month average commodity price to calculate the value of proved reserves versus the former method of using year-end prices. Other key revisions included 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. Companies were required 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 31, 2009. Early adoption was not permitted. Changes in our reserves estimates as of December 31, 2009, compared with the methodology used in 2008 based on the prior SEC rules, included:

Production and Price History

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

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Productive Wells

The following table sets forth information at December 31, 2010 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2010 relating to our leasehold acreage.

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Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. We generally have been able to obtain extensions of the primary terms of our federal leases for the period in which we have been unable to obtain drilling permits due to environmental stipulations, pending environmental analysis or related legal challenge. The following table sets forth, as of December 31, 2010, the expiration periods of the gross and net acres that are subject to leases summarized in the above table of undeveloped acreage.

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. The table reflects the revised SEC oil and gas disclosure rules.

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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. We do construct, operate and maintain a majority of the gas gathering and compression facilities associated with our gas fields. 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 2010, Enterprise Gas Processing LLC and ConocoPhillips Company accounted for 13.7% and 11.7%, respectively, of our oil and gas production revenues. During 2009, Sempra Energy Trading Corporation and Enterprise Gas Processing, LLC accounted for 14.9% and 10.4%, respectively, of our oil and gas production revenues. During 2008, EnCana Oil & Gas and Sempra Energy Trading Corporation accounted for 16.7% and 16.6%, respectively, of our oil and gas production revenues.

We enter into hedging transactions with unaffiliated third parties for portions of our production revenues to achieve more predictable cash flows and to reduce our exposure to fluctuations in commodities 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 is 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 gatherer, 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 that has contracted for pipeline capacity. These agreements are subject to the limitations discussed above in this paragraph.

Our oil production is collected in tanks and sold to third parties that collect the oil in trucks and transport it to refiners. We sell our oil production to a variety of purchasers under monthly, annual or multi-year terms. Our oil contracts are priced either off of NYMEX or area oil posting with location or transportation differentials. We contract only for volumes that have been produced.

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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. We source the gas to meet these commitments from our producing properties. At the time we entered into these commitments, we estimated that our production, and the production of joint interest owners that we market, would be sufficient to meet these commitments. Under these firm gathering, transportation and processing contracts, we are obligated to deliver minimum daily gas volumes, or pay the respective gathering, transportation or processing fees for any deficiencies in deliveries. With the firm sales contracts, we are obligated to sell minimum daily gas volumes. If the volumes are not met, we will bear our proportionate share of costs related to the volume shortfall.

Hedging Activities

We have an active commodity hedging program to mitigate the risks of the volatile prices of natural gas, NGLs and oil. Typically, we intend to hedge approximately 50-70% of our oil and natural gas production on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments with counterparties that we believe are creditworthy. To date all of our hedging counterparties are lenders or affiliates of lenders under our credit facility and we are not required to post collateral for our hedges other than the security for our credit facility. For additional information on our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies, some 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 than we can, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. 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 lower demand periods. 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:

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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 and timing 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 are in compliance with and have complied, with all applicable environmental laws and regulations. We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with governmental regulations. We believe that our continued compliance with existing requirements have been accounted for and 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 any more stringent future laws and regulations at this time. For the year ended December 31, 2010, 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 that could have a material impact on the oil and natural gas exploration and production industry and our business 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 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 may trigger 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

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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.” An environmental organization recently petitioned the EPA to reconsider certain RCRA exemptions for exploration and production 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 have held, and continue to hold, all necessary and up-to-date approvals, 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.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “superfund” law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for a release or threatened release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site, or site where the release or threatened release of a “hazardous substance” 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, could 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 released.

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 jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms 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, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. The EPA has recently deemed carbon dioxide (“CO2”) to be a public danger which presumably will lead to regulation in a manner similar to other pollutants. The EPA now requires reporting of greenhouse gases, CO2 and methane, from operations. 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.

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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 not passed 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 CO2 emissions from power plants. The EPA has also issued certain regulatory actions to address issues related to climate change. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely CO2 and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could impact our future operations. Our operations are not currently 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 could impact our business. However, future laws or regulations could result in substantial expenditures or reduced demand for oil or natural gas.

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:

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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 can 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 NGLs within its jurisdiction.

Natural Gas Sales and 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 transporting 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 the Bureau of Indian Affairs and the Environmental Protection Agency, 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, Tribal employment contractor preferences and numerous other matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and Bureau of Land Management. However, each Native American tribe is a sovereign nation and has the right to enact and 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

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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, or delays in obtaining necessary approvals or permits pursuant to these regulations, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.

Employees

As of January 28, 2011, we had 280 full time equivalent employees of whom 163 work in our Denver office and 117 work 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 are 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, 2010, 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 2019. We also own field offices in Waltman, Wyoming, Roosevelt, Utah and Silt, Colorado, and we lease field offices in Gillette, Wyoming and Cortez, Colorado. 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, 2010 we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet of natural gas.

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

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 can be produced into a pipeline.

Completion. Installation of permanent equipment for production of oil and gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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.

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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 or Dry well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Environmental Assessment or EA. A study that can be required pursuant to federal law prior to drilling a well.

Environmental Impact Statement or EIS. 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 a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another 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.

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

Horizontal Drilling. A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontal within a designated zone typically defined as the prospective pay zone to be completed for oil and or gas.

Hydraulic fracturing. The injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.

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.

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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.

NGLs. Natural gas liquids.

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

Play. A term used to describe an accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area expanse.

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. An exploratory, development, or extension well that is not a dry well.

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 quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from know reservoirs, and under existing economic conditions, operating methods, and government regulations.

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

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

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.

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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.

Shale oil. Considered to be an unconventional accumulation of oil where the oil 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.

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 that 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

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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:

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.

Our exploratory and development drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We acquire significant amounts of unproved property in order to attempt to further our exploration and development efforts. Exploration and development drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. From time to time, we may seek industry partners to help mitigate our risk on certain exploration prospects. We cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such unproved property or wells, or that we will succeed in bringing on additional partners.

Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The seismic

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data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether natural gas or oil is present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in our shale plays may be more uncertain than in other shale plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in our shale prospects. As a result, we may incur future dry hole costs and or impairment charges due to any of these factors.

A continued U.S. and global economic downturn could have a material adverse effect on our business and operations.

Any or all of the following may occur as a result of the recent crisis in the global financial and securities markets and resulting economic downturn:

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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 and debt 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:

If our revenues or the borrowing base under our 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 credit facility places certain restrictions on 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 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 subject us 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 or subject us to liabilities as a result of other factors, including:

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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, death, environmental damage, property damage, or suspension of operations. As a result, we face the possibility of liabilities from these events that could adversely affect our business, financial condition or results of operations as well as adverse publicity that could lead to delays in or cessation of our operations in the affected area and loss of related assets or revenues.

Additionally, the coalbeds in the Powder River Basin from which we produce methane gas typically contain water, which may hamper our ability to produce gas in commercial quantities. This water must be partially removed in order for the gas to detach from the coal and flow to the well bore. 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. The life of a coalbed well typically 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 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.

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

Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of soil, protection of groundwater, and preservation of natural resources. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by

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Native American tribes. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Our Powder River Basin coalbed methane exploration and production activities involve the permitted discharge of produced groundwater into adjacent lands and waterways. 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 requirements for 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.

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 state regulation of oil and natural gas production and Native American tribes conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs, could have a material adverse effect on our ability to explore on or develop our properties. In addition, if we do not reasonably believe that we can obtain the drilling permits covering locations for which we recorded proved undeveloped reserves in a timely fashion, we may be required to write down the level of our proved reserves. 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, larger operating areas, and other aspects of their businesses. 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.”

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.

Under the direction of Congress, the EPA has undertaken a study of the affect of hydraulic fracturing on drinking water and groundwater. Congress is also currently considering legislation to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states have issued similar “fracking” disclosure rules. In addition, the Department of Interior is considering expended or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes many of the lands on which we conduct or plan to conduct operations. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production. Sponsors of bills proposed before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, and the proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. The

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adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to perform, or even prohibit, hydraulic fracturing, and complete natural gas and oil wells. Any such laws and or regulations may also increase our costs of compliance and doing business, and prevent us from accessing, developing and booking reserves in the future.

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

Underground accumulations of oil and natural gas cannot 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. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties—Oil and Gas Data—Proved Reserves” and “Notes to Consolidated Financial Statements—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. 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 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. 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.

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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.

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 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 differ materially differ from those presently identified, which could adversely affect our business.

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 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 evaluate 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 choose 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

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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.

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, weather, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

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

Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

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.

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, processing facilities and refineries 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 and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:

In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.

Our counterparties are typically financial institutions that are lenders under our credit facility. The risk that a counterparty may default on its obligations is heightened by the recent financial sector crisis and 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 production revenues, 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. Recent economic circumstances may further increase these risks.

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

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

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

Our revolving credit facility has commitments from 19 lenders. With the recent turbulent credit markets, the lenders may become more restrictive in their lending practices or may be unable to fund their commitments,

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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 reserves growth, leading to declining production and potentially losses.

We face risks related to rating agency downgrades.

If one or more rating agencies downgrades our outstanding debt, raising capital will become more difficult and more costly and we may be required to provide collateral or other credit support to pipeline companies or other parties. Providing credit support increases our costs and can limit our liquidity.

Possible additional 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 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. The EPA has initiated rulemaking pertaining to greenhouse gases and now requires reporting of our greenhouse gas emissions. 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.

Federal legislation may decrease our ability, and increase the cost, to enter into hedge transactions.

The Dodd-Frank Wall Street Reform and Consumer Protective Act (“Dodd-Frank” or the “new law”) was signed into law on July 21, 2010. Dodd-Frank regulates derivative transactions, including our commodity derivative swaps. The new law requires the Treasury Department to implement final administrative procedures related to derivatives within one year. The effect of such administrative procedures on our business is currently uncertain. However, we expect that as a commercial end user using derivatives to manage commercial risks, we will be exempt from posting collateral requirements and mandatory trading on a centralized exchange. We expect to be able to continue to trade with our counterparties, which are all lenders in our credit facility, albeit with a separate capitalized subsidiary of the lender. We do expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased capital costs of bank subsidiaries. Decreasing our ability to enter into hedging transactions would expose us to additional risks related to commodity price volatility and impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.

Possible additional regulation could have an adverse effect on our operations.

Proposed energy legislation and new regulations, driven in part by the Macondo oil spill in the Gulf of Mexico, could limit our ability to operate on Federal lands, delay access to Federal lands, and increase the cost of our operations. These include the Consolidated Land, Energy, and Aquatic Resources Act (CLEAR), the Clean Energy Jobs and Oil Company Accountability Act, the Blowout Prevention Act, and public land leasing reforms. The inability to access Federal lands, as well as delays and the increased cost of operating on Federal lands could result in losses of revenues, increased costs and devaluing of our assets.

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Risks Related to Our Common Stock

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:

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.

Risks Related to our Senior Notes, Convertible Notes and Credit Facility

We may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes, our convertible notes and our revolving credit facility.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our 9.875% Senior Notes due 2016 (“Senior Notes”), our 5% Convertible Senior Notes due 2028 (“Convertible Notes”) and our credit facility (“Amended Credit Facility”). Any insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt, including the notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

As of December 31, 2010, the total outstanding principal amount of our long term indebtedness was approximately $422.5 million, and we had approximately $674.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would be secured debt effectively senior to the Senior Notes and Convertible Notes to the extent of the value of the collateral securing that indebtedness. The Amended Credit Facility has $700.0 million in commitments. The borrowing base is dependent on our proved reserves and hedge positions and, as of December 31, 2010, was $800.0 million based on our June 30, 2010 proved reserves and hedge positions.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

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However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our debt could have important consequences. For example, it could:

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our existing Convertible Notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

Our Amended Credit Facility contains a number of significant covenants in addition to covenants restricting the incurrence of additional debt. Our Amended Credit Facility requires us, among other things, to maintain certain financial ratios and limit our debt. These restrictions also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indenture governing the notes and our Amended Credit Facility impose on us.

Our Amended Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine 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 currently requires the consent of the lenders holding 98% 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 mandatory principal prepayments required under the Amended Credit Facility.

A breach of any covenant in our Amended Credit Facility or the agreements and indentures governing our other indebtedness would result in a default under that agreement or indenture after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under the agreement and in a default

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with respect to, and an acceleration of, the debt outstanding under other debt agreements. The accelerated debt would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Not applicable.

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

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PART II

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: