Bill Barrett (BBG) 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

OR

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

For the transition period from            to            

Commission file number 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(303) 293-9100

(Registrant’s telephone number, including area code)

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 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.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

There were 47,546,367 shares of $0.001 par value common stock outstanding on July 22, 2011.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)	3
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
	Item 4.	Controls and Procedures	43
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	44
	Item 1A.	Risk Factors	44
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
	Item 3.	Defaults Upon Senior Securities	44
	Item 5.	Other Information	44
	Item 6.	Exhibits	45
SIGNATURES			46

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30, 2011			December 31, 2010
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	39,856		$	58,690
Accounts receivable, net of allowance for doubtful accounts of $813 for June 30, 2011 and $814 for December 31, 2010		94,708			72,594
Prepayments and other current assets		9,258			11,444
Derivative assets		28,038			64,920
Total current assets		171,860			207,648
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		3,078,515			2,752,981
Unproved oil and gas properties, excluded from amortization		353,065			274,282
Furniture, equipment and other		30,944			28,501
		3,462,524			3,055,764
Accumulated depreciation, depletion, amortization and impairment		(1,374,923	)		(1,243,945	)
Total property and equipment, net		2,087,601			1,811,819
Deferred Financing Costs and Other Noncurrent Assets		23,995			19,033
Total	$	2,283,456		$	2,038,500
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	101,915		$	83,981
Amounts payable to oil and gas property owners		27,264			19,803
Production taxes payable		40,095			38,410
Derivative liabilities		4,042			943
Deferred income taxes		8,894			22,820
Total current liabilities		182,210			165,957
Note Payable to Bank		145,000			0
Senior Notes		240,463			239,766
Convertible Senior Notes		167,704			164,633
Asset Retirement Obligations		56,925			52,270
Deferred Income Taxes		296,327			266,009
Derivatives and Other Noncurrent Liabilities		4,516			8,903
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 47,463,838 and 46,813,269 shares issued and outstanding at June 30, 2011 and December 31, 2010, respectively, with 870,348 and 891,453 shares subject to restrictions, respectively		47			46
Additional paid-in capital		850,239			830,903
Retained earnings		310,035			262,184
Treasury stock, at cost: zero shares at June 30, 2011 and December 31, 2010		0			0
Accumulated other comprehensive income		29,990			47,829
Total stockholders’ equity		1,190,311			1,140,962
Total	$	2,283,456		$	2,038,500

See notes to unaudited consolidated financial statements.

3

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	194,328		$	186,300		$	366,525		$	349,949
Commodity derivative gain (loss)		(2,907	)		7,676			(14,019	)		2,012
Other		3,021			2,649			3,259			2,474
Total operating and other revenues		194,442			196,625			355,765			354,435
Operating Expenses:
Lease operating expense		14,075			13,581			27,374			26,022
Gathering, transportation and processing expense		21,338			18,487			40,674			34,457
Production tax expense		9,781			9,042			18,347			17,331
Exploration expense		697			654			2,048			955
Impairment, dry hole costs and abandonment expense		1,093			988			1,376			3,867
Depreciation, depletion and amortization		68,847			65,900			134,241			122,434
General and administrative expense		14,757			13,968			32,453			27,744
Total operating expenses		130,588			122,620			256,513			232,810
Operating Income		63,854			74,005			99,252			121,625
Other Income and Expense:
Interest and other income		102			105			165			125
Interest expense		(12,321	)		(11,199	)		(24,363	)		(21,322	)
Total other income and expense		(12,219	)		(11,094	)		(24,198	)		(21,197	)
Income before Income Taxes		51,635			62,911			75,054			100,428
Provision for Income Taxes		18,999			23,713			27,203			37,253
Net Income	$	32,636		$	39,198		$	47,851		$	63,175
Net Income Per Common Share, Basic	$	0.70		$	0.87		$	1.03		$	1.40
Net Income Per Common Share, Diluted	$	0.69		$	0.86		$	1.02		$	1.39
Weighted Average Common Shares Outstanding, Basic		46,415,832			45,080,349			46,255,121			44,995,474
Weighted Average Common Shares Outstanding, Diluted		47,108,063			45,521,264			46,929,015			45,456,430

See notes to unaudited consolidated financial statements.

4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

	Common Stock		Additional Paid-In Capital			Retained Earnings		Treasury Stock			Accumulated Other Comprehensive Income			Total Stockholders’ Equity			Comprehensive Income
	(in thousands)
Balance — December 31, 2009	$	45	$	792,418		$	181,682	$	0		$	54,410		$	1,028,555
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding		1		23,777			0		(3,685	)		0			20,093		$	0
APIC pool for excess tax benefits related to stock-based compensation		0		(52	)		0		0			0			(52	)		0
Stock-based compensation		0		18,445			0		0			0			18,445			0
Retirement of treasury stock		0		(3,685	)		0		3,685			0			0			0
Comprehensive income:
Net income		0		0			80,502		0			0			80,502			80,502
Effect of derivative financial instruments, net of $4,086 of taxes		0		0			0		0			(6,581	)		(6,581	)		(6,581	)
Total comprehensive income																	$	73,921
Balance — December 31, 2010	$	46	$	830,903		$	262,184	$	0		$	47,829		$	1,140,962
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding		1		13,177			0		(3,516	)		0			9,662		$	0
Stock-based compensation		0		9,675			0		0			0			9,675			0
Retirement of treasury stock		0		(3,516	)		0		3,516			0			0			0
Comprehensive income:																		0
Net income		0		0			47,851		0			0			47,851			47,851
Effect of derivative financial instruments, net of $10,812 of taxes		0		0			0		0			(17,839	)		(17,839	)		(17,839	)
Total comprehensive income																	$	30,012
Balance — June 30, 2011	$	47	$	850,239		$	310,035	$	0		$	29,990		$	1,190,311

See notes to unaudited consolidated financial statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2011			2010
	(in thousands)
Operating Activities:
Net Income	$	47,851		$	63,175
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		134,241			122,434
Deferred income taxes		27,203			32,282
Impairment, dry hole costs and abandonment expense		1,376			3,867
Unrealized derivative loss (gain)		25			(14,998	)
Stock compensation and other non-cash charges		10,345			8,327
Amortization of debt discounts and deferred financing costs		6,420			5,661
Gain on sale of properties		(2,009	)		(1,049	)
Change in operating assets and liabilities:
Accounts receivable		(22,114	)		(65	)
Prepayments and other assets		2,069			(2,971	)
Accounts payable, accrued and other liabilities		(3,314	)		(3,551	)
Amounts payable to oil and gas property owners		7,461			1,669
Production taxes payable		1,685			(2,814	)
Net cash provided by operating activities		211,239			211,967
Investing Activities:
Additions to oil and gas properties, including acquisitions		(383,802	)		(199,182	)
Additions of furniture, equipment and other		(2,772	)		(1,638	)
Proceeds from sale of properties and other investing activities		1,860			2,268
Net cash used in investing activities		(384,714	)		(198,552	)
Financing Activities:
Proceeds from credit facility		145,000			20,000
Principal payments on credit facility		0			(25,000	)
Proceeds from stock option exercises		13,078			2,387
Deferred financing costs and other		(3,437	)		(14,966	)
Net cash provided by (used in) financing activities		154,641			(17,579	)
Decrease in Cash and Cash Equivalents		(18,834	)		(4,164	)
Beginning Cash and Cash Equivalents		58,690			54,405
Ending Cash and Cash Equivalents	$	39,856		$	50,241

See notes to unaudited consolidated financial statements.

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BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

June 30, 2011

1. Organization

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

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying Unaudited Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of June 30, 2011, the Company’s results of operations for the three and six months ended June 30, 2011 and 2010 and cash flows for the six months ended June 30, 2011 and 2010. Operating results for the three and six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, timing of development and exploration activities, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the Unaudited Consolidated Financial Statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 previously filed with the SEC.

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

The most significant areas requiring the use of assumptions, judgments and estimates relate to the expected cash settlement of the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”) in computing diluted earnings per share, volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future abandonment obligations, impairments of undeveloped properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.

Oil and Gas Properties.The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. The weighted average interest rates used to capitalize interest were 11.3% and 11.8% for the three and six months ended June 30, 2011, respectively, and 12.2% and 11.8% for the three and six months ended June 30, 2010, respectively, which include interest, amortization of discounts and deferred financing fees on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“Senior Notes”) and its credit facility. The Company capitalized interest costs of $0.5 million and $1.0 million for the three and six months ended June 30, 2011, respectively, and $1.2 million and $2.5 million for the three and six months ended June 30, 2010, respectively.

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

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive and are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters. During the three and six months ended June 30, 2011 and 2010, the Company did not recognize any non-cash impairment charges related to its unproved oil and gas properties.

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

The following table sets forth the net capitalized costs and associated accumulated DD&A, and non-cash impairments relating to the Company’s natural gas and oil producing activities:

	As of June 30, 2011			As of December 31, 2010
	(in thousands)
Proved properties	$	508,791		$	437,741
Wells and related equipment and facilities		2,318,010			2,083,329
Support equipment and facilities		242,034			219,280
Materials and supplies		9,680			12,631
Total proved oil and gas properties		3,078,515			2,752,981
Accumulated depreciation, depletion, amortization and impairment		(1,360,712	)		(1,230,975	)
Total proved oil and gas properties, net	$	1,717,803		$	1,522,006
Unproved properties	$	232,051		$	172,242
Wells and facilities in progress		121,014			102,040
Total unproved oil and gas properties, excluded from amortization	$	353,065		$	274,282

Net changes in capitalized exploratory well costs for the six months ended June 30, 2011 are reflected in the following table (in thousands):

Beginning of period	$	9,041
Additions to capitalized exploratory well costs pending the determination of proved reserves		9,801
Reclassifications of wells, facilities and equipment based on the determination of proved reserves		(1,623	)
Exploratory well costs charged to dry hole costs and abandonment expense		0
End of period	$	17,219

The following table presents costs of exploratory wells for which drilling has been completed for a period of greater than one year and which are included in unproved oil and gas properties as of June 30, 2011, pending determination of whether the wells will be assigned proved reserves:

	Time Elapsed Since Drilling Completed
	1-2 Years		3-5 Years		Total
Costs of wells for which drilling has been completed (in thousands)	$	886	$	4,360	$	5,246
Number of wells for which drilling has been completed		7		27		34

As of June 30, 2011, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $5.2 million, all of which were related to coalbed methane wells located in the Powder River Basin. These wells were drilled into various coal seams. In order to produce gas from the coal seams, a period of dewatering typically lasting up to 36 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.

Management believes these wells with suspended exploratory drilling costs have the potential for sufficient quantities of hydrocarbons to justify their development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt regarding the economic or operational viability of any of these wells, the associated costs will be expensed.

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

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Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. During the three and six months ended June 30, 2011 and 2010, the Company did not recognize any non-cash impairment charges related to its proved oil and gas properties.

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

Accounts Payable and Accrued Liabilities. Accounts payable and accrued expenses are comprised of the following (in thousands):

	June 30,		December 31,
	2011		2010
Accrued drilling and facility costs	$	55,840	$	39,912
Accrued lease operating, gathering, transportation and processing expenses		18,362		15,610
Accrued general and administrative expenses		7,083		9,020
Trade payables and other		20,630		19,439
Total accounts payable and accrued liabilities	$	101,915	$	83,981

New Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-06,Improving Disclosures about Fair Value Measurements, which amended Accounting Standards Codification (“ASC”) 820,Fair Value Measurements and Disclosures.The intent of this update was to improve disclosure requirements related to fair value measurements and disclosures. New disclosures were required regarding transfers in and out of Levels 1 and 2 and activity within Level 3 fair value measurements, as well as clarification of existing disclosures regarding the level of disaggregation of derivative contracts and disclosures about fair value measurement inputs and valuation techniques. The guidance was effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures, which were effective for interim and annual periods beginning after December 15, 2010. The Company adopted the provisions on January 1, 2010, except for the Level 3 reconciliation disclosures, which were adopted on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations.

In June 2011, the FASB issued Accounting Standards Update 2011-05,Presentation of Comprehensive Income, ASC 220,Comprehensive Income.The intent of this update was to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. To facilitate convergence of GAAP and International Financial Reporting Standards (“IFRS”), the FASB eliminated the option to present components of other comprehensive income as part of the statement of stockholders’ equity and requires an entity to present total comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. The guidance is effective for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact that the adoption will have on the Company’s disclosures and financial statements.

3. Earnings Per Share

Basic net income per share of common stock is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding during each period. Nonvested equity shares of common stock are included in the computation of basic net income per share only after the shares become fully vested. Diluted net income per share of common stock is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company’s common stock and shares into which the Convertible Notes are convertible.

In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. The Company currently expects to settle the Convertible Notes in cash at or near the initial redemption date of March 26, 2012; therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that conversion feature. The Convertible Notes issued March 12, 2008 have not been dilutive since their issuance, and therefore, did not impact the diluted net income per share calculation for the three and six months ended June 30, 2011 and 2010. The diluted net income per share calculation excludes the anti-dilutive effect of 125,575 and 230,147 shares of stock options and nonvested performance-based equity shares of common stock for the three months ended June 30, 2011 and 2010, respectively, and 196,646 and 272,200 shares of stock options and nonvested performance-based equity shares of common stock for the six months ended June 30, 2011 and 2010, respectively.

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The following table sets forth the calculation of basic and diluted net income per share (in thousands, except per share amounts):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Net income	$	32,636	$	39,198	$	47,851	$	63,175
Basic weighted-average common shares outstanding in period		46,416		45,080		46,255		44,995
Add dilutive effects of stock options and nonvested performance-based equity shares of common stock		692		441		674		461
Diluted weighted-average common shares outstanding in period		47,108		45,521		46,929		45,456
Basic income per common share	$	0.70	$	0.87	$	1.03	$	1.40
Diluted income per common share	$	0.69	$	0.86	$	1.02	$	1.39

4. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows (in thousands):

	Six Months Ended June 30,
	2011			2010
Cash paid for interest, net of amount capitalized	$	16,890		$	16,680
Cash paid for income taxes, net of refunds received		(7,504	)		7,004
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities that are reflected in investing activities		60,081			53,697
Current liabilities that are reflected in financing activities		140			49
Net increase (decrease) in asset retirement obligations		3,535			(869	)
Treasury stock acquired from employee stock option exercises		100			70
Retirement of treasury stock		(3,516	)		(3,480	)

5. Acquisitions

Acquisitions

On June 8, 2011, the Company completed an acquisition, from an unrelated party, of oil properties and related assets in the East Bluebell area of the Uinta Basin (“East Bluebell Acquisition”) located in Duchesne and Uintah Counties in Utah. The properties were purchased for approximately $119.4 million, subject to final post-closing adjustments. The preliminary purchase price allocation, which is subject to final purchase price allocation adjustments, is as follows:

Consideration given:
Cash	$	119,441
Total consideration given	$	119,441

Amounts recognized for preliminary fair value of assets acquired and liabilities assumed:
Proved property	$	76,302
Unproved property		45,164
Asset retirement obligation		(2,054	)
Liabilities assumed		(1,932	)
Other assets acquired		1,961
Total fair value of oil and gas properties acquired	$	119,441

The East Bluebell Acquisition qualified as a business combination and, as such, the Company estimated the fair value of each property as of the acquisition date, June 8, 2011. To estimate the fair values of the properties as of the acquisition date, the Company used a net asset value approach. The Company utilized a discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows:

• Estimated ultimate recovery of crude oil and natural gas as prepared by the Company’s internal petroleum engineers;

• Estimated future commodity prices based on NYMEX crude oil futures prices as of the acquisition date and adjusted for estimated location and quality differentials as well as related transportation costs;

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• Estimated future production rates based on the Company’s experience with similar Uinta Basin properties which the Company operates; and

• Estimated timing and amounts of future operating and development costs based on the Company’s experience with similar Uinta Basin properties that the Company operates.

To estimate the fair value of proved properties, the Company discounted the future net cash flows using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduced the discounted future net cash flows of the unproved properties by additional risk-weighting factors. Due to the unobservable nature of the inputs, the fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.

The Company has not presented pro forma information for the acquired business as the impact of the acquisition was not material to the consolidated balance sheet or results of operations for the three or six months ended June 30, 2011. The results of operations from the East Bluebell Acquisition are included in the Company’s consolidated financial statements from the acquisition date of June 8, 2011. Revenue related to the East Bluebell Acquisition that was included in the Company’s Unaudited Consolidated Statement of Operations was approximately $0.6 million for both the three and six months ended June 30, 2011 and net income was insignificant.

6. Long-Term Debt

The Company’s outstanding debt is summarized below (in thousands):

		As of June 30, 2011							As of December 31, 2010
	Maturity Date	Principal		Unamortized Discount			Carrying Amount		Principal		Unamortized Discount			Carrying Amount
Amended Credit Facility	April 1, 2014	$	145,000	$	0		$	145,000	$	0	$	0		$	0
Senior Notes (1)	July 15, 2016		250,000		(9,537	)		240,463		250,000		(10,234	)		239,766
Convertible Notes (2)	March 15, 2028 (3)		172,500		(4,796	)		167,704		172,500		(7,867	)		164,633

(1) The aggregate estimated fair value of the Senior Notes was approximately $284.5 million as of June 30, 2011 based on reported market trades of these instruments.

(2) The aggregate fair value of the Convertible Notes was approximately $177.9 million as of June 30, 2011. Because there is no active, public market for the Convertible Notes, the fair value was based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades.

(3) The Company currently expects that the holders will put the Convertible Notes to the Company in March 2012. The Company also has the option to call the Convertible Notes at any time thereafter.

Revolving Credit Facility

On March 16, 2010, the Company amended its revolving credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. The Amended Credit Facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.0% to 3.0% or an alternate base rate (“ABR”), based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.0%, plus applicable margins ranging from 1.0% to 2.0%. The borrowing base is required to be redetermined twice per year. On March 25, 2011, the borrowing base was reaffirmed at $800.0 million with commitments from 19 lenders of $700.0 million, based on December 31, 2010 reserves and hedge positions. The Company pays annual commitment fees of 0.5% of the unused amount of the commitments. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the stock of the Company’s subsidiaries. The Amended Credit Facility also contains certain financial covenants. The Company currently is in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

As of June 30, 2011, the Company had $145.0 million outstanding under the Amended Credit Facility. As credit support for future payments under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, effective May 4, 2010, which reduced the borrowing capacity of the Amended Credit Facility by $26.0 million.

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9.875% Senior Notes Due 2016

The Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes. Interest is payable in arrears semi-annually on January 15 and July 15 each year. The Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility and the Convertible Notes. The Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. The Company is currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

5% Convertible Senior Notes due 2028

The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company’s existing and future senior unsecured indebtedness, including the Senior Notes. Interest is payable semi-annually in arrears on March 15 and September 15 of each year. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility and Senior Notes.

The following table summarizes the cash portion of interest expense related to the Amended Credit Facility, Senior Notes and Convertible Notes along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Amended Credit Facility (1)
Cash interest	$	1,253	$	973	$	2,234	$	1,422
Non-cash interest	$	780	$	778	$	1,559	$	1,183
Senior Notes (2)
Cash interest	$	6,172	$	6,172	$	12,344	$	12,344
Non-cash interest	$	611	$	554	$	1,219	$	1,105
Convertible Notes (3)
Cash interest	$	2,156	$	2,156	$	4,313	$	4,313
Non-cash interest	$	1,858	$	1,723	$	3,641	$	3,375

(1) Cash interest includes amounts related to interest and commitment fees paid on the line of credit and participation and fronting fees paid on the letter of credit.

(2) The stated interest rate for the Senior Notes is 9.875% per annum with an effective interest rate of 11.3% per annum.

(3) The stated interest rate for the Convertible Notes is 5% per annum with an effective interest rate of 9.7% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represents the fair value of the equity conversion feature at the time of issue.

7. Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Unaudited Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Unaudited Consolidated Statements of Operations.

A reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2011 is as follows (in thousands):

Beginning of period	$	53,079
Liabilities incurred		3,535
Liabilities settled		(335	)
Accretion expense		1,902
Revisions to estimate		0
End of period	$	58,181
Less: current asset retirement obligations		1,256
Long-term asset retirement obligations	$	56,925

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8. Fair Value Measurements

Assets and Liabilities Measured on a Recurring Basis

The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure. The Company’s other financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities as of June 30, 2011 and December 31, 2010 that were measured at fair value on a recurring basis. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.

As of June 30, 2011

	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets
Deferred compensation plan	$	408	$	0		$	0	$	408
Commodity derivatives		0		52,355			0		52,355
Liabilities
Commodity derivatives	$	0	$	(24,640	)	$	0	$	(24,640	)

As of December 31, 2010

	Level 1		Level 2			Level 3		Total
			(in thousands)
Assets
Deferred compensation plan	$	260	$	0		$	0	$	260
Commodity derivatives		0		81,685			0		81,685
Liabilities
Commodity derivatives	$	0	$	(25,294	)	$	0	$	(25,294	)

All fair values reflected in the table above and on the Unaudited Consolidated Balance Sheets have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 Fair Value Measurements –The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 13) which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets on the Unaudited Consolidated Balance Sheets. These financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Level 2 Fair Value Measurements – The fair value of the natural gas and crude oil forwards and options are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties’ valuations to assess the reasonableness of the Company’s valuations.

Level 3 Fair Value Measurements – As of June 30, 2011, and for the six months ended June 30, 2011, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy.

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Assets and Liabilities Measured on a Non-Recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property and equipment. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3. The Company also applied fair value accounting guidance to measure the assets and liabilities acquired in the East Bluebell Acquisition. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. The preliminary fair values of these items were primarily determined using the present value of estimated future cash inflows and outflows. Given the unobservable nature of these inputs, they are classified within Level 3. See Note 5 for additional discussion of the East Bluebell Acquisition and disclosure of the inputs used to determine the preliminary fair value of the assets and liabilities acquired. Additionally, the Company uses fair value to determine the inception value of its asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition and would generally be classified within Level 3.

9. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices related to the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair value and included in the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative instruments in the Unaudited Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010:

	June 30, 2011			December 31, 2010
	(in thousands)
Derivatives Designated as Cash Flow Hedging Instruments
Assets:
Current: Derivative assets	$	39,061		$	80,460
Current: Derivative liability (1)		5,079			0
Deferred financing costs and other noncurrent assets (4)		6,341			0
Derivatives and other noncurrent liabilities (1)(3)		854			1,166
Liabilities:
Current: Derivative assets (2)		(2,343	)		(2,172	)
Current: Derivative liability		(358	)		(943	)
Deferred financing costs and other noncurrent assets (4)(2)		(637	)		0
Derivatives and other noncurrent liabilities (3)		(12	)		(2,925	)
Total derivatives designated as cash flow hedging instruments	$	47,985		$	75,586
Derivatives Not Designated as Cash Flow Hedging Instruments
Assets:
Current: Derivative assets	$	59		$	59
Current: Derivative liability (1)		391			0
Deferred financing costs and other noncurrent assets (4)		542			0
Derivatives and other noncurrent liabilities (1)(3)		28			0
Liabilities:
Current: Derivative assets (2)		(8,739	)		(13,427	)
Current: Derivative liability		(9,154	)		0
Deferred financing costs and other noncurrent assets (4)(2)		(172	)		0
Derivatives and other noncurrent liabilities (3)		(3,225	)		(5,827	)
Total derivatives not designated as cash flow hedging instruments	$	(20,270	)	$	(19,195	)
Total Derivatives	$	27,715		$	56,391

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(1) Amounts are netted against derivative liability balances with the same counterparty, and, therefore, are presented as a net liability on the Unaudited Consolidated Balance Sheets.

(2) Amounts are netted against derivative asset balances with the same counterparty, and, therefore, are presented as a net asset on the Unaudited Consolidated Balance Sheets.

(3) As of June 30, 2011 and December 31, 2010, this line item on the Unaudited Consolidated Balance Sheets also includes $2.2 million and $1.3 million, respectively, of other noncurrent liabilities.

(4) As of June 30, 2011 and December 31, 2010, this line item on the Unaudited Consolidated Balance Sheets also includes $17.9 million and $19.0 million, respectively, of deferred financing costs and other noncurrent assets.

For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedges are effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from AOCI to oil and gas production revenues in the Unaudited Consolidated Statements of Operations as the hedged production quantity is sold. Based on projected market prices as of June 30, 2011, the amount to be reclassified from AOCI to net income in the next 12 months would be an after-tax net gain of approximately $25.9 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. The Company anticipates that all originally forecasted transactions related to the Company’s derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The commodity hedge instruments designated as cash flow hedges are at highly liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Although those derivatives may not achieve 100% effectiveness for accounting purposes, the Company believes that its derivative instruments continue to be highly effective in achieving its risk management objectives. The ineffective portion of commodity hedge derivatives is reported in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. The following table summarizes the cash flow hedge gains and losses and their locations on the Unaudited Consolidated Balance Sheets and the Unaudited Consolidated Statements of Operations for the periods indicated:

	Derivatives Qualifying as Cash Flow Hedges	Three Months Ended June 30,					Six Months Ended June 30,
		2011		2010			2011		2010
		(in thousands)					(in thousands)
Amount of gain recognized in AOCI (net of tax)	Commodity Hedges	$	17,840	$	3,395		$	11,987	$	65,700
Amount of gain reclassified from AOCI into income (net of tax)	Commodity Hedges (1)		12,366		31,191			29,826		44,320
Amount of gain (loss) recognized in income on ineffective hedges	Commodity Hedges (2)		888		(659	)		1,050		(266	)

(1) Included in oil and gas production revenues in the Unaudited Consolidated Statements of Operations.

(2) Included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

During the derivative’s term, if the Company determines that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains and losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI and are reclassified to earnings when the underlying transaction occurs. If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment, and all subsequent mark-to-market gains and losses are recorded in earnings, and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.

Some of the Company’s commodity derivative instruments do not qualify or are not designated as cash flow hedges but are, to a degree, an economic offset to the Company’s commodity price exposure. If a commodity derivative instrument does not qualify or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. The Company’s cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument is settled by making or receiving a payment to or from the counterparty. Realized gains and losses of commodity derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Consolidated Statements of Cash Flows.

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In addition to the swaps and collars discussed above, the Company has entered into basis only swaps. Basis only swaps hedge the difference between the New York Mercantile Exchange (“NYMEX”) gas price and the price received for the Company’s natural gas production at a specific delivery location. Although the Company believes that this is an appropriate part of a mitigation strategy, the basis only swaps do not qualify for hedge accounting because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings and recognized in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. The Company has also entered into swap contracts to hedge the amount received related to natural gas liquids (“NGLs”) resulting from the processing of its natural gas. The NGL hedges were not designated as cash flow hedges, and the changes in fair value of these derivative instruments were recorded in earnings.

The following table summarizes the location and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting for the period indicated:

	Location of Loss Recognized in Income on Derivatives	Three Months Ended June 30,					Six Months Ended June 30,
		2011			2010		2011			2010
		(in thousands)					(in thousands)
Amount of gain (loss) recognized in income on derivatives	Commodity derivative gain (loss)	$	(3,795	)	$	8,335	$	(15,069	)	$	2,278

As of June 30, 2011, the Company had financial instruments in place to hedge the following volumes for the periods indicated:

	July – December 2011		For the year 2012		For the  year 2013		For the  year 2014
Oil (Bbls)		533,600		1,024,800		255,500		146,000
Natural Gas (MMbtu)		34,800,000		46,495,000		3,650,000		0
Natural Gas Basis (MMbtu)		3,680,000		7,320,000		0		0
Natural Gas Liquids (Gallons)		38,475,000		21,000,000		0		0

The Company recognized a net increase in revenues related to natural gas, NGL and basis only hedges of $13.5 million and $36.8 million in the three and six months ended June 30, 2011, respectively, and $40.8 million and $56.7 million for the three and six months ended June 30, 2010, respectively. The Company also recognized a net decrease related to oil hedges of $2.3 million and $3.1 million for the three and six months ended June 30, 2011, respectively, and a net increase of $0.8 million and $1.2 million for the three and six months ended June 30, 2010.

The table below summarizes the realized and unrealized gains and losses the Company recognized in the Unaudited Consolidated Statements of Operations related to its commodity derivative instruments for the periods indicated (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized gain on derivatives designated as cash flow hedges (1)	$	19,776		$	49,889		$	47,699		$	70,898
Realized loss on derivatives not designated as cash flow hedges (2)	$	(8,590	)	$	(8,223	)	$	(13,994	)	$	(12,986	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges (2)		888			(659	)		1,050			(266	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges (2)		4,795			16,558			(1,075	)		15,264
Total commodity derivative gain (loss)	$	(2,907	)	$	7,676		$	(14,019	)	$	2,012

(1) Included in oil and gas production revenues in the Unaudited Consolidated Statements of Operations.

(2) Included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

Derivative financial instruments that hedge the price of oil and gas are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has hedges in place with 12 different counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

16

It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”) or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions with its lenders (or affiliates of lenders) that, in the event of counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty or its affiliated lender under the Amended Credit Facility or other general obligations against monies owed for derivative contracts.

10. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on technical merits. During the six months ended June 30, 2011, there was no change to the Company’s liability for uncertain tax positions.

The Company’s policy is to classify accrued interest and penalties related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and six months ended June 30, 2011.

Income tax expense for the three and six months ended June 30, 2011 and 2010 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income before income taxes principally due to the effect of state income taxes, stock-based compensation and other operating expenses that are not deductible for income tax purposes.

11. Stockholders’ Equity

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

When issued, each share of Series A Junior Participating Preferred Stock will entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.

The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of stock-based awards or for other reasons. As of June 30, 2011, all treasury stock held by the Company was retired.

12. Accumulated Other Comprehensive Income

The components of AOCI and related tax effects for the six months ended June 30, 2011 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated Other Comprehensive Income—December 31, 2010	$	76,613		$	(28,784	)	$	47,829
Unrealized change in fair value of cash flow hedges		19,048			(7,061	)		11,987
Reclassification adjustment for realized gains on hedges included in net income		(47,699	)		17,873			(29,826	)
Accumulated Other Comprehensive Income—June 30, 2011	$	47,962		$	(17,972	)	$	29,990

13. Equity Incentive Compensation Plans and Other Employee Benefits

The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

17

The following table presents the non-cash stock-based compensation related to equity awards for the three and six months ended June 30, 2011 and 2010 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Common stock options	$	1,741	$	2,150	$	3,909	$	4,175
Nonvested equity common stock		2,139		1,693		4,199		3,390
Nonvested performance-based equity		361		0		535		182
Market performance-based equity		118		78		308		151
Total non-cash stock-based compensation	$	4,359	$	3,921	$	8,951	$	7,898

Unrecognized compensation cost as of June 30, 2011 was $32.7 million related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.7 years.

Stock Options and Nonvested Equity Shares. The following tables present the equity awards granted pursuant to the Company’s various stock compensation plans:

	Three Months Ended June 30, 2011				Six Months Ended June 30, 2011
	Number of options		Weighted Average Price Per Share		Number of Options		Weighted Average Price Per Share
Options to purchase shares of common stock		15,000	$	44.57		262,824	$	39.34

	Three Months Ended June 30, 2011				Six Months Ended June 30, 2011
	Number of shares		Weighted Average Grant Date Fair Value		Number of shares		Weighted Average Grant Date Fair Value
Nonvested equity shares		28,859	$	41.57		316,461	$	39.23
Nonvested performance-based equity shares		0		—		4,922	$	39.88
Market performance-based equity shares		0		—		1,038	$	39.88
Total shares granted		28,859				322,421

Performance Share Program. In February 2010, the Compensation Committee of the Board of Directors of the Company approved a performance share program (the “2010 Program”) pursuant to the Company’s 2008 Stock Incentive Plan (the “2008 Incentive Plan”). A total of 325,000 shares of common stock under the 2008 Incentive Plan were set aside for this program. The vesting of these awards is contingent upon meeting various Company-wide performance goals. Upon commencement of the 2010 Program and during each subsequent year of the 2010 Program, the Compensation Committee will meet to approve target and stretch goals for certain operational or financial metrics that are selected by the Compensation Committee for the upcoming year and to determine whether metrics for the prior year have been met. These performance-based awards contingently vest over a period of up to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for up to 50% of the shares to vest based on the achievement of the performance goals. Twenty-five percent of the total grant will vest if each of the independent metrics are met at the target level, and an additional 25% of the total grant will vest if each of the independent metrics are met at the stretch level. If the actual results for a metric are between the target levels and the stretch levels, the vested number of shares will be adjusted on a prorated basis of the actual results compared to the target and stretch goals. If the target level metrics are not met, no shares will vest. In any event, the total number of shares of common stock that could vest will not exceed the original number of performance shares granted. At the end of four years, any shares that have not vested will be forfeited.

For the year ended December 31, 2010, the performance goals consisted of finding and development costs per Mcfe (weighted at 37.5%), combined lease operating expenses and general and administrative expenses (weighted at 25%) and production growth (weighted at 37.5%). Based on the Company’s performance with respect to those metrics during the year ended December 31, 2010, the Compensation Committee in February 2011 approved vesting of 25.9% of the total grant. The Company recorded the remaining non-cash stock-based compensation cost associated with these shares of $0.2 million for the six months ended June 30, 2011, for the remaining time vesting requirement through the February 2011 vest date.

As new goals are established each year for the performance-based awards, a new grant date and a new fair value are created for financial reporting purposes for those shares that could potentially vest in the upcoming year. Compensation cost is recognized based upon an estimate of the extent to which the performance goals would be met. If such goals are not met, no compensation cost is recognized and any previously recognized compensation cost is reversed.

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In March 2011, the Compensation Committee approved the performance metrics for vesting of the performance shares based on 2011 performance. For the year ending December 31, 2011, the performance goals consist of annual production growth (weighted at 25%), increases to our natural gas and oil proved reserves (weighted at 25%), finding and development costs (weighted at 25%) and increases to the Company’s present value (at a 10% annual discount) of future net cash flows from proved reserves (weighted at 25%). For the six months ended June 30, 2011, the remaining nonvested performance shares that were granted in 2010, along with 4,922 newly granted performance-based nonvested equity shares of common stock, were subject to the new grant date and the fair value was remeasured at $39.88 per share. Of those performance-based nonvested equity shares, 136,534 could potentially vest if all performance goals are met at the stretch level. Based upon the number of shares expected to vest through February 2012, at the estimated performance compared to the performance metrics at June 30, 2011, the Company recognized $0.4 million of non-cash stock-based compensation expense associated with these shares for the three and six months ended June 30, 2011.

In March 2011, the Compensation Committee also modified the vesting terms of the Company’s nonvested equity awards that are subject to a market performance-based vesting condition, which is based on the Company’s total stockholder return (“TSR”) ranking relative to a defined peer group’s individual TSRs. The remeasured aggregate fair value of the market-based awards was $1.3 million based on a per-unit fair value of $39.88 on the new grant date. The fair value of the market-based awards is amortized ratably over the remaining three year requisite service period. All compensation expense related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The Company recognized $0.1 million and $0.3 million of non-cash stock-based compensation expense attributable to these awards for the three and six months ended June 30, 2011, respectively.

Director Fees. The Company’s non-employee, or outside, directors may elect to receive all or a portion of their annual retainer and meeting fees in the form of the Company’s common stock issued pursuant to the Company’s 2004 Incentive Plan. After each quarter, shares with a value equal to the fees payable in common stock for that quarter, calculated using the closing price on the last trading day of the quarter, will be delivered to each outside director who elected before that quarter to receive shares for payment of director fees. The following table summarizes common stock issued as payment for directors’ fees and the amount of non-cash stock-based compensation cost recognized associated with the issuance of those shares:

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Director fees (shares)		2,187		2,541		4,978		4,844
Stock-based compensation (in thousands)	$	101	$	78	$	213	$	149

Other Employee Benefits-401(k) Savings Plan. The Company has an employee-directed 401(k) savings plan (the “401(k) Plan”) for all eligible employees over the age of 21. Under the 401(k) Plan, employees may make voluntary contributions based upon a percentage of their pretax income.

The Company matches 100% of each employee’s contribution, up to 6% of the employee’s pretax income, with 50% of the match made with the Company’s common stock. The Company’s cash and common stock contributions and shares of common stock are fully vested upon the date of match and employees can immediately sell the portion of the match made with the Company’s common stock. The Company made matching cash and common stock contributions of $0.3 million and $1.0 million for the three and six months ended June 30, 2011, respectively, and $0.4 million and $1.0 million for the three and six months ended June 30, 2010, respectively.

Deferred Compensation Plan. In 2010, the Company adopted a non-qualified deferred compensation plan for certain employees and officers whose eligibility to participate in the plan was determined by the Compensation Committee of the Company’s Board of Directors. The Company makes matching cash contributions on behalf of eligible employees up to 6% of the employee’s cash compensation once the contribution limits are reached on the Company’s 401(k) Plan. All amounts deferred and matched under the plan vest immediately.

Participants earn a return on their deferred compensation based on investment earnings of participant-selected mutual funds. Participants’ deferred compensation amounts are not directly invested in these investment vehicles; however, the Company tracks the performance of each participant’s investment selections and adjusts the deferred compensation liability accordingly. Changes in the market value of the participants’ investment selections are recorded as an adjustment to deferred compensation liabilities, with an offset to compensation expense included within general and administrative expenses in the Unaudited Consolidated Statements of Operations. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.

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The table below summarizes the activity in the plan during the year ended December 31, 2010 and six months ended June 30, 2011 (in thousands):

Beginning deferred compensation liability balance – January 1, 2010	$	0
Employee contributions		145
Company matching contributions		104
Participant earnings		11
Ending deferred compensation liability balance – December 31, 2010	$	260
Employee contributions		88
Company matching contributions		85
Distributions		(34	)
Participant earnings		9
Ending deferred compensation liability balance – June 30, 2011	$	408
Amount to be paid within one year	$	144
Remaining balance to be paid beyond one year	$	264

The Company is not obligated to contemporaneously fund the liability. It has, however, established a rabbi trust to offset the deferred compensation liability and protect the interest of the plan participants. The trust assets are invested in publicly-traded mutual funds. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability. The gains and losses from changes in fair value of the investments are included in interest and other income in the Unaudited Consolidated Statements of Operations.

The following table represents the Company’s activity in the investment assets held in the rabbi trust during the year ended December 31, 2010 and the six months ended June 30, 2011 (in thousands):

Beginning investment balance – January 1, 2010	$	0
Investment purchases		249
Earnings		11
Ending investment balance – December 31, 2010	$	260
Investment purchases		173
Distributions		(34	)
Earnings		9
Ending investment balance – June 30, 2011	$	408

14. Guarantor Subsidiaries

In addition to the Amended Credit Facility, the Senior Notes and the Convertible Notes, which are registered securities, are jointly and severally guaranteed on a full and unconditional basis by the Company’s 100%- owned subsidiaries (“Guarantor Subsidiaries”). Presented below are the Company’s condensed consolidating balance sheets, statements of income and statements of cash flows, as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

The following condensed consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the Unaudited Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the intercompany eliminations column.

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Condensed Consolidating Balance Sheets

	June 30, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Assets:
Current assets	$	170,449		$	1,411		$	0	$	171,860
Property and equipment, net		1,968,507			119,094			0		2,087,601
Intercompany receivable (payable)		101,029			(101,029	)		0		0
Investment in subsidiaries		(9,045	)		0			9,045		0
Noncurrent assets		23,995			0			0		23,995
Total assets	$	2,254,935		$	19,476		$	9,045	$	2,283,456
Liabilities and Stockholders’ Equity:
Current liabilities	$	181,173		$	1,037		$	0	$	182,210
Long-term debt		553,167			0			0		553,167
Deferred income taxes		271,423			24,904			0		296,327
Other noncurrent liabilities		58,861			2,580			0		61,441
Stockholders’ equity		1,190,311			(9,045	)		9,045		1,190,311
Total liabilities and stockholders’ equity	$	2,254,935		$	19,476		$	9,045	$	2,283,456

	December 31, 2010
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Assets:
Current assets	$	206,987		$	661		$	0	$	207,648
Property and equipment, net		1,727,872			83,947			0		1,811,819
Intercompany receivable (payable)		65,662			(65,662	)		0		0
Investment in subsidiaries		(7,474	)		0			7,474		0
Noncurrent assets		19,033			0			0		19,033
Total assets	$	2,012,080		$	18,946		$	7,474	$	2,038,500
Liabilities and Stockholders’ Equity:
Current liabilities	$	165,166		$	791		$	0	$	165,957
Long-term debt		404,399			0			0		404,399
Deferred income taxes		241,105			24,904			0		266,009
Other noncurrent liabilities		60,448			725			0		61,173
Stockholders’ equity		1,140,962			(7,474	)		7,474		1,140,962
Total liabilities and stockholders’ equity	$	2,012,080		$	18,946		$	7,474	$	2,038,500

Condensed Consolidating Statements of Operations

	Three Months Ended June 30, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	191,330		$	3,112		$	0	$	194,442
Operating expenses		112,117			3,714			0		115,831
General and administrative		14,757			0			0		14,757
Interest and other income (expense)		(12,219	)		0			0		(12,219	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		52,237			(602	)		0		51,635
Provision for income taxes		18,999			0			0		18,999
Equity in earnings (loss) of subsidiaries		(602	)		0			602		0
Net income (loss)	$	32,636		$	(602	)	$	602	$	32,636

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	Six Months Ended June 30, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	350,075		$	5,690		$	0	$	355,765
Operating expenses		216,797			7,263			0		224,060
General and administrative		32,453			0			0		32,453
Interest and other income (expense)		(24,198	)		0			0		(24,198	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		76,627			(1,573	)		0		75,054
Provision for income taxes		27,203			0			0		27,203
Equity in earnings (loss) of subsidiaries		(1,573	)		0			1,573		0
Net income (loss)	$	47,851		$	(1,573	)	$	1,573	$	47,851

	Three Months Ended June 30, 2010
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	193,103		$	3,522		$	0	$	196,625
Operating expenses		104,953			3,699			0		108,652
General and administrative		13,968			0			0		13,968
Interest and other income (expense)		(11,094	)		0			0		(11,094	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		63,088			(177	)		0		62,911
Income tax expense		23,713			0			0		23,713
Equity in earnings (loss) of subsidiaries		(177	)		0			177		0
Net income (loss)	$	39,198		$	(177	)	$	177	$	39,198

	Six Months Ended June 30, 2010
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	347,416		$	7,019		$	0	$	354,435
Operating expenses		197,468			7,598			0		205,066
General and administrative		27,744			0			0		27,744
Interest and other income (expense)		(21,197	)		0			0		(21,197	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		101,007			(579	)		0		100,428
Income tax expense		37,253			0			0		37,253
Equity in earnings (loss) of subsidiaries		(579	)		0			579		0
Net income (loss)	$	63,175		$	(579	)	$	579	$	63,175

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Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	209,352		$	1,887		$	0	$	211,239
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(347,325	)		(36,477	)		0		(383,802	)
Additions to furniture, fixtures and other		(2,423	)		(349	)		0		(2,772	)
Proceeds from sale of properties and other investing activities		1,860			0			0		1,860
Cash flows from financing activities:
Proceeds from debt		145,000			0			0		145,000
Principal payments on debt		0			0			0		0
Intercompany transfers		(34,938	)		34,938			0		0
Other financing activities		9,640			1			0		9,641
Change in cash and cash equivalents		(18,834	)		0			0		(18,834	)
Beginning cash and cash equivalents		58,690			0			0		58,690
Ending cash and cash equivalents	$	39,856		$	0		$	0	$	39,856

	Six Months Ended June 30, 2010
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	209,171		$	2,796		$	0	$	211,967
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(198,521	)		(661	)		0		(199,182	)
Additions to furniture, fixtures and other		(1,354	)		(284	)		0		(1,638	)
Proceeds from sale of properties and other investing activities		2,268			0			0		2,268
Cash flows from financing activities:
Proceeds from debt		20,000			0			0		20,000
Principal payments on debt		(25,000	)		0			0		(25,000	)
Intercompany transfers		1,851			(1,851	)		0		0
Other financing activities		(12,579	)		0			0		(12,579	)
Change in cash and cash equivalents		(4,164	)		0			0		(4,164	)
Beginning cash and cash equivalents		54,405			0			0		54,405
Ending cash and cash equivalents	$	50,241		$	0		$	0	$	50,241

15. Subsequent Events

The Company evaluated subsequent events occurring through the date the Unaudited Consolidated Financial Statements were issued, and identified the events presented below.

In July 2011, the Company signed a purchase and sale agreement with an unaffiliated party to acquire properties in the Denver-Julesburg Basin in Colorado and Wyoming (“DJ Basin Acquisition”) targeting the Niobrara formation for the contract price of $150 million. The DJ Basin Acquisition is expected to close during the third quarter of 2011, subject to customary closing conditions and adjustments.

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the following risks and uncertainties:

• volatility of market prices received for natural gas, natural gas liquids (“NGLs”) and oil;

• ability to receive drilling and other permits and regulatory approvals;

• legislative or regulatory changes;

• economic and competitive conditions;

• debt and equity market conditions;

• derivative and hedging activities;

• exploration risks such as drilling unsuccessful wells;

• the ability to obtain industry partners for our prospects on favorable terms to reduce our capital risks and accelerate our exploration activities;

• costs and availability of third party facilities for gathering, processing, refining and transportation;

• future processing volumes and pipeline throughput;

• reductions in the borrowing base under our revolving bank credit facility (the “Amended Credit Facility”);

• the potential for production decline rates from our wells to be greater than we expect;

• ability to replace natural production declines with new drilling or recompletion activities;

• changes in estimates of proved reserves;

• potential failure to achieve expected production from existing and future exploration or development projects;

• declines in the values of our natural gas and oil properties resulting in impairments;

• capital expenditures and other contractual obligations;

• liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;

• higher than expected costs and expenses including production, drilling and well equipment costs;

• occurrence of property acquisitions or divestitures;

• ability to obtain adequate pipeline transportation capacity for our production;

• changes in tax rates;

• compliance with environmental regulations; and

• other uncertainties, as well as those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2010 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections and in Item 1A, “Risk Factors” of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to publicly correct or update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

Overview

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

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in and developing key existing development programs. Through exploration and acquisition, we seek high quality growth prospects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices, and revenues related to the sale of NGLs, resulting from the processing of our natural gas by third parties, and the settlement of commodity hedges. As of December 31, 2010, our proved reserves were 1,118 Bcfe.

We were formed in January 2002. Since inception, we substantially increased our activity level and the number of properties that we operate and our operating results reflect this growth. We began operations in March 2002 with the acquisition of properties in the Wind River Basin. From 2002 through 2009, we completed several acquisitions of properties in the Uinta, Piceance and Powder River Basins. On December 15, 2004, we completed our initial public offering in which we received net proceeds of $347.3 million after deducting underwriting fees and other offering costs. Consistent with our strategy of pursuing strategic and complementary acquisitions of developed and undeveloped properties in the Rocky Mountain region, we are continuously evaluating acquisition opportunities. On June 8, 2011, we acquired entities and oil properties in the Uinta Basin with a purchase price of approximately $119 million (the “East Bluebell Acquisition”). This acquisition was financed through borrowings under the Amended Credit Facility. On July 8, 2011, we entered into a purchase and sale agreement to purchase oil properties in the Denver-Julesburg Basin with a purchase price of approximately $150 million, subject to customary closing conditions and adjustments (the “DJ Basin Acquisition”). Closing of the DJ Basin Acquisition is expected in the third quarter. We also intend to finance the DJ Basin Acquisition through borrowings under the Amended Credit Facility.

While there are currently no unannounced agreements for the acquisition of any material businesses or assets, future acquisitions could have a material impact on our financial condition and results of operations by increasing our proved reserves, production, and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with the borrowings under the Amended Credit Facility, other indebtedness, and/or debt, equity or equity-linked securities.

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Results of Operations

The financial information for the three and six months ended June 30, 2011 and 2010 that is discussed below is unaudited. In the opinion of management, such information contains all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

	Six Months Ended June 30,					Increase (Decrease)
	2011			2010		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil and gas production	$	366,525		$	349,949	$	16,576			5	%
Commodity derivative gain (loss)		(14,019	)		2,012		(16,031	)		nm	*
Other		3,259			2,474		785			32	%
Operating Expenses
Lease operating expense		27,374			26,022		1,352			5	%
Gathering, transportation and processing expense		40,674			34,457		6,217			18	%
Production tax expense		18,347			17,331		1,016			6	%
Exploration expense		2,048			955		1,093			114	%
Impairment, dry hole costs and abandonment expense		1,376			3,867		(2,491	)		(64	)%
Depreciation, depletion and amortization		134,241			122,434		11,807			10	%
General and administrative expense (1)		23,806			20,003		3,803			19	%
Non-cash stock-based compensation expense (1)		8,647			7,741		906			12	%
Total operating expenses	$	256,513		$	232,810	$	23,703			10	%
Production Data:
Natural gas (MMcf)		45,941			43,965		1,976			4	%
Oil (MBbls)		628			473		155			33	%
Combined volumes (MMcfe)		49,709			46,803		2,906			6	%
Daily combined volumes (MMcfe/d)		275			259		16			6	%
Average Realized Prices (2):
Natural gas (per Mcf)	$	6.57		$	6.91	$	(0.34	)		(5	)%
Oil (per Bbl)		80.53			70.12		10.41			15	%
Combined (per Mcfe)		7.09			7.20		(0.11	)		(2	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.55		$	0.56	$	(0.01	)		(2	)%
Gathering, transportation and processing expense		0.82			0.74		0.08			11	%
Production tax expense		0.37			0.37		0.00			0	%
Depreciation, depletion and amortization		2.70			2.62		0.08			3	%
General and administrative expense (3)		0.48			0.43		0.05			12	%

* Not meaningful.

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $32.5 million and $27.7 million for the six months ended June 30, 2011 and 2010, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.

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(2) Average realized prices shown in the table include the impact of all of our realized financial hedges in the form of commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. As a result of our realized hedging transactions, natural gas production revenues and oil production revenues increased (decreased) by the following amounts (in millions) for the periods indicated:

	Six Months Ended June 30,
	2011			2010
Natural gas production revenues	$	36.8		$	56.7
Oil production revenues	$	(3.1	)	$	1.2

Before the effects of hedging, the average prices we received for natural gas and oil were as follows:

	Six Months Ended June 30,
	2011		2010
Natural gas (per Mcf)	$	5.77	$	5.62
Oil (per Bbl)	$	85.52	$	67.65

(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. This presentation is a non-GAAP measure. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Consolidated Statements of Operations, were $0.65 and $0.59 for the six months ended June 30, 2011 and 2010, respectively.

Production Revenues and Volumes.Production revenues increased to $366.5 million for the six months ended June 30, 2011 from $349.9 million for the six months ended June 30, 2010 due to a 6% increase in production partially offset by a 1% decrease in natural gas and oil prices on a per Mcfe basis after the effects of realized cash flow hedges. The effects of realized hedges only include settlements from hedging instruments that were designated as cash flow hedges and exclude those that do not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges are included in the line item commodity derivative gain (loss) within operating revenues in the Unaudited Consolidated Statements of Operations. See below for more information related to the commodity derivative gain (loss) line item. The net increase in production added approximately $21.4 million of production revenues, while the decrease in average realized price decreased production revenues by approximately $4.8 million.

During the six months ended June 30, 2011, we realized an increase in production revenues related to NGL values received for a portion of our gas production in the Piceance Basin of approximately $56.7 million, or $1.14 per Mcfe, as compared to an increase of $29.5 million, or $0.63 per Mcfe, for the six months ended June 30, 2010. There is no assurance that the amount received in the future related to NGLs resulting from the processing of natural gas will exceed the additional cost of processing or the price of natural gas. Based on our revised capital expenditures budget and current price outlook (see “–Capital Resources and Liquidity” section below) for 2011, we expect our NGL-related revenues for 2011 to be comparable to prior years.

Total production volumes for the six months ended June 30, 2011 of 49.7 Bcfe increased from 46.8 Bcfe for the six months ended June 30, 2010 primarily due to increased production in the Piceance and Uinta Basins. The increase in production was partially offset by a decrease in production from the Wind River and Powder River Basins. Additional information concerning production is in the following table:

	Six Months Ended June 30, 2011						Six Months Ended June 30, 2010						% Increase (Decrease)
	Oil		Natural Gas		Total		Oil		Natural Gas		Total		Oil			Natural Gas			Total
	(MBbls)		(MMcf)		(MMcfe)		(MBbls)		(MMcf)		(MMcfe)		(MBbls)			(MMcf)			(MMcfe)
Piceance Basin		261		22,253		23,819		263		20,691		22,269		(1	)%		8	%		7	%
Uinta Basin		340		14,178		16,218		183		12,746		13,844		86	%		11	%		17	%
Wind River Basin		10		2,738		2,798		9		3,562		3,616		11	%		(23	)%		(23	)%
Powder River Basin		0		6,638		6,638		0		6,892		6,892		0	%		(4	)%		(4	)%
Other		17		134		236		18		74		182		(6	)%		81	%		30	%
Total		628		45,941		49,709		473		43,965		46,803		33	%		4	%		6	%

The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 143 new gross wells from July 1, 2010 to June 30, 2011. The production increase in the Uinta Basin resulted primarily from our full field development of West Tavaputs in the Uinta Basin with initial sales from 37 new gross wells from July 1, 2010 to June 30, 2011. In addition, we had increased production resulting from our ongoing development program at Blacktail Ridge and Lake Canyon in the Uinta Basin with initial sales from 25 new gross wells from July 1, 2010 to June 30, 2011. The production decreases in the Wind River and Powder River Basins were due to natural production declines with no significant drilling or recompletion activities in our Wind River Basin properties or coalbed methane Powder River Basin properties to offset these declines.

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Hedging Activities.During the six months ended June 30, 2011, approximately 65% of our natural gas volumes (excluding basis only swaps, which were equivalent to 8% of our natural gas volumes), 54% of our NGL volumes and 67% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $36.8 million and a decrease in oil revenues of $3.1 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the six months ended June 30, 2010, approximately 75% of our natural gas volumes (excluding basis only swaps, which were equivalent to 15% of our natural gas volumes), 42% of NGL volumes and 47% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $56.7 million and an increase in oil revenues of $1.2 million after settlements for all commodity derivatives, including basis only and NGL swaps. We may not be able to generate increases in revenue as in the first half of 2011 as discussed above because hedges we entered into at higher prices are expiring, and we may be unable to enter into new hedges at those prices due to lower natural gas prices.

The overall change in commodity derivative gain (loss) to a loss of $14.0 million for the six months ended June 30, 2011 from a gain of $2.0 million for the six months ended June 30, 2010 was primarily due to a change in the unrealized gain (loss) on derivatives not designated as cash flow hedges from a $15.3 million gain for the six months ended June 30, 2010 to a $1.1 million loss for the six months ended June 30, 2011 as a result of changes in the fair value of our basis only and NGL hedges.

The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain (loss) for the periods indicated:

	Six Months Ended June 30,
	2011			2010
	(in thousands)
Realized loss on derivatives not designated as cash flow hedges	$	(13,994	)	$	(12,986	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges		1,050			(266	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges		(1,075	)		15,264
Total commodity derivative gain (loss)	$	(14,019	)	$	2,012

Lease Operating Expense. Lease operating expense decreased to $0.55 per Mcfe for the six months ended June 30, 2011 from $0.56 per Mcfe for the six months ended June 30, 2010. The six months ended June 30, 2010 included $1.9 million of nonrecurring remediation efforts related to a minor condensate leak at the Dry Canyon Compressor Station in the Uinta Basin, which increased lease operating expense by $0.04 per Mcfe. The successful drilling program in our Blacktail Ridge field in the Uinta Basin throughout the six months ended June 30, 2011 has increased water production. The additional trucking and disposal costs associated with this water production are primarily responsible for the increase in lease operating expense. As our development program in the Blacktail Ridge field continues to grow, we plan to add necessary infrastructure and scale to reduce future operating costs on a unit of production basis.

Gathering, Transportation and Processing Expense.Gathering, transportation and processing expense increased to $0.82 per Mcfe for the six months ended June 30, 2011 from $0.74 per Mcfe for the six months ended June 30, 2010. Increased production from the West Tavaputs field within the Uinta Basin has led to an increase in volumes gathered and processed under higher cost structured agreements, which resulted in higher costs on a per unit basis. We also recognized additional expenses associated with firm contracts to gather, transport and process our production from the Piceance and Uinta Basins ahead of anticipated production increases.

We have entered into long-term firm transportation contracts for a portion of our production to guarantee capacity on major pipelines and reduce the risk and impact related to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance and Uinta Basins where we expect to allocate a significant portion of our capital expenditure programs in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Piceance and Uinta Basins. Included in gathering, transportation and processing expense are $0.28 and $0.18 per Mcfe of firm transportation and gathering expense for the six months ended June 30, 2011 and 2010, respectively, and $0.05 per Mcfe of firm processing expense from long-term contracts for both the six months ended June 30, 2011 and 2010. The increase in firm transportation and gathering expense to $0.28 per Mcfe for the six months ended June 30, 2011 compared to $0.18 per Mcfe for the six months ended June 30, 2010 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Piceance and Uinta Basins as mentioned above. We have also contracted for capacity on the Ruby Pipeline, which went into service on July 27, 2011 and transports natural gas from Opal, Wyoming to Malin, Oregon, allowing us to market our gas production from the Piceance and Uinta Basins to markets in the northwest United States. Beginning in August 2011, we will begin incurring demand charges of approximately $1.1 million per month, or $3.4 million per quarter, for firm transportation on the Ruby Pipeline. This commitment expires on July 31, 2021.

Production Tax Expense.Total production taxes increased to $18.3 million for the six months ended June 30, 2011 from $17.3 million for the six months ended June 30, 2010. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense increased during the six months ended June 30, 2011 primarily due to a 15% increase in the wellhead values of production, excluding hedging activities, partially offset by a decrease in production tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 5.7% for the six months ended June 30, 2011 compared to 6.2% for the six months ended June 30, 2010.

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Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The decrease in the overall production tax rate is consistent with our production decrease from states with higher production tax rates.

Exploration Expense.Exploration expense increased to $2.0 million for the six months ended June 30, 2011 from $1.0 million for the six months ended June 30, 2010. Exploration expense for the six months ended June 30, 2011 consisted of $1.5 million of geological and geophysical seismic programs and $0.5 million for delay rentals across all basins. Exploration expense for the six months ended June 30, 2010 consisted of $0.3 million for seismic programs, $0.1 million for evaluation of non-acquired assets and $0.6 million for delay rentals and other costs across all basins.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense decreased to $1.4 million during the six months ended June 30, 2011 from $3.9 million during the six months ended June 30, 2010. For the six months ended June 30, 2011, expired leasehold costs were $1.1 million and dry hole costs were $0.3 million. The $0.3 million in dry hole costs were related to additional costs incurred in the current period for wells determined to be dry holes in prior periods. For the six months ended June 30, 2010, abandonment expense associated with exploratory drilling locations was $0.3 million, expired leasehold costs were $1.6 million and dry hole costs were $2.0 million. The $2.0 million in dry hole costs were primarily associated with the partial expensing of one exploratory well in the Blacktail Ridge prospect of the Uinta Basin. For the six months ended June 30, 2011 and 2010, we did not incur any impairment charges related to the net carrying value of our oil and gas properties.

Depreciation, Depletion and Amortization (“DD&A”).DD&A was $134.2 million for the six months ended June 30, 2011 compared to $122.4 million for the six months ended June 30, 2010. The increase of $11.8 million was a result of a 6% increase in production for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 coupled with a 3% increase in the DD&A rate. The increase in production accounted for $7.6 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for a $4.2 million increase in DD&A expense. For the six months ended June 30, 2011 and 2010, the weighted average DD&A rates were $2.70 per Mcfe and $2.62 per Mcfe, respectively.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $23.8 million in the six months ended June 30, 2011 from $20.0 million in the six months ended June 30, 2010. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 26 for a reconciliation and explanation. This increase was primarily due to an increase in employee compensation and benefit programs for the six months ended June 30, 2011. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $0.48 per Mcfe for the six months ended June 30, 2011 from $0.43 per Mcfe for the six months ended June 30, 2010.

Non-cash charges for stock-based compensation were $8.6 million for the six months ended June 30, 2011 compared to $7.7 million for the six months ended June 30, 2010. Non-cash stock-based compensation expense for both periods related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation was primarily due to additional equity awards that were granted during the last six months of 2010 and during the six months ended June 30, 2011.

The components of non-cash stock-based compensation for the six months ended June 30, 2011 and 2010 are shown in the following table:

	Six Months Ended June 30,
	2011		2010
	(in thousands)
Stock options and nonvested equity shares of common stock	$	8,046	$	7,232
Shares issued for 401(k) plan		388		360
Shares issued for directors’ fees		213		149
Total	$	8,647	$	7,741

Interest Expense.Interest expense increased to $24.4 million for the six months ended June 30, 2011 from $21.3 million for the six months ended June 30, 2010. The increase was primarily due to an increase in our weighted average outstanding debt balance, including our Amended Credit Facility, 5.0% Convertible Notes (“Convertible Notes”) and 9.875% Senior Notes (“Senior Notes”), which was $429.9 million for the six months ended June 30, 2011 compared to $403.9 million for the six months ended June 30, 2010. The increase in our weighted average outstanding debt balance was due to additional borrowings on the Amended Credit Facility. In addition, capitalized interest costs decreased during the six months ended June 30, 2011. Interest cost is capitalized as a component of oil and gas property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. For the six months ended June 30, 2011, we had fewer significant wells and facilities in progress as compared to the six months ended June 30, 2010, which resulted in a lower amount of interest costs that were capitalized during the period. We capitalized interest costs of $1.0 million and $2.5 million for the six months ended June 30, 2011 and 2010, respectively.

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Income Tax Expense. Income tax expense totaled $27.2 million for the six months ended June 30, 2011 compared to $37.3 million for the six months ended June 30, 2010, resulting in effective tax rates of 36.2% and 37.1%, respectively. The decrease in income tax expense was primarily the result of the variations in revenue and expense components as discussed above and the resulting decrease in income before income taxes. The effective tax rate decline was primarily the result of an increase in stock-based compensation deductible for tax purposes. Additionally, a greater proportion of our operating revenue was attributable to lower tax rate jurisdictions during the six months ended June 30, 2011. The effect of this rate change on our prior year net deferred tax liability was included in income tax expense for the six months ended June 30, 2011. The effective tax rate will vary from period to period due to changes in the composition of income between state tax jurisdictions resulting from our activity. For both the 2011 and 2010 periods, our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are subject to different treatment for income tax purposes than for financial reporting purposes as well as the effect of state income taxes.

30

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

	Three Months Ended June 30,					Increase (Decrease)
	2011			2010		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil and gas production	$	194,328		$	186,300	$	8,028			4	%
Commodity derivative gain (loss)		(2,907	)		7,676		(10,583	)		(138	)%
Other		3,021			2,649		372			14	%
Operating Expenses
Lease operating expense		14,075			13,581		494			4	%
Gathering, transportation and processing expense		21,338			18,487		2,851			15	%
Production tax expense		9,781			9,042		739			8	%
Exploration expense		697			654		43			7	%
Impairment, dry hole costs and abandonment expense		1,093			988		105			11	%
Depreciation, depletion and amortization		68,847			65,900		2,947			4	%
General and administrative expense (1)		10,739			10,201		538			5	%
Non-cash stock-based compensation expense (1)		4,018			3,767		251			7	%
Total operating expenses	$	130,588		$	122,620	$	7,968			6	%
Production Data:
Natural gas (MMcf)		24,506			23,342		1,164			5	%
Oil (MBbls)		331			288		43			15	%
Combined volumes (MMcfe)		26,492			25,070		1,422			6	%
Daily combined volumes (MMcfe/d)		291			275		16			6	%
Average Realized Prices (2):
Natural gas (per Mcf)	$	6.47		$	6.76	$	(0.29	)		(4	)%
Oil (per Bbl)		82.40			70.18		12.22			17	%
Combined (per Mcfe)		7.01			7.10		(0.09	)		1	%
Average Costs (per Mcfe):
Lease operating expense	$	0.53		$	0.54	$	(0.01	)		(2	)%
Gathering, transportation and processing expense		0.81			0.74		0.07			9	%
Production tax expense		0.37			0.36		0.01			3	%
Depreciation, depletion and amortization		2.60			2.63		(0.03	)		(1	)%
General and administrative expense (3)		0.41			0.41		(0.00	)		0	%

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $14.8 million and $14.0 million for the three months ended June 30, 2011 and 2010, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.

(2) Average realized prices shown in the table include the impact of all of our realized financial hedges in the form of commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. As a result of our realized hedging transactions, natural gas production revenues and oil production revenues increased (decreased) by the following amounts (in millions) for the periods indicated:

	Three Months Ended June 30,
	2011			2010
Natural gas production revenues	$	13.5		$	40.8
Oil production revenues	$	(2.3	)	$	0.8

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Before the effects of hedging, the average prices we received for natural gas and oil were as follows:

	Three Months Ended June 30,
	2011		2010
Natural gas (per Mcf)	$	5.91	$	5.01
Oil (per Bbl)	$	89.40	$	67.27

(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. This presentation is a non-GAAP measure. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Consolidated Statements of Operations, were $0.56 for both the three months ended June 30, 2011 and 2010.

Production Revenues and Volumes.Production revenues increased to $194.3 million for the three months ended June 30, 2011 from $186.3 million for the three months ended June 30, 2010 due to a 6% increase in production partially offset by a 1% decrease in natural gas and oil prices on a per Mcfe basis after the effects of realized cash flow hedges. The effects of realized hedges only include settlements from hedging instruments that were designated as cash flow hedges and exclude those that do not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges are included in the line item commodity derivative gain (loss) within operating revenues in the Unaudited Consolidated Statements of Operations. See below for more information related to the commodity derivative gain (loss) line item. The net increase in production added approximately $10.4 million of production revenues, while the decrease in average price decreased production revenues by approximately $2.4 million.

During the three months ended June 30, 2011, we realized an increase in production revenues related to NGL values received for a portion of our gas production in the Piceance Basin of approximately $32.6 million, or $1.23 per Mcfe, as compared to an increase of $16.8 million, or $0.67 per Mcfe, for the three months ended June 30, 2010. There is no assurance that the amount received in the future related to NGLs resulting from the processing of natural gas will exceed the additional cost of processing or the price of natural gas. Based on our revised capital expenditures budget and current price outlook (see “—Capital Resources and Liquidity” section below) for 2011, we expect our NGL-related revenues for 2011 to be comparable to prior years.

Total production volumes for the three months ended June 30, 2011 of 26.5 Bcfe increased from 25.1 Bcfe for the three months ended June 30, 2010 primarily due to increased production in the Uinta Basin. The increase in production was partially offset by decreases in production from the Piceance, Wind River, and Powder River Basins. Additional information concerning production is in the following table:

	Three Months Ended June 30, 2011						Three Months Ended June 30, 2010						% Increase (Decrease)
	Oil		Natural Gas		Total		Oil		Natural Gas		Total		Oil			Natural Gas			Total
	(MBbls)		(MMcf)		(MMcfe)		(MBbls)		(MMcf)		(MMcfe)		(MBbls)			(MMcf)			(MMcfe)
Piceance Basin		121		11,121		11,847		158		11,522		12,470		(23	)%		(3	)%		(5	)%
Uinta Basin		195		8,632		9,802		117		6,486		7,188		67	%		33	%		36	%
Wind River Basin		6		1,383		1,419		4		1,747		1,771		50	%		(21	)%		(20	)%
Powder River Basin		0		3,297		3,297		0		3,557		3,557		0	%		(7	)%		(7	)%
Other		9		73		127		9		30		84		0	%		143	%		51	%
Total		331		24,506		26,492		288		23,342		25,070		15	%		5	%		6	%

The production increase in the Uinta Basin resulted primarily from our full field development of West Tavaputs in the Uinta Basin with initial sales from 37 new gross wells from July 1, 2010 to June 30, 2011. In addition, we had increased production resulting from our ongoing development program at Blacktail Ridge and Lake Canyon with initial sales from 25 new gross wells from July 1, 2010 to June 30, 2011. The production decrease in the Piceance Basin was the result of reducing our development activity from a three rig drilling program to a two rig drilling program allowing us to expand our resources in the Uinta Basin. The production decreases in the Wind River and Powder River Basins were due to natural production declines with no significant drilling or recompletion activities in our Wind River Basin properties or coalbed methane Powder River Basin properties to offset these declines.

Hedging Activities.During the three months ended June 30, 2011, approximately 66% of our natural gas volumes (excluding basis only swaps, which were equivalent to 7% of our natural gas volumes), 63% of NGL volumes and 71% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $13.5 million and a decrease in oil revenues of $2.3 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the three months ended June 30, 2010, approximately 73% of our natural gas volumes (excluding basis only swaps, which were equivalent to 11% of our natural gas volumes), 36% of NGL volumes and 46% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $40.8 million and an increase in oil revenues of $0.8 million after settlements for all commodity derivatives, including basis only and NGL swaps.

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The overall change in commodity derivative gain (loss) to a loss of $2.9 million for the three months ended June 30, 2011 from a gain of $7.7 million for the three months ended June 30, 2010 was primarily due to a decrease in the unrealized gain on derivatives not designated as cash flow hedges from $16.6 million for the three months ended June 30, 2010 to $4.8 million for the three months ended June 30, 2011 primarily as a result of changes in the fair value of our basis only and NGL hedges.

The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain (loss) for the periods indicated:

	Three Months Ended June 30,
	2011			2010
	(in thousands)
Realized loss on derivatives not designated as cash flow hedges	$	(8,590	)	$	(8,223	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges		888			(659	)
Unrealized gain on derivatives not designated as cash flow hedges		4,795			16,558
Total commodity derivative gain (loss)	$	(2,907	)	$	7,676

Lease Operating Expense. Lease operating expense decreased to $0.53 per Mcfe for the three months ended June 30, 2011 from $0.54 per Mcfe for the three months ended June 30, 2010. The three months ended June 30, 2010 included $1.9 million of nonrecurring remediation efforts related to a minor condensate leak at the Dry Canyon Compressor Station in the Uinta Basin, which increased lease operating expense by $0.08 per Mcfe. The successful drilling program in our Blacktail Ridge field in the Uinta Basin throughout the six months ended June 30, 2011 has increased water production. The additional trucking and disposal costs associated with this water production are primarily responsible for the increase in lease operating expense. As our development program in the Blacktail Ridge field continues to grow, we plan to add necessary infrastructure and scale to reduce future operating costs on a unit of production basis.

Gathering, Transportation and Processing Expense.Gathering, transportation and processing expense increased to $0.81 per Mcfe for the three months ended June 30, 2011 from $0.74 per Mcfe for the three months ended June 30, 2010. Increased production from the West Tavaputs field within the Uinta Basin has led to an increase in volumes gathered and processed under higher cost structured agreements, resulting in higher costs on a per unit basis. Also, we recognized additional expenses associated with firm contracts to gather, transport and process our production from the Piceance and Uinta Basins ahead of anticipated production increases.

Included in gathering, transportation and processing expense are $0.27 and $0.19 per Mcfe of firm transportation and gathering expense and $0.06 and $0.05 per Mcfe of firm processing expense from long-term contracts for the three months ended June 30, 2011 and 2010, respectively. The increase in firm transportation and gathering expense to $0.27 per Mcfe for the three months ended June 30, 2011 compared to $0.19 per Mcfe for the three months ended June 30, 2010 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Piceance and Uinta Basins as mentioned above. We have also contracted for capacity on the Ruby Pipeline, which went into service on July 27, 2011 and transports natural gas from Opal, Wyoming to Malin, Oregon, allowing us to market our gas production from the Piceance and Uinta Basins to markets in the northwest United States. Beginning in August 2011, we will begin incurring demand charges of approximately $1.1 million per month, or $3.4 million per quarter, for firm transportation on the Ruby Pipeline. This commitment expires on July 31, 2021.

Production Tax Expense.Total production taxes increased to $9.8 million for the three months ended June 30, 2011 from $9.0 million for the three months ended June 30, 2010. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of natural gas and oil sales before hedging adjustments was 5.6% for the three months ended June 30, 2011 compared to 6.6% for the three months ended June 30, 2010.

Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The decrease in the overall production tax rate is consistent with our production decrease from states with higher production tax rates.

Exploration Expense.Exploration expense remained constant at $0.7 million for both of the three months ended June 30, 2011 and 2010. Exploration expense for the three months ended June 30, 2011 consisted of $0.3 million of geological and geophysical seismic programs and $0.4 million for delay rentals across all basins. Exploration expense for the three months ended June 30, 2010 consisted of $0.1 million for seismic programs, $0.1 million for evaluation of non-acquired assets and $0.5 million for delay rentals and other costs across all basins.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased to $1.1 million during the three months ended June 30, 2011 from $1.0 million during the three months ended June 30, 2010. For the three months ended June 30, 2011, expired leasehold costs were $0.9 million and dry hole costs were $0.2 million. The $0.2 million in dry hole costs were related to additional costs incurred in the current period for wells determined to be dry holes in prior periods. For the three months ended June 30, 2010, abandonment expense associated with exploratory drilling locations was $0.1 million, expired leasehold costs were $0.8 million and dry hole costs were $0.1 million. The $0.1 million in dry hole costs were related to additional costs incurred in the current period for wells determined to be dry holes in prior periods. For the three months ended June 30, 2011 and 2010, we did not incur any impairment charges related to the net carrying value of our oil and gas properties.

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Depreciation, Depletion and Amortization.DD&A was $68.8 million for the three months ended June 30, 2011 compared to $65.9 million for the three months ended June 30, 2010. The increase of $2.9 million was a result of a 6% increase in production for the three months ended June 30, 2011 compared to the three months ended June 30, 2010 partially offset by a 1% decrease in the DD&A rate. The increase in production accounted for $3.7 million of additional DD&A expense, while the overall decrease in the DD&A rate accounted for a $0.8 million decrease in DD&A expense. For the three months ended June 30, 2011 and 2010, the weighted average DD&A rates were $2.60 per Mcfe and $2.63 per Mcfe, respectively.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $10.7 million in the three months ended June 30, 2011 from $10.2 million in the three months ended June 30, 2010. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 31 for a reconciliation and explanation. This increase was primarily due to an increase in employee compensation and benefit programs for the three months ended June 30, 2011. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, was $0.41 per Mcfe for both the three months ended June 30, 2011 and 2010.

Non-cash charges for stock-based compensation were $4.0 million for the three months ended June 30, 2011 compared to $3.8 million for the three months ended June 30, 2010. Non-cash stock-based compensation expense for both periods related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees.

The components of non-cash stock-based compensation for the three months ended June 30, 2011 and 2010 are shown in the following table:

	Three Months Ended June 30,
	2011		2010
	(in thousands)
Stock options and nonvested equity shares of common stock	$	3,805	$	3,574
Shares issued for 401(k) plan		112		115
Shares issued for directors’ fees		101		78
Total	$	4,018	$	3,767

Interest Expense.Interest expense increased to $12.3 million for the three months ended June 30, 2011 from $11.2 million for the three months ended June 30, 2010. The increase was primarily due to an increase in our weighted average outstanding debt balance, including our Amended Credit Facility, Convertible Notes and Senior Notes, which was $454.2 million for the three months ended June 30, 2011 compared to $404.5 million for the three months ended June 30, 2010. The increase in our weighted average outstanding debt balance was due to additional borrowings on the Amended Credit Facility. In addition, capitalized interest costs decreased during the three months ended June 30, 2011. Interest cost is capitalized as a component of oil and gas property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. For the three months ended June 30, 2011, we had fewer significant wells and facilities in progress as compared to the three months ended June 30, 2010 which resulted in a lower amount of interest costs that were capitalized during the period. We capitalized interest costs of $0.5 million and $1.2 million for the three months ended June 30, 2011 and 2010, respectively.

Income Tax Expense. Income tax expense totaled $19.0 million for the three months ended June 30, 2011 compared to $23.7 million for the three months ended June 30, 2010, resulting in effective tax rates of 36.8% and 37.7%, respectively. The decrease in income tax expense was primarily the result of the variations in revenue and expense components as discussed above and the resulting decrease in income before income taxes. The effective tax rate decline was primarily the result of an increase in stock-based compensation deductible for tax purposes. Additionally, a greater proportion of our operating revenue was attributable to lower tax rate jurisdictions during the three months ended June 30, 2011. The effect of this rate change on our prior year net deferred tax liability was included in income tax expense for the three months ended June 30, 2011. The effective tax rate will vary from period to period due to changes in the composition of income between state tax jurisdictions resulting from our activity. For both the 2011 and 2010 periods, our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are subject to different treatment for income tax purposes than for financial reporting purposes as well as the effect of state income taxes.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, including our Convertible Notes and Senior Notes, bank credit facilities, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of natural gas and oil properties. As we pursue profitable reserves and production growth, we continually monitor the

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capital resources available to us, including issuance of debt and equity securities, to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on available capital and our success in finding or acquiring additional reserves. The credit markets have experienced periods of dislocation over the past two to three years, which may affect our access to capital and our cost of capital. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. We funded the East Bluebell Acquisition through borrowings under the Amended Credit Facility. We also expect to fund the DJ Basin Acquisition through borrowings under our Amended Credit Facility. In addition, our hedge positions provide relative certainty on a significant portion of our cash flows from operations through 2011 and 2012 even with the general decline in the price of natural gas resulting from current oversupply and decreased demand. We actively review acquisition opportunities on an ongoing basis. If we were to make substantial additional acquisitions for cash, we may need to obtain additional equity or debt financing, which may be at a higher cost than previous issuances or that was previously available. We have an automatically effective shelf registration statement with the SEC that we used for the offering of our Senior Notes and that we may use for future securities offerings.

At June 30, 2011, we had cash and cash equivalents of $39.9 million with $145.0 million outstanding under our Amended Credit Facility. Under our Amended Credit Facility, we have a borrowing base of $800.0 million with commitments from 19 lenders for a total of $700.0 million, which was reaffirmed on March 25, 2011 based on our December 31, 2010 reserves and hedge position. For the six months ended June 30, 2011, the weighted average outstanding balance under our Amended Credit Facility was $23.6 million and the maximum outstanding balance was $145.0 million. Our borrowing capacity is reduced by $26.0 million due to an outstanding irrevocable letter of credit.

Cash Flow from Operating Activities

For the six months ended June 30, 2011, we generated $211.2 million of cash provided by operating activities, a decrease of $0.8 million over the same period in 2010. Cash provided by operating activities decreased primarily due to higher cash operating expenses including lease operating expense, gathering, transportation and processing expense, production tax expense and general and administrative expense, which were slightly offset by higher production volumes and revenues.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas, NGLs and oil. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic and political activity, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3.—Quantitative and Qualitative Disclosure about Market Risk” below.

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas, NGLs and oil prices, we have entered into financial commodity swap and cashless collar contracts (purchased put options and written call options) to receive fixed prices for a portion of our production revenue. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production revenue. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. In addition to the swaps and collars, we also have entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. At June 30, 2011, we had in place natural gas financial collars, swaps and basis only swaps covering portions of our 2011, 2012 and 2013 production revenue, NGL swaps covering portions of 2011 and 2012 production and crude oil financial collars and swaps covering portions of our 2011, 2012, 2013 and 2014 production and revenue.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedges are effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction occurs. The ineffective portion of hedge derivatives is reported in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. Realized gains and losses on cash flow hedges are transferred from AOCI and recognized in earnings and included within oil and gas production revenues in the Unaudited Consolidated Statements of Operations as the associated production occurs.

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During the term of a derivative instrument, if we determine that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains or losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI and are reclassified to earnings when the underlying transaction occurs. If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment and all subsequent mark-to-market gains and losses are recorded in earnings, and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.

Some of our derivatives do not qualify for hedge accounting or are not designated as cash flow hedges but are, to a degree, an economic offset to our commodity price exposure. If a derivative instrument does not qualify as a cash flow hedge or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty. Realized gains and losses of derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Consolidated Statements of Cash Flows.

In addition to the swaps and collars discussed above, we have entered into basis only swaps to hedge the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. Although we believe this is an appropriate part of a mitigation strategy, the basis only swaps do not qualify for hedge accounting because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments were recorded in earnings.

We have also entered into swap contracts to hedge a portion of the amount received related to NGLs resulting from the processing of our natural gas. Our NGL hedges were not designated as cash flow hedges, and the fair value of these derivative instruments were recorded in earnings.

At June 30, 2011, the estimated fair value of all of our commodity derivative instruments was a net asset of $27.7 million comprised of current and non-current assets and liabilities, including a fair value liability of $11.6 million for basis only swaps and a fair value liability of $8.7 million for NGL swaps. We will reclassify the appropriate cash flow hedge amounts from AOCI to gains and losses included in natural gas and oil production operating revenues as the hedged production quantities are produced. Based on current projected market prices, the net amount of existing unrealized after-tax income relating to cash flow hedges as of June 30, 2011 to be reclassified from AOCI to earnings in the next 12 months would be a gain of approximately $25.9 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The hedge instruments designated as cash flow hedges are at liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Ineffectiveness is reported in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. Although those derivatives may not achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

The table below summarizes the realized and unrealized gains and losses we incurred related to our derivative instruments for the periods indicated (amounts in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Realized gain on derivatives designated as cash flow hedges (1)	$	19,776		$	49,889		$	47,699		$	70,898
Realized loss on derivatives not designated as cash flow hedges (2)	$	(8,590	)	$	(8,223	)	$	(13,994	)	$	(12,986	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges (2)		888			(659	)		1,050			(266	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges (2)		4,795			16,558			(1,075	)		15,264
Total commodity derivative gain (loss)	$	(2,907	)	$	7,676		$	(14,019	)	$	2,012

(1) Included in oil and gas production revenues in the Unaudited Consolidated Statements of Operations.

(2) Included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

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The following table summarizes all of our hedges in place as of June 30, 2011:

Contract	Total Hedged Volumes		Quantity Type	Weighted Average Floor Price		Weighted Average Ceiling Price		Weighted Average Fixed Price		Basis Differential			Index Price(1)	Fair Market Value (in thousands)
Cashless Collars:
2011
Natural gas		1,230,000	MMBtu	$	4.75	$	6.00		N/A		N/A		CIG	$	890
Oil		55,200	Bbls	$	95.00	$	121.18		N/A		N/A		WTI	$	227
2012
Oil		146,400	Bbls	$	92.50	$	131.30		N/A		N/A		WTI	$	806
Swap Contracts:
2011
Natural gas		15,637,500	MMBtu		N/A		N/A	$	5.72		N/A		CIG	$	23,990
Natural gas		17,932,500	MMBtu		N/A		N/A	$	4.81		N/A		NWPL	$	10,704
Natural gas liquids (2)		38,475,000	Gallons		N/A		N/A	$	1.10		N/A		Mt. Belvieu	$	(8,641	)
Oil		478,400	Bbls		N/A		N/A	$	92.69		N/A		WTI	$	(2,008	)
2012
Natural gas		18,145,000	MMBtu		N/A		N/A	$	4.69		N/A		CIG	$	4,395
Natural gas		28,350,000	MMBtu		N/A		N/A	$	4.59		N/A		NWPL	$	3,068
Natural gas liquids (2)		21,000,000	Gallons		N/A		N/A	$	1.62		N/A		Mt. Belvieu	$	(68	)
Oil		878,400	Bbls		N/A		N/A	$	104.25		N/A		WTI	$	3,667
2013
Natural gas		1,825,000	MMBtu		N/A		N/A	$	5.01		N/A		CIG	$	461
Natural gas		1,825,000	MMBtu		N/A		N/A	$	5.07		N/A		NWPL	$	502
Oil		255,500	Bbls		N/A		N/A	$	104.51		N/A		WTI	$	884
2014
Oil		146,000	Bbls		N/A		N/A	$	103.63		N/A		WTI	$	399
Basis Only Swap Contracts (3):
2011
Natural gas		3,680,000	MMBtu		N/A		N/A		N/A	$	(1.72	)	NWPL	$	(5,342	)
2012
Natural gas		3,660,000	MMBtu		N/A		N/A		N/A	$	(1.24	)	NWPL	$	(2,976	)
Natural gas		3,660,000	MMBtu		N/A		N/A		N/A	$	(1.20	)	CIG	$	(3,243	)
Total														$	27,715

The following table includes all hedges entered into subsequent to June 30, 2011 through July 22, 2011:

Contract	Total Hedged Volumes		Quantity Type		Weighted Average Floor Price	Weighted Average Ceiling Price	Weighted Average Fixed Price		Basis Differential	Index Price(1)
Swap Contracts:
2011
Oil		61,200		Bbls	N/A	N/A	$	99.00	N/A		WTI
2012
Oil		36,600		Bbls	N/A	N/A	$	101.00	N/A		WTI
2013
Oil		73,000		Bbls	N/A	N/A	$	100.00	N/A		WTI
2014
Oil		73,000		Bbls	N/A	N/A	$	102.00	N/A		WTI

(1) CIG refers to Colorado Interstate Gas Rocky Mountains and NWPL refers to Northwest Pipeline Corporation, price as quoted in Platt’s Inside FERC on the first business day of each month. Mt. Belvieu refers to the average daily price as quoted by Oil Price Information Service (“OPIS”) for Mont Belvieu spot gas liquid prices. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

(2) Weighted average fixed price includes purity ethane, propane, normal butane, isobutane and natural gasoline hedges.

(3) Represents a swap of the basis between the NYMEX price and the spot price of the index listed under Index Price above.

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By removing the price volatility related to a portion of our natural gas production revenue for 2011, 2012 and 2013, a portion of our natural gas liquid production revenue for 2011 and 2012 and a portion of our oil production revenue for 2011, 2012, 2013 and 2014 we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

By using derivative instruments that are not traded or settled on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers and that are lenders in our Amended Credit Facility, affiliates of lenders in our Amended Credit Facility or potential lenders in our Amended Credit Facility. The creditworthiness of our counterparties is subject to continual review. Furthermore, all of our derivative contracts are documented with an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”) or other contracts that contain set-off provisions that, in the event of counterparty default, allow us to net our receivables with amounts that we owe the counterparties under our Amended Credit Facility or other general obligations.

We believe all of our counterparties currently are acceptable credit risks. We are not required to provide credit support or collateral to any of our counterparties other than cross collateralization with the properties securing our Amended Credit Facility, nor are they required to provide credit support to us. We do not believe that we will be required to post collateral as a result of proposed rules related to derivatives under the Dodd-Frank Wall Street Reform and Consumer Protection Act, although costs of hedging are expected to increase. As of July 22, 2011, we do not have any past due receivables from any of our counterparties.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

	Six Months Ended June 30,
Basin/Area	2011		2010
	(in millions)
Piceance	$	94.4	$	150.4
Uinta		279.0		60.3
Paradox		0.9		0.6
Powder River		22.4		3.6
Wind River		1.5		3.4
Other		9.8		7.3
Total	$	408.0	$	225.6

	Six Months Ended June 30,
	2011		2010
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	129.3	$	3.9
Drilling, development, exploration and exploitation of natural gas and oil properties (1)		273.8		219.4
Geologic and geophysical costs		2.0		1.0
Furniture, fixtures and equipment		2.9		1.3
Total (2)	$	408.0	$	225.6

(1) Includes related gathering and facilities costs.

(2) For the six months ended June 30, 2010, we received $1.9 million of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.

On June 8, 2011, we completed the East Bluebell Acquisition, an acquisition from an unrelated party of oil properties and related assets in the East Bluebell field of the Uinta Basin in Duchesne and Uintah Counties in Utah. The properties were purchased for approximately $119.4 million, subject to final post-closing adjustments. The preliminary purchase price allocation was $74.2 million for proved oil and gas properties and $45.2 million for unevaluated oil and gas properties excluded from amortization, which is subject to final purchase price allocation adjustments. This acquisition was funded using our Amended Credit Facility. The properties are located near our Blacktail Ridge-Lake Canyon project area.

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In July 2011, we signed a purchase and sale agreement with an unaffiliated party for the DJ Basin Acquisition, under which we will acquire properties in the Denver-Julesburg Basin in Colorado and Wyoming for the contract price of $150 million. The DJ Basin Acquisition is expected to close during the third quarter of 2011, subject to customary closing conditions and adjustments. We also expect to fund the DJ Basin Acquisition through borrowings under our Amended Credit Facility.

Our current estimate is for capital expenditures of $685 million to $705 million in 2011, which may be adjusted throughout the remainder of the year as business conditions warrant. This amount excludes the East Bluebell Acquisition of $119.4 million, which is subject to final purchase price allocation adjustments, and our pending DJ Basin Acquisition of approximately $150 million. Our estimated capital expenditure budget of $685 million to $705 million in 2011 includes additional drilling and facilities capital expenditures at the East Bluebell Acquisition area and at our pending DJ Basin Acquisition area. We have increased our capital expenditure budget from the budget set forth in our Form 10-K for the year ended December 31, 2010. We believe that we have sufficient available liquidity through 2011 to fund our capital expenditures budget from cash flow from operations and the Amended Credit Facility. Future cash flows are subject to a number of variables, including our level of natural gas and oil production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If natural gas and oil

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

Financing Activities

Our outstanding debt is summarized below (in thousands):

		As of June 30, 2011							As of December 31, 2010
	Maturity Date	Principal		Unamortized Discount			Carrying Amount		Principal		Unamortized Discount			Carrying Amount
Amended Credit Facility	April 1, 2014	$	145,000	$	0		$	145,000	$	0	$	0		$	0
Senior Notes (1)	July 15, 2016		250,000		(9,537	)		240,463		250,000		(10,234	)		239,766
Convertible Notes (2)	March 15, 2028 (3)		172,500		(4,796	)		167,704		172,500		(7,867	)		164,633

(1) The aggregate estimated fair value of the Senior Notes was approximately $284.5 million as of June 30, 2011 based on reported market trades of these instruments.

(2) The aggregate fair value of the Convertible Notes was approximately $177.9 million as of June 30, 2011. Because there is no active, public market for the Convertible Notes, the fair value was based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades.

(3) We currently expect that the holders will put the Convertible Notes to us in March 2012, and we expect to settle the notes in cash through borrowings under the Amended Credit Facility. We also have the option to call the Convertible Notes at any time thereafter.

Revolving Credit Facility

On March 16, 2010, we amended our credit facility and extended the maturity date to April 1, 2014. The Amended Credit Facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.0% to 3.0% or an alternate base rate (“ABR”), based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.0%, plus applicable margins ranging from 1.0% to 2.0%. The borrowing base is required to be redetermined twice per year. On March 25, 2011, the borrowing base was reaffirmed at $800.0 million with commitments from 19 lenders of $700.0 million, based on December 31, 2010 reserves and hedge positions. We pay annual commitment fees of 0.5% of the unused amount of our commitments. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. The Amended Credit Facility also contains certain financial covenants. We currently are in compliance with all financial and other covenants, and we have complied with all financial covenants for all prior periods.

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As of June 30, 2011, we had $145.0 million outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility effective May 4, 2010, which reduced the borrowing capacity of the Amended Credit Facility by $26.0 million.

9.875% Senior Notes Due 2016

The Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes. Interest is payable in arrears semi-annually on January 15 and July 15 each year. The Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility and the Convertible Notes. The Senior Notes include certain covenants that limit our ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. We currently are in compliance with all financial covenants, and we have complied with all financial covenants for all prior periods.

5% Convertible Senior Notes due 2028

The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness, including the Senior Notes. Interest is payable semi-annually in arrears on March 15 and September 15 of each year. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility.

The following table summarizes the cash portion of interest expense related to the Amended Credit Facility, Senior Notes and Convertible Notes along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Amended Credit Facility (1)
Cash interest	$	1,253	$	973	$	2,234	$	1,422
Non-cash interest	$	780	$	778	$	1,559	$	1,183
Senior Notes (2)
Cash interest	$	6,172	$	6,172	$	12,344	$	12,344
Non-cash interest	$	611	$	554	$	1,219	$	1,105
Convertible Notes (3)
Cash interest	$	2,156	$	2,156	$	4,313	$	4,313
Non-cash interest	$	1,858	$	1,723	$	3,641	$	3,375

(1) Cash interest includes amounts related to interest and commitment fees paid on the line of credit and participation and fronting fees paid on the letter of credit.

(2) The stated interest rate for the Senior Notes is 9.875% per annum with an effective interest rate of 11.3% per annum.

(3) The stated interest rate for the Convertible Notes is 5% per annum with an effective interest rate of 9.7% per annum. The effective interest rate of the Convertible Notes includes the amortization of the debt discount, which represents the fair value of the equity conversion feature at the time of issue.

Shelf Registration Statement.We have on file with the SEC an effective universal shelf registration statement to allow us to offer an indeterminate amount of equity or debt securities in the future. Under the registration statement, we may periodically offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. However, the issuance of additional securities in periods of market volatility may be less likely or may have terms less favorable to us. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

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Contractual Obligations.A summary of our contractual obligations as of and subsequent to June 30, 2011 is provided in the following table:

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)	$	553	$	553	$	145,553	$	553	$	553	$	1,013	$	148,778
Senior Notes (2)		24,688		24,688		24,688		24,688		24,688		251,029		374,469
Convertible Notes (3)		178,849		0		0		0		0		0		178,849
Purchase commitments (4)(5)		11,981		0		0		0		0		0		11,981
Drilling rig commitments (5)(6)		27,092		13,355		0		0		0		0		40,447
Office and office equipment leases and other		2,394		2,250		1,992		1,812		1,829		5,161		15,438
Firm transportation and processing agreements (5)(7)		61,372		61,876		61,791		61,516		59,930		215,894		522,379
Asset retirement obligations (8)		1,256		1,390		563		187		357		54,428		58,181
Derivative liabilities (9)		4,042		2,592		0		0		0		0		6,634
Total	$	312,227	$	106,704	$	234,587	$	88,756	$	87,357	$	527,525	$	1,357,156

(1) Included in notes payable is the outstanding principal amount under our Amended Credit Facility due April 1, 2014. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Also included in notes payable is a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is April 30, 2018.

(2) On July 8, 2009, we issued $250.0 million aggregate principal amount of Senior Notes. We are obligated to make annual interest payments throughout maturity equal to $24.7 million.

(3) On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. For purposes of contractual obligations, we assume that the holders of our Convertible Notes will not exercise the conversion feature, and we will therefore repay the $172.5 million in cash in 2012. We currently expect that the holders will put the Convertible Notes to us in March 2012. We also are obligated to make annual interest payments equal to $8.6 million.

(4) We have two take-or-pay carbon dioxide (“CO2”) purchase agreements, one that expires in December 2011 and one that expires in February 2012, that impose a minimum volume commitment to purchase CO2 at a contracted price. The contracts provide CO2 used in fracture stimulation operations in our Uinta Basin operations. Should we not take delivery of the minimum volume required, we would be obligated to pay for the deficiency. At this time, our planned volumes needed exceed the minimum requirement, and we do not anticipate any deficiency payments.

(5) The values in the table represent the gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest and net revenue interest, which will vary from property to property.

(6) We currently have five drilling rigs under contract. Two contracts expire in 2011, one expires in 2012 and two expire in 2013. These contracts may be terminated, but we would be required to pay a total penalty of $25.1 million. All other rigs currently performing work for us are on a well-by-well basis and, therefore, can be released without penalty at the conclusion of drilling on the current well. These latter types of drilling obligations have not been included in the table above.

(7) We have entered into contracts that provide firm processing rights and firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to 13 years and require us to pay transportation demand and processing charges regardless of the amount of gas we deliver to the processing facility or pipeline.

(8) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(9) Derivative liabilities represent the net fair value for oil, NGL and natural gas commodity derivatives presented as liabilities in our Unaudited Consolidated Balance Sheets as of June 30, 2011. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See “Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 and in “—Commodity Hedging Activities” above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

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In addition to the commitments above, we have commitments for the purchase of facilities and infrastructure as of June 30, 2011 of $13.6 million.

Trends and Uncertainties

In addition to the discussion below, we refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 for a discussion of trends and uncertainties that may affect our financial condition or liquidity.

The EPA regulates the level of ozone in ambient air and is proposing lowering the allowed level of ozone. Because of intense sunlight at higher altitudes, most of the Rocky Mountain region, where we operate, has higher levels of ozone. As a result of these existing and possible more stringent standards, we may not be able to obtain permits necessary to construct and operate new facilities, or, if we obtain the permits, the added costs to comply with the requirements could substantially increase our operating expenses, which would reduce our profits or make certain operations uneconomical. In addition, at the state level, permits for air emissions may take longer to obtain, which would delay our ability to produce.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 and the notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly Report on Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

Commodity Price Risk

Our primary market risk exposure is in the prices we receive for our production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas, NGLs and oil has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the six months ended June 30, 2011, our annual income before income taxes would have decreased by approximately $1.9 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.2 million for each $1.00 per barrel decrease in crude oil prices.

We routinely enter into financial hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. These financial hedging activities are intended to support natural gas and oil prices at targeted levels that provide an acceptable rate of return and to manage our exposure to natural gas and oil price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, we have fixed the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location to mitigate against the risk of large differences between NYMEX Henry Hub and our primary sales points, CIG and NWPL. We may consider entering into hedge transactions based on a NYMEX price in the future with a volume equal to the volume for our basis only swaps, thereby effectively fixing a price for CIG or NWPL.

As of July 22, 2011, we have financial derivative instruments related to natural gas, NGLs and oil volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Commodity Hedging Activities.”

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	July – December 2011		For the year 2012		For the  year 2013		For the  year 2014
Oil (Bbls)		594,800		1,061,400		328,500		219,000
Natural Gas (MMbtu)		34,800,000		46,495,000		3,650,000		0
Natural Gas Basis (MMbtu)		3,680,000		7,320,000		0		0
Natural Gas Liquids (Gallons)		38,475,000		21,000,000		0		0

Interest Rate Risks

At June 30, 2011, we had $145.0 million outstanding under our Amended Credit Facility, which bears interest at floating rates in accordance with our Amended Credit Facility with an average outstanding debt balance of $23.6 million for the six months ended June 30, 2011. The average annual interest rate incurred on this debt for the six months ended June 30, 2011was 2.7% and a 1.0% increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2011 would have resulted in an estimated $0.6 million increase in interest expense for the six months ended June 30, 2011. At June 30, 2010, we had a zero balance outstanding under our Amended Credit Facility with an average outstanding debt balance of $4.6 million for the six months ended June 30, 2010, which bears interest at floating rates in accordance with our Amended Credit Facility. The average annual interest rate incurred on this debt for the six months ended June 30, 2010 was 2.2%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2010 would have resulted in an estimated $0.02 million increase in interest expense assuming a similar average debt level to the six months ended June 30, 2010. We also had $172.5 million principal amount of Convertible Notes and $250.0 million principal amount of Senior Notes outstanding at June 30, 2011, which have fixed cash interest rates of 5.0% and 9.875% per annum, respectively, and do not have exposure to interest rate changes.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2011.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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 effect on our financial condition or results of operations.

Item 1A. Risk Factors.

Other than as set forth below, as of the date of this filing, there have been no material changes or updates to the risk factors previously disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2010, referred to as our 2010 Annual Report. An investment in our securities involves various risks. When considering an investment in our Company, you should carefully consider all of the risk factors described in our 2010 Annual Report and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

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

Compliance with Environmental Protection Agency (“EPA”) regulations is expected to become increasingly costly and may lead to our inability to obtain permits necessary to construct and operate new facilities.

The EPA regulates the level of ozone in ambient air and is proposing lowering the allowed level of ozone. Because of intense sunlight at higher altitudes, most of the Rocky Mountain region, where we operate, has higher levels of ozone. As a result of these existing and possible more stringent standards, we may not be able to obtain permits necessary to construct and operate new facilities, or, if we obtain the permits, the added costs to comply with the requirements could substantially increase our operating expenses, which would reduce our profits or making certain operations uneconomical.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered Sales of Securities

There were no sales of unregistered equity securities during the period covered by this report.

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended June 30, 2011:

Period	Total Number of Shares (1)		Weighted Average Price Paid Per Share		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1 – 30, 2011		1,590	$	41.61		0		0
May 1 – 31, 2011		1,010		41.06		0		0
June 1 – 30, 2011		0		0		0		0
Total		2,600	$	41.40		0		0

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

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 5. Other Information.

Not applicable.

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Item 6. Exhibits.

Exhibit Number	Description of Exhibits
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]
3.2	Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 of our Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1(a)	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.1(b)	Indenture, dated March 12, 2008, between Bill Barrett Corporation and Deutsch Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.1(c)	Indenture, dated July 8, 2009, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.2(a)	Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.2(b)	First Supplemental Indenture, dated March 12, 2008, by and between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.2(c)	First Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.3(a)	Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.3(b)	Second Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K with the Commission on July 8, 2009.]
4.4	Form of Rights Agreement concerning Shareholder Rights Plan, which includes as Exhibit A thereto the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and, as Exhibit B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5	Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.6	Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit B) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Chief Financial Officer.
101	The following materials from the Bill Barrett Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language) include (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Stockholders’ Equity and Comprehensive Income, (iv) the Consolidated Statements of Cash Flows, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.*

* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these Sections.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	BILL BARRETT CORPORATION
Date: August 4, 2011	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors, Chief Executive Officer and President
		(Principal Executive Officer)

Date: August 4, 2011	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)

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