Bill Barrett (BBG) 10-Q 2012 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, 2012

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 48,180,913 shares of $0.001 par value common stock outstanding on July 20, 2012.

INDEX TO FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
	Item 1.	Consolidated Financial Statements (Unaudited)	3
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	51
	Item 4.	Controls and Procedures	52
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	53
	Item 1A.	Risk Factors	53
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	53
	Item 3.	Defaults Upon Senior Securities	53
	Item 4.	Mine Safety Disclosures	53
	Item 5.	Other Information	54
	Item 6.	Exhibits	55
SIGNATURES			57

2

PART I. FINANCIAL INFORMATION

ITEM 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30, 2012			December 31, 2011
	(in thousands, except share data)
Assets:
Current Assets:
Cash and cash equivalents	$	20,834		$	57,331
Accounts receivable, net of allowance for doubtful accounts of $976 and $848 as of June 30, 2012 and December 31, 2011, respectively		83,364			101,500
Derivative assets		84,062			77,280
Prepayments and other current assets		14,369			10,232
Total current assets		202,629			246,343
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		3,967,049			3,513,050
Unproved oil and gas properties, excluded from amortization		491,580			480,416
Furniture, equipment and other		42,937			39,168
		4,501,566			4,032,634
Accumulated depreciation, depletion, amortization and impairment		(1,801,534	)		(1,625,870	)
Total property and equipment, net		2,700,032			2,406,764
Deferred financing costs, derivative assets and other noncurrent assets		52,785			34,823
Total	$	2,955,446		$	2,687,930
Liabilities and Stockholders’ Equity: Current Liabilities:
Accounts payable and accrued liabilities	$	135,034		$	136,661
Amounts payable to oil and gas property owners		10,410			15,793
Production taxes payable		40,905			48,600
Derivative liabilities		0			2,543
Deferred income taxes		13,302			29,601
Total current liabilities		199,651			233,198
Long-term debt		1,142,317			882,240
Asset retirement obligations		70,045			68,587
Deferred income taxes		304,788			281,789
Derivatives and other noncurrent liabilities		3,263			3,278
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 48,127,182 and 47,809,903 shares issued and outstanding at June 30, 2012 and December 31, 2011, respectively, with 908,501 and 835,258 shares subject to restrictions, respectively		47			47
Additional paid-in capital		876,114			869,856
Retained earnings		332,082			292,891
Treasury stock, at cost: zero shares at June 30, 2012 and December 31, 2011		0			0
Accumulated other comprehensive income		27,139			56,044
Total stockholders’ equity		1,235,382			1,218,838
Total	$	2,955,446		$	2,687,930

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,
	2012			2011			2012			2011
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	159,490		$	194,328		$	336,532		$	366,525
Other		862			3,021			2,996			3,259
Total operating and other revenues		160,352			197,349			339,528			369,784
Operating Expenses:
Lease operating expense		19,030			14,075			37,668			27,374
Gathering, transportation and processing expense		25,862			21,338			53,214			40,674
Production tax expense		6,892			9,781			13,099			18,347
Exploration expense		4,062			697			4,501			2,048
Impairment, dry hole costs and abandonment expense		21,075			1,093			21,639			1,376
Depreciation, depletion and amortization		85,942			68,847			160,025			134,241
General and administrative expense		15,036			14,757			33,476			32,453
Total operating expenses		177,899			130,588			323,622			256,513
Operating Income (Loss)		(17,547	)		66,761			15,906			113,271
Other Income and Expense:
Interest and other income		113			102			75			165
Interest expense		(23,912	)		(12,321	)		(45,502	)		(24,363	)
Commodity derivative gain (loss)		47,024			(2,907	)		91,771			(14,019	)
Gain on extinguishment of debt		0			0			1,601			0
Total other income and expense		23,225			(15,126	)		47,945			(38,217	)
Income before Income Taxes		5,678			51,635			63,851			75,054
Provision for Income Taxes		2,380			18,999			24,660			27,203
Net Income	$	3,298		$	32,636		$	39,191		$	47,851
Net Income Per Common Share, Basic	$	0.07		$	0.70		$	0.83		$	1.03
Net Income Per Common Share, Diluted	$	0.07		$	0.69		$	0.83		$	1.02
Weighted Average Common Shares Outstanding, Basic		47,201,954			46,415,832			47,143,430			46,255,121
Weighted Average Common Shares Outstanding, Diluted		47,245,167			47,108,063			47,334,507			46,929,015

See notes to Unaudited Consolidated Financial Statements.

4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
	(in thousands)
Net income	$	3,298		$	32,636	$	39,191		$	47,851
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		(12,997	)		5,474		(28,905	)		(17,839	)
Other comprehensive income (loss)		(12,997	)		5,474		(28,905	)		(17,839	)
Comprehensive Income (Loss)	$	(9,699	)	$	38,110	$	10,286		$	30,012

See notes to Unaudited Consolidated Financial Statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)

(In thousands)

	Common Stock		Additional Paid-In Capital			Retained Earnings		Treasury Stock			Accumulated Other Comprehensive Income			Total Stockholders’ Equity
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		22,838			0		(4,436	)		0			18,403
Stock-based compensation		0		20,551			0		0			0			20,551
Retirement of treasury stock		0		(4,436	)		0		4,436			0			0
Net income		0		0			30,707		0			0			30,707
Effect of derivative financial instruments, net of $4,886 of taxes		0		0			0		0			8,215			8,215
Balance — December 31, 2011	$	47	$	869,856		$	292,891	$	0		$	56,044		$	1,218,838
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	$	0	$	668		$	0	$	(2,323	)	$	0		$	(1,655	)
Stock-based compensation		0		8,912			0		0			0			8,912
Retirement of treasury stock		0		(2,323	)		0		2,323			0			0
Settlement of convertible notes		0		(999	)		0		0			0			(999	)
Net income		0		0			39,191		0			0			39,191
Effect of derivative financial instruments, net of $17,358 of taxes		0		0			0		0			(28,905	)		(28,905	)
Balance —June 30, 2012	$	47	$	876,114		$	332,082	$	0		$	27,139		$	1,235,382

See notes to Unaudited Consolidated Financial Statements.

6

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2012			2011
	(in thousands)
Operating Activities:
Net income	$	39,191		$	47,851
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		160,025			134,241
Deferred income taxes		24,660			27,203
Impairment, dry hole costs and abandonment expense		21,639			1,376
Unrealized derivative (gain) loss		(69,052	)		25
Stock compensation and other non-cash charges		7,640			10,345
Amortization of debt discounts and deferred financing costs		5,002			6,420
Gain on sale of properties		0			(2,009	)
Change in operating assets and liabilities:
Accounts receivable		18,136			(22,114	)
Prepayments and other assets		(6,066	)		2,069
Accounts payable, accrued and other liabilities		(8,853	)		(3,314	)
Amounts payable to oil and gas property owners		(5,383	)		7,461
Production taxes payable		(7,695	)		1,685
Net cash provided by operating activities		179,244			211,239
Investing Activities:
Additions to oil and gas properties, including acquisitions		(460,059	)		(383,802	)
Additions of furniture, equipment and other		(4,241	)		(2,772	)
Proceeds from sale of properties and other investing activities		134			1,860
Net cash used in investing activities		(464,166	)		(384,714	)
Financing Activities:
Proceeds from debt		525,000			145,000
Principal payments on debt		(267,156	)		0
Proceeds from stock option exercises		668			13,078
Deferred financing costs and other		(10,087	)		(3,437	)
Net cash provided by financing activities		248,425			154,641
Decrease in Cash and Cash Equivalents		(36,497	)		(18,384	)
Beginning Cash and Cash Equivalents		57,331			58,690
Ending Cash and Cash Equivalents	$	20,834		$	39,856

See notes to Unaudited Consolidated Financial Statements.

7

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

June 30, 2012

1. Organization

Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the “Company”) is an independent oil and gas company engaged in the exploration, development and production of crude oil and natural gas. 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, 2012, the Company’s results of operations for the three and six months ended June 30, 2012 and 2011 and cash flows for the six months ended June 30, 2012 and 2011. Operating results for the three and six months ended June 30, 2012 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 oil and natural gas, 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, 2011 previously filed with the SEC.

Use of Estimates. In the course of preparing the Company’s financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure 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.

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 oil and natural gas 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 asset retirement obligations, the timing of dry hole costs, impairments of undeveloped properties, valuing deferred tax assets, and estimating fair values of derivative instruments and stock-based payment awards.

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

Oil and Gas Properties. The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized. The costs of development wells are capitalized whether proved reserves are added or not. Oil and gas lease acquisition costs also are 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 8.8% and 9.0% for the three and six months ended June 30, 2012, respectively, and 11.3% and 11.8% for the three and six months ended June 30, 2011, respectively, which include interest, amortization of discounts and deferred financing fees on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“9.875% Senior Notes”), its 7.625% Senior Notes due 2019 (“7.625% Senior Notes”), its 7.0% Senior Notes due 2022 (“7.0% Senior Notes”), and its credit facility (the “Amended Credit Facility”). The Company capitalized interest costs of $0.1 million and $0.2 million for the three and six months ended June 30, 2012, respectively, and $0.5 million and $1.0 million for the three and six months ended June 30, 2011, respectively.

8

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 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 or 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.

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 oil and natural gas producing activities:

	As of June 30,  2012			As of December 31, 2011
	(in thousands)
Proved properties	$	635,488		$	599,619
Wells and related equipment and facilities		3,025,078			2,636,424
Support equipment and facilities		293,174			259,672
Materials and supplies		13,309			17,335
Total proved oil and gas properties	$	3,967,049		$	3,513,050
Unproved properties		351,607			339,210
Wells and facilities in progress		139,973			141,206
Total unproved oil and gas properties, excluded from amortization	$	491,580		$	480,416
Accumulated depreciation, depletion, amortization and impairment		(1,784,153	)		(1,610,271	)
Total oil and gas properties, net	$	2,674,476		$	2,383,195

Net changes in capitalized exploratory well costs for the six months ended June 30, 2012, are reflected in the following table (in thousands):

December 31, 2011	$	0
Additions to capitalized exploratory well costs pending the determination of proved reserves		8,694
Reclassifications of wells, facilities and equipment based on the determination of proved reserves		0
Exploratory well costs charged to dry hole costs and abandonment expense		0
June 30, 2012	$	8,694

All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. As of June 30, 2012, there were no exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling.

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 value of a property exceeds the undiscounted future cash flows, the Company may impair the carrying value to fair value based on an analysis of quantitative and qualitative factors.

9

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, 2012 and June 30, 2011, the Company did not recognize any non-cash impairment charges related to its proved oil and gas properties.

The Company assesses individually significant unproved properties for impairment on a quarterly basis and will recognize a loss where circumstances indicate impairment in value. For the three and six months ended June 30, 2012, the Company recorded a non-cash impairment charge of $18.3 million related to certain unproved oil and gas properties within various exploration and development projects primarily as a result of unfavorable market conditions or no plans to evaluate the remaining acreage.

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 Mcfe. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration by this calculation.

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

	June 30, 2012		December 31, 2011
	(in thousands)
Accrued drilling, completion and facility costs	$	73,092	$	66,809
Accrued lease operating, gathering, transportation and processing expenses		19,225		17,711
Accrued general and administrative expenses		5,996		11,052
Trade payables and other		36,721		41,089
Total accounts payable and accrued liabilities	$	135,034	$	136,661

Comprehensive Income (Loss). Comprehensive income (loss) consists of net income and the effective component of derivative instruments classified as cash flow hedges. The total of comprehensive income, including the components of net income and the components of other comprehensive income, are presented in the Unaudited Consolidated Statements of Comprehensive Income (Loss).

Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas, and natural gas liquid (“NGL”) sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and included in the Unaudited Consolidated Balance Sheets as assets or liabilities.

Effective January 1, 2012, the Company elected to discontinue hedge accounting prospectively. Consequently, as of January 1, 2012, the Company no longer designates any hedges as cash flow hedges and the Company elected to de-designate all commodity hedge instruments that were previously designated as cash flow hedges as of December 31, 2011. The election to de-designate commodity hedges did not impact the Company’s reported cash flows, did not affect the economic substance of these transactions and changes only how these transactions are reported in the Unaudited Consolidated Financial Statements. As a result of discontinuing hedge accounting effective January 1, 2012, the mark-to-market value of all commodity hedge instruments within accumulated other comprehensive income (“AOCI”) at December 31, 2011 was frozen in AOCI as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions affect earnings.

The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Before it discontinued cash flow hedge accounting effective January 1, 2012, the Company was required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

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

10

Currently, the Company’s financial derivative instruments are marked to market with the resulting changes in fair value recorded in earnings. For additional discussion of derivatives, see Note 9. As a result of its election to discontinue cash flow hedge accounting effective January 1, 2012, the Company reclassified the commodity derivative gain (loss) line item within the Unaudited Consolidated Statements of Operations from operating and other revenues to other income and expenses, due to the change in the composition of the commodity derivative gain (loss) line item, to include prospective fair value changes of hedge instruments.

New Accounting Pronouncements. In May 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-04,Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, which amended FASB Accounting Standards Codification (“ASC”) Topic 820,Fair Value Measurement. The objective of this update is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments are not expected to have a significant impact on companies applying GAAP. This provision is effective for interim and annual periods beginning after December 15, 2011. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

In June 2011, the FASB issued Accounting Standards Update 2011-05,Presentation of Comprehensive Income, which amended FASB ASC Topic 220, Comprehensive Income. The intent of this update is 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 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. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

In December 2011, the FASB issued Accounting Standards Update 2011-12,Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The intent of this update is to indefinitely defer certain provisions of ASU 2011-05Presentation of Comprehensive Income, which require entities to present reclassification adjustments by component in both the statement where net income is presented and the statement where other comprehensive income is presented for both interim and annual financial statements.

3. Earnings Per Share

Basic net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding during each period. Non-vested equity shares of common stock are included in the computation of basic net income per common share only after the shares become fully vested. Diluted net income per common share 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 common 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.

On March 20, 2012, approximately 85% of the holders of the Company’s Convertible Notes, having an aggregate fair value of $147.2 million, exercised their right to require the Company to purchase their notes, leaving $25.3 million in principal outstanding. As of June 30, 2012, the Company expected to settle the remaining Convertible Notes in cash. Therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that remaining conversion feature. The Company has the right with at least 30 days’ notice to call the Convertible Notes, and the holders have the right to require the Company to purchase the notes on each of March 20, 2015, March 20, 2018 and March 20, 2023. The Convertible Notes have not been dilutive since their issuance in March 2008, and therefore, did not impact the diluted net income per common share calculation for the three and six months ended June 30, 2012 and 2011, respectively. The diluted net income per share calculation excludes the anti-dilutive effect of 3,771,662 and 125,575 shares underlying stock options and nonvested performance-based equity shares of common stock for the three months ended June 30, 2012 and 2011, respectively, and 2,896,452 and 196,646 shares underlying stock options and nonvested performance-based equity shares of common stock for the six months ended June 30, 2012 and 2011, respectively.

11

The following table sets forth the calculation of basic and diluted earnings per share, in thousands except per share amounts:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Net income	$	3,298	$	32,636	$	39,191	$	47,851
Basic weighted-average common shares outstanding in period		47,202		46,416		47,143		46,255
Add dilutive effects of stock options and nonvested equity shares of common stock		43		692		192		674
Diluted weighted-average common shares outstanding in period		47,245		47,108		47,335		46,929
Basic income per common share	$	0.07	$	0.70	$	0.83	$	1.03
Diluted income per common share	$	0.07	$	0.69	$	0.83	$	1.02

4. Supplemental Disclosures of Cash Flow Information

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

	Six Months Ended June 30,
	2012			2011
Cash paid for interest, net of amount capitalized	$	34,656		$	16,890
Cash paid for income taxes, net of refunds (received)		8			(7,504	)
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities that are reflected in investing activities		75,112			60,081
Net increase (decrease) in asset retirement obligations		(545	)		3,535
Treasury stock acquired from employee stock option exercises		0			100
Retirement of treasury stock		(2,323	)		(3,516	)

5. Acquisitions and Dispositions

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 $116.8 million. As of June 30, 2012, the final purchase price allocation was as follows (in thousands):

Consideration given:
Cash	$	116,790
Total consideration given	$	116,790

Amounts recognized for final fair value of assets acquired and liabilities assumed:

Proved property	$	76,234
Unproved property		44,027
Asset retirement obligation		(2,054	)
Liabilities assumed		(3,880	)
Other assets acquired		2,463
Total fair value of oil and gas properties acquired	$	116,790

On August 16, 2011, the Company completed an acquisition, from an unrelated party, of oil and gas properties and related assets in the Denver-Julesburg Basin (“DJ Basin Acquisition”) located in northeastern Colorado and southeastern Wyoming. Total consideration given was approximately $145.6 million in cash. As of June 30, 2012, the final purchase price allocation was as follows (in thousands):

Consideration given:
Cash	$	145,636
Total consideration given	$	145,636

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Amounts recognized for final fair value of assets acquired and liabilities assumed:

Proved property	$	93,110
Unproved property		61,891
Asset retirement obligation		(7,670	)
Liabilities assumed		(1,695	)
Total fair value of oil and gas properties acquired	$	145,636

The East Bluebell Acquisition and the DJ Basin Acquisition qualified as business combinations and, as such, the Company estimated the fair value of each property as of the respective acquisition dates, June 8, 2011 and August 16, 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 and gas futures prices as of each acquisition date and adjusted for estimated location and quality differentials as well as related transportation costs;

• Estimated future production rates; and

• Estimated timing and amounts of future operating and development costs.

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 businesses because the impact of the acquisitions was not material to the results of operations for the three and six months ended June 30, 2011 and 2012. The results of operations from the East Bluebell Acquisition are included in the Unaudited Consolidated Financial Statements from the acquisition date of June 8, 2011. Revenue and net income related to the East Bluebell Acquisition that was included in the Unaudited Consolidated Statements of Operations is summarized below (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
Revenue	$	4,896	$	583		$	8,900	$	583
Net Income (loss)		1,487		(23	)		2,414		(23	)

The results of operations from the DJ Basin Acquisition are included in the Unaudited Consolidated Financial Statements from the acquisition date of August 16, 2011. Revenue and net income related to the DJ Basin Acquisition that was included in the Unaudited Consolidated Statements of Operations is summarized below (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Revenue	$	9,223	$	0	$	15,176	$	0
Net Income		1,886		0		3,428		0

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6. Long-Term Debt

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

		As of June 30, 2012								As of December 31, 2011
	Maturity Date	Principal			Unamortized Discount			Carrying Amount		Principal		Unamortized Discount			Carrying Amount
Amended Credit Facility(1)	October 31, 2016	$	75,000		$	0		$	75,000	$	70,000	$	0		$	70,000
9.875% Senior Notes(2)	July 15, 2016		250,000			(8,027	)		241,973		250,000		(8,802	)		241,198
Convertible Notes(3)	March 15, 2028 (4)		25,344	(7)		0			25,344		172,500		(1,458	)		171,042
7.625% Senior Notes(5)	October 1, 2019		400,000			0			400,000		400,000		0			400,000
7.0% Senior Notes(6)	October 15, 2022		400,000			0			400,000		0		0			0
Total Long-Term Debt		$	1,150,344		$	(8,027	)	$	1,142,317	$	892,500	$	(10,260	)	$	882,240

(1) The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure.

(2) The aggregate estimated fair value of the 9.875% Senior Notes was approximately $274.7 million as of June 30, 2012 based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the Convertible Notes was approximately $23.6 million as of June 30, 2012. 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.

(4) The Company has the right with at least 30 days’ notice to call the Convertible Notes, and the holders have the right to require the Company to purchase the notes on each of March 20, 2015, March 20, 2018 and March 20, 2023.

(5) The aggregate estimated fair value of the 7.625% Senior Notes was approximately $400.0 million as of June 30, 2012 based on reported market trades of these instruments.

(6) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $380.5 million as of June 30, 2012 based on reported market trades of these instruments.

(7) Balance represents the remaining principal amount of the Convertible Notes after the Company’s redemption of $147.2 million principal amount of Convertible Notes on March 20, 2012.

The Company’s outstanding long-term debt instruments are reported at fair value based on trades on a non-regulated market, which represent Level 2 inputs.

Amended Credit Facility

On October 18, 2011, the Company amended its Amended Credit Facility to extend the maturity date to October 31, 2016. The Amended Credit Facility has commitments of $900.0 million and had a borrowing base of $1.1 billion based upon June 30, 2011 proved reserves, hedge position and senior debt outstanding. The interest margin is LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee ranges from 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 1.7% and 2.7% for the three months ended June 30, 2012 and June 30, 2011, respectively. The average annual interest rates incurred on the Amended Credit Facility were 1.8% and 2.7% for the six months ended June 30, 2012 and June 30, 2011, respectively. As of June 30, 2012, the Company had a balance of $75.0 million outstanding under the Amended Credit Facility.

The borrowing base is required to be re-determined twice per year. The borrowing base was re-determined on May 1, 2012 with a borrowing base of $900.0 million and commitments of $900.0 million based on December 31, 2011 proved reserves, hedge position, senior debt outstanding and lender commodity price benchmarks. Future borrowing bases will be computed based on proved oil and natural gas reserves, hedge position and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company. The Amended Credit Facility is secured by oil and natural gas 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 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 reduces the current borrowing capacity of the Amended Credit Facility by $26.0 million to $874.0 million.

9.875% Senior Notes Due 2016

The 9.875% Senior Notes have an aggregate principal amount of $250.0 million, 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. The

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9.875% Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 each year. The 9.875% Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The 9.875% 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 currently is in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

5% Convertible Senior Notes Due 2028

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. As of January 1, 2009 with the adoption of new authoritative accounting guidance under FASB ASC subtopic 470-20,Debt with Conversion Options, the Company recorded a debt discount of $23.1 million, which represented the fair value of the equity conversion feature as of the date of the issuance of the Convertible Notes. The value of the equity conversion feature was also recorded as APIC, net of $8.6 million of deferred taxes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. The Company settled the notes in cash and recognized a gain on extinguishment of $1.6 million after completing a fair value analysis of the cash consideration transferred to holders of the Convertible Notes compared to the fair value of the Convertible Notes that were redeemed. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. 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, are senior in right of payment to all of the Company’s future subordinated indebtedness, and are effectively subordinated to all of the Company’s secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company’s subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the 9.875% Senior Notes, the 7.625% Senior Notes and the 7.0% Senior Notes.

The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company has the right with at least 30 days’ notice to call the Convertible Notes.

For the remainder of the Convertible Notes outstanding, the conversion price is approximately $66.33 per share of the Company’s common stock, equal to the applicable conversion rate of 15.0761 shares of common stock, subject to adjustment, for each $1,000 of the principal amount of the Convertible Notes. Upon conversion of the Convertible Notes, holders will receive, at the Company’s election, cash, shares of common stock or a combination of cash and shares of common stock. If the conversion value exceeds $1,000, the Company will also deliver, at its election, cash, shares of common stock or a combination of cash and shares of common stock with respect to the remaining value deliverable upon conversion.

7.625% Senior Notes Due 2019

The 7.625% Senior Notes have an aggregate principal amount of $400.0 million and 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. The 7.625% Senior Notes will mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The 7.625% 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.

7.0% Senior Notes Due 2022

On March 12, 2012, the Company issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes will mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year beginning October 15, 2012. The Company received the net proceeds of $392.0 million (net of related offering costs), which were used to repay the outstanding balance under the Amended Credit Facility, settle the Convertible Notes that were redeemed by the Company and for general corporate purposes. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes, the 9.875% Senior Notes and the 7.625% Senior Notes. The 7.0% 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 since issuance.

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The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, 9.875% Senior Notes, 7.625% Senior Notes, 7.0% 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,
	2012		2011		2012		2011
Amended Credit Facility(1)
Cash interest	$	1,106	$	1,253	$	2,254	$	2,234
Non-cash interest	$	586	$	780	$	1,171	$	1,559
9.875% Senior Notes(2)
Cash interest	$	6,172	$	6,172	$	12,344	$	12,344
Non-cash interest	$	636	$	611	$	1,253	$	1,219
Convertible Notes(3)
Cash interest	$	370	$	2,156	$	2,269	$	4,313
Non-cash interest	$	1	$	1,858	$	1,769	$	3,641
7.625% Senior Notes(4)
Cash interest	$	7,625	$	0	$	15,250	$	0
Non-cash interest	$	260	$	0	$	541	$	0
7.0% Senior Notes(5)
Cash interest	$	7,000	$	0	$	8,397	$	0
Non-cash interest	$	201	$	0	$	267	$	0

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

(2) The stated interest rate for the 9.875% 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. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represented the fair value of the equity conversion feature at the time of issue. The stated interest rate of 5% on the Convertible Notes will be the effective interest rate of the $25.3 million remaining principal balance, as the related debt discount was fully amortized as of March 31, 2012.

(4) The stated interest rate for the 7.625% Senior Notes is 7.625% per annum with an effective interest rate of 7.9% per annum.

(5) The stated interest rate for the 7.0% Senior Notes is 7.0% per annum with an effective interest rate of 7.2% per annum. The cash interest will be paid with the first interest payment due on October 15, 2012.

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 discount 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 DD&A expense in the Unaudited Consolidated Statements of Operations.

A reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2012 is as follows (in thousands):

December 31, 2011	$	69,302
Liabilities incurred		1,950
Liabilities settled		(2,679	)
Accretion expense		2,378
Revisions to estimate		170
June 30, 2012	$	71,121
Less: current asset retirement obligations		1,076
Long-term asset retirement obligations	$	70,045

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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, as discussed in Note 6, 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.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Given the Company’s historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally unobservable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities as of June 30, 2012 and December 31, 2011 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, 2012
	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	672	$	0		$	0	$	672
Cash Equivalents - Money Market Funds		53		0			0		53
Commodity Derivatives		0		111,132			0		111,132
Liabilities
Commodity Derivatives	$	0	$	(5,073	)	$	0	$	(5,073	)

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As of December 31, 2011
	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	579	$	0		$	0	$	579
Cash Equivalents - Money Market Funds		52,164		0			0		52,164
Commodity Derivatives		0		94,385			0		94,385
Liabilities
Commodity Derivatives	$	0	$	(11,116	)	$	0	$	(11,116	)

The fair values of derivative instruments 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. The Company also has highly liquid short term investments in money market funds. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs. The money market fund investments are recorded at carrying value, which approximates fair value, which represent Level 1 inputs.

Level 2 Fair Value Measurements – The fair value of the crude oil and natural gas 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, 2012, and for the six months ended June 30, 2012, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy.

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 and the DJ Basin Acquisition. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. The final fair values of these items were primarily determined using the present value of estimated future cash inflows and outflows. Because of the unobservable nature of these inputs, they are classified within Level 3. See Note 5 for additional discussion of the East Bluebell Acquisition and the DJ Basin Acquisition and disclosure of the inputs used to determine the final 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.

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In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of natural gas that have varying terms and 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 the dates indicated. As a result of its election to discontinue cash flow hedge accounting effective January 1, 2012, the Company did not have any derivatives designated as cash flow hedging instruments at June 30, 2012. See Note 2.

Derivatives Not Designated as Cash Flow Hedging Instruments

As of June 30, 2012
Derivative Assets				Derivative Liabilities
Balance Sheet	Fair Value			Balance Sheet	Fair Value
(in thousands)
Current: Derivative assets	$	88,485		Current: Derivative assets(4)	$	(4,423	)
Deferred financing costs, derivative assets and other noncurrent assets(2)		22,485		Deferred financing costs, derivative assets and other noncurrent assets(2)(4)		(429	)
Derivatives and other noncurrent liabilities(1)(3)		162		Derivatives and other noncurrent liabilities(3)		(221	)
Total derivative assets not designated as cash flow hedging instruments	$	111,132		Total derivative liabilities not designated as cash flow hedging instruments	$	(5,073	)
As of December 31, 2011
Derivative Assets				Derivative Liabilities
Balance Sheet	Fair Value			Balance Sheet	Fair Value
(in thousands)
Current: Derivative assets	$	2,589		Current: Derivative assets(4)	$	(4,552	)
Current: Derivative liabilities(1)		95		Current: Derivative liabilities		(4,044	)
Total derivative assets not designated as cash flow hedging instruments	$	2,684		Total derivative liabilities not designated as cash flow hedging instruments	$	(8,596	)
Derivatives Designated as Cash Flow Hedging Instruments
As of December 31, 2011
Derivative Assets				Derivative Liabilities
Balance Sheet	Fair Value			Balance Sheet	Fair Value
(in thousands)
Current: Derivative assets	$	80,653		Current: Derivative assets(4)	$	(1,410	)
Current: Derivative liabilities(1)		1,984		Current: Derivative liabilities		(578	)
Deferred financing costs and other noncurrent assets(2)		9,064		Deferred financing costs and other noncurrent assets(2)(4)		(162	)
Derivatives and other noncurrent liabilities (1)(3)		(315	)	Derivatives and other noncurrent liabilities (3)		(55	)
Total derivative assets designated as cash flow hedging instruments	$	91,386		Total derivative liabilities designated as cash flow hedging instruments	$	(2,205	)

(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 Sheet.

(2) As of June 30, 2012 and December 31, 2011, this line item on the Unaudited Consolidated Balance Sheets includes $30.7 million and $25.9 million of deferred financing costs and other noncurrent assets, respectively.

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(3) As of June 30, 2012 and December 31, 2011, this line item on the Unaudited Consolidated Balance Sheets also includes $3.2 million and $2.9 million of other noncurrent liabilities.

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

The Company elected to discontinue hedge accounting effective January 1, 2012. Therefore, the Commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations was comprised of changes in the derivative’s fair value for all discontinued cash flow hedges. As a result of discontinuing hedge accounting effective January 1, 2012, the mark-to-market value of all commodity hedge instruments within AOCI at December 31, 2011 was frozen in AOCI as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions affect earnings.

The following table summarizes the cash flow hedge gains and losses, net of tax, and their locations on the Unaudited Consolidated Balance Sheets and Unaudited Consolidated Statements of Operations as of the periods indicated:

	Derivatives Qualifying as Cash Flow Hedges	Three Months Ended June 30,				Six Months Ended June 30,
		2012		2011		2012		2011
		(in thousands)				(in thousands)
Amount of gain recognized in AOCI (net of tax)	Commodity Hedges	$	0	$	17,840	$	0	$	11,987
Amount of gain reclassified from AOCI into income (net of tax)	Commodity Hedges(1)		12,997		12,366		28,905		29,826
Amount of gain recognized in income on ineffective hedges	Commodity Hedges		0		888		0		1,050

(1) Gains and losses reclassified from AOCI into income as well as gains and losses on ineffective hedges are located on the oil and gas production revenues and the commodity derivative gain (loss) line item, respectively, in the Unaudited Consolidated Statements of Operations.

Some of the Company’s commodity derivative instruments did 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 did not qualify or was not designated as a cash flow hedge, the change in the fair value of the derivative was 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 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.

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 risk 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 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 cash flow hedge accounting for the periods indicated:

	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended June 30,					Six Months Ended June 30,
		2012		2011			2012		2011
		(in thousands)					(in thousands)
Amount of gain (loss) recognized in income on derivatives	Commodity derivative gain (loss)	$	47,024	$	(3,795	)	$	91,771	$	(15,069	)

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As of June 30, 2012, the Company had financial instruments in place to hedge the following volumes for the periods indicated:

	July – December 2012		For the year 2013		For the year 2014
Oil (Bbls)		975,200		1,679,000		438,000
Natural Gas (MMbtu)		34,190,000		48,455,000		16,425,000
Natural Gas Basis (MMbtu)		3,680,000		0		0
Natural Gas Liquids (Gallons)		15,000,000		9,000,000		0

As a result of the settlement of various oil swap and collar contracts, the Company received $3.8 million and $3.1 million for oil contracts that settled during the three and six months ended June 30, 2012, respectively, and paid $2.3 million and $3.1 million during the three and six months ended June 30, 2011. As a result of the settlement of various natural gas swap and collar contracts (including basis and NGL swaps), the Company also received $35.9 million and $65.9 million during the three and six months ended June 30, 2012, respectively, and $13.5 million and $36.8 million during the three and six months ended June 30, 2011, respectively.

The table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil, natural gas NGL and basis derivative instruments for the periods indicated:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	(in thousands)
Realized gain on derivatives designated as cash flow hedges(1)	$	20,798	$	19,776		$	46,263	$	47,699
Realized gain (loss) on derivatives not designated as cash flow hedges(2)	$	18,916	$	(8,590	)	$	22,719	$	(13,994	)
Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges(2)		0		888			0		1,050
Unrealized gain (loss) on derivatives not designated as cash flow hedges(2)		28,108		4,795			69,052		(1,075	)
Total commodity derivative gain (loss)	$	47,024	$	(2,907	)	$	91,771	$	(14,019	)

(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 11 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.

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. Two counterparties that were lenders in the Amended Credit Facility withdrew from the facility when the Company amended the facility in October 2011. The Company will continue to monitor the credit worthiness of these two counterparties during the remaining duration of the derivatives that were entered into while they were 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. (“ISDA”) Master Agreement 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 in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed the Company under derivative contracts. Where the counterparty is not a lender under the Company’s Amended Credit Facility, the Company may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility and even if the relevant agreement provides for it.

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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 three and six months ended June 30, 2012, there was no change to the Company’s liability for uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest 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, 2012.

Income tax expense for the three and six months ended June 30, 2012 and 2011 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 not deductible for income tax purposes.

11. Stockholders’ Equity

The Company’s authorized capital structure consists of 75,000,000 shares of preferred stock, par value $0.001 per share and 150,000,000 shares of common stock, par value $0.001 per share. 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, 2012, all treasury stock held by the Company was retired.

12. Accumulated Other Comprehensive Income.

The components of AOCI and related tax effects for the three and six months ended June 30, 2012 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—March 31, 2012	$	64,249		$	(24,113	)	$	40,136
Reclassification adjustment for realized gains on hedges included in net income		(20,798	)		7,801			(12,997	)
Accumulated other comprehensive income—June 30, 2012	$	43,451		$	(16,312	)	$	27,139

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2011	$	89,714		$	(33,670	)	$	56,044
Reclassification adjustment for realized gains on hedges included in net income		(46,263	)		17,358			(28,905	)
Accumulated other comprehensive income—June 30, 2012	$	43,451		$	(16,312	)	$	27,139

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).

In May 2012, the Company’s stockholders approved and the Company adopted its 2012 Equity Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan replaces the 2002 Stock Option Plan, 2003 Stock Option Plan, 2004 Stock Incentive Plan, and 2008 Stock Incentive Plan (the “Prior Plans”). No new grants will be made under the Prior Plans. The purpose of the 2012 Incentive Plan is to enhance the Company’s ability to attract and retain officers, employees, directors and consultants and to provide

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such persons with an interest in the Company aligned with the interests of stockholders. The 2012 Incentive Plan provides for the grant of stock options (including incentive stock options and non-qualified stock options) and other awards (including performance units, performance shares, share awards, share units, restricted stock, cash incentive, and stock appreciation rights or SARs).

The aggregate number of shares that the Company may issue under the 2012 Incentive Plan may not exceed 1,500,000 shares of the Company’s common stock plus any shares remaining for future grants under the Prior Plans, for a total of 2,051,402 shares available under the 2012 Incentive Plan on the date of adoption, subject to adjustment for future stock splits, stock dividends and similar changes in the Company’s capitalization. The aggregate number of shares of common stock subject to options, stock appreciation rights, or performance awards granted to a participant during any calendar year may not exceed 500,000 shares, and the maximum amount payable to a participant during any calendar year with respect to performance or cash incentive awards that are not denominated in common stock or common stock equivalents may not exceed $5.0 million. The 2012 Incentive Plan provides that all awards granted under the 2012 Incentive Plan expire not more than ten years from the grant date and have an exercise price of no less than the closing price of the Company’s common stock on the date of grant.

The following table presents the non-cash stock-based compensation related to equity awards for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Common stock options	$	1,573	$	1,741	$	3,673	$	3,909
Nonvested equity common stock		1,797		2,139		3,774		4,199
Nonvested performance-based equity		388		479		803		843
Total non-cash stock-based compensation	$	3,758	$	4,359	$	8,250	$	8,951

Unrecognized compensation cost as of June 30, 2012 was $29.1 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. The following tables present the equity awards granted during the periods indicated pursuant to the Company’s various stock compensation plans:

	Three Months Ended June 30, 2012				Three 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		9,576	$	23.47		15,000	$	44.57
	Six Months Ended June 30, 2012				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		555,682	$	27.49		262,824	$	39.34

Nonvested Equity Shares. The following tables present the equity awards granted during the periods indicated pursuant to the Company’s various stock compensation plans:

	Three Months Ended June 30, 2012				Three 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		24,617	$	23.54		28,859	$	41.57
Nonvested performance-based equity shares		4,221	$	23.58		0		—
Total shares granted		28,838				28,859

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	Six Months Ended June 30, 2012				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		229,114	$	26.67		316,461	$	39.23
Nonvested performance-based equity shares		176,587	$	27.65		5,960	$	39.88
Total shares granted		405,701				322,421

Performance Share Programs.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 were set aside for this program under the 2008 Incentive Plan. 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.

Based on Company performance in 2010, 25.9% of the performance shares vested in February 2011, and the Company recognized $0.0 and $0.2 million of compensation expense related to these awards for the three and six months ended June 30, 2011. Based upon the Company’s performance in 2011, 26.6% of the performance shares vested in February 2012, and the Company recognized $0.0 and $0.2 million of compensation expense related to these awards for the three and six months ended June 30, 2012.

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 expense 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 expense is recognized and any previously recognized compensation expense is reversed.

In March 2012, the Compensation Committee approved the performance metrics used to measure potential vesting of the performance shares in the 2010 Program based on 2012 performance. For the year ending December 31, 2012, the performance goals consist of increases to oil and natural gas proved reserves (weighted at 25%), increases to oil and natural gas proved, probable and possible reserves (weighted at 25%), increases to the Company’s present value (at a 10% annual discount) of future net cash flows from proved reserves (weighted at 25%), and a discretionary cash flow metric (weighted at 25%). In March 2012, 95,925 performance-based nonvested equity shares of common stock in the 2010 Program were subject to the new grant date, and the fair value was remeasured at the grant date. During the three months ended June 30, 2012, the Company granted an additional 149 performance-based equity shares. All remaining unvested shares could potentially vest if all performance goals are met at the stretch level. As of March 31, 2012, the Company estimated 18.75% of the performance shares would vest in February 2013; however, based on new estimates during the three months ended June 30, 2012, the Company estimated that 0% of the performance shares will vest in February 2013. Therefore, the Company reversed the $0.1 million of non-cash stock-based compensation expense related to the three months ended March 31, 2012 during the three months ended June 30, 2012.

In March 2012, the Compensation Committee also modified the vesting terms of the Company’s nonvested equity awards in the 2010 Program 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. In March 2012, 25,266 market-based nonvested equity shares of common stock were subject to the new grant date, and the fair value was remeasured at the grant date. During the three months ended June 30, 2012, the Company granted an additional 40 market-based nonvested equity shares. The fair value of the market-based awards is amortized ratably over the remaining 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 $0.2 million of non-cash stock-based compensation expense attributable to these awards for the three and six months ended June 30, 2012.

In March 2012, the Compensation Committee approved a new performance share program (the “2012 Program”) pursuant to the 2008 Incentive Plan. The performance-based awards contingently vest in May 2015, depending on the level at which the performance goals are achieved. The performance goals, which will be measured over the three year period ending December 31, 2014, consist of the Company’s TSR ranking relative to a defined peer group’s individual TSR (weighted at 33%), the percentage change in

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discretionary cash flow per debt adjusted share relative to a defined peer group’s percentage calculation (weighted at 33%) and percentage change in proved oil and natural gas reserves per debt adjusted share (weighted at 33%). Fifty percent of the total award will vest for performance met at the threshold level, 100% will vest at the target level and 200% will vest at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of shares will be adjusted on a prorated basis of the actual results compared to the threshold, target and stretch goals. If the threshold 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 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that have not vested will be forfeited. A total of 172,366 shares were granted under this program in March 2012 and an additional 4,032 shares were granted during the three months ended June 30, 2012. All compensation expense related to the TSR metric will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. All compensation expense related to the discretionary cash flow metric and the proved oil and natural gas reserves metric will be based upon the number of shares expected to vest at the end of the three year period. The Company recognized $0.3 million and $0.4 million of non-cash stock-based compensation expense associated with these shares for the three and six months ended June 30, 2012.

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 or 2012 Incentive Plan. After each quarter, shares of common stock with a value equal to the fees payable for that quarter, calculated using the closing price on the last trading day before the end of the quarter, will be delivered to each outside director who elected before that quarter to receive shares for payment of director fees. Beginning July 1, 2012, restricted stock units under the 2012 Incentive Plan will be issued rather than shares of common stock. These restricted stock units will be settled in shares of common stock at the end of the applicable quarter or such later date elected by the director. The following table summarizes, for the periods indicated, 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,
	2012		2011		2012		2011
Director fees (shares)		1,657		2,187		3,175		4,978
Stock-based compensation (in thousands)	$	36	$	101	$	75	$	213

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 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 $0.4 million and $1.2 million for the three and six months ended June 30, 2012, respectively, and $0.3 million and $1.0 million for the three and six months ended June 30, 2011, 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, and 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, 2011 and six months ended June 30, 2012 and the Company’s ending deferred compensation liability as of June 30, 2012 (in thousands):

Beginning deferred compensation liability balance – January 1, 2011	$	260
Employee contributions		183
Company matching contributions		175
Distributions		(34	)
Participant losses		(5	)
Ending deferred compensation liability balance – December 31, 2011	$	579
Employee contributions		108
Company matching contributions		82
Distributions		(117	)
Participant earnings		21
Ending deferred compensation liability balance – June 30, 2012	$	673
Amount to be paid within one year	$	284
Remaining balance to be paid beyond one year	$	389

The Company is not obligated to fund the liability. It has, however, established a rabbi trust to offset the deferred compensation liability and protect the interests 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 material 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, 2011 and six months ended June 30, 2012 (in thousands):

Beginning investment balance – January 1, 2011	$	260
Investment purchases		362
Distributions		(34	)
Earnings (losses)		(9	)
Ending investment balance – December 31, 2011	$	579
Investment purchases		190
Distributions		(117	)
Earnings		20
Ending investment balance – June 30, 2012	$	672

14. Commitments and Contingencies

Drilling Contracts. The Company has contracts with various drilling contractors to lease five rigs with remaining terms of up to one year. These commitments are not recorded in the accompanying Unaudited Consolidated Balance Sheets. As of June 30, 2012, the aggregate undiscounted minimum future drilling rig commitment was approximately $22.2 million; however the contracts may be terminated but the Company would be required to pay a penalty of $13.9 million.

Gathering, Processing and Transportation Agreements. The Company has contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move a portion of our production to market. The remaining terms on these contracts range from one to 12 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. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying Unaudited Consolidated Balance Sheets.

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The aggregate undiscounted commitments under our gathering, processing and transportation agreements are presented below:

	June 30, 2012
	(in thousands)
2012	$	62,115
2013		62,035
2014		61,766
2015		60,184
2016		56,468
After 2016		169,763
Total	$	472,331

The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. The Company renewed the lease of its principal offices in Denver, Colorado in February 2012, extending the lease through March 2019 and adding square footage. As of June 30, 2012, the aggregate undiscounted minimum future commitments are presented below:

	June 30, 2012
	(in thousands)
2012	$	3,528
2013		3,613
2014		3,075
2015		2,536
2016		2,496
After 2016		4,436
Total	$	19,684

Other Obligations. The Company has one take-or-pay carbon dioxide purchase agreement, amended in July 2012, which expires in December 2015. The agreement imposes a minimum volume commitment to purchase CO2 at a contracted price. The contract provides CO2 used in fracture stimulation operations in the Company’s Uinta Basin operations. Should the Company not take delivery of the minimum volume required, the Company would be obligated to pay for the deficiency. As of June 30, 2012, the aggregate undiscounted minimum future commitment was approximately $7.1 million.

15. Guarantor Subsidiaries

In addition to the Amended Credit Facility, the 9.875% Senior Notes, the 7.625% Senior Notes, the 7.0% 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 unaudited balance sheets, statements of operations 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 unaudited 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

	As of June 30, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Assets:
Current assets	$	199,799		$	2,830		$	0	$	202,629
Property and equipment, net		2,589,400			110,632			0		2,700,032
Intercompany receivable (payable)		144,733			(144,733	)		0		0
Investment in subsidiaries		(46,800	)		0			46,800		0
Noncurrent assets		52,785			0			0		52,785
Total assets	$	2,939,917		$	(31,271	)	$	46,800	$	2,955,446
Liabilities and Stockholders’ Equity:
Current liabilities	$	198,551		$	1,100		$	0	$	199,651
Long-term debt		1,142,317			0			0		1,142,317
Deferred income taxes		293,445			11,343			0		304,788
Other noncurrent liabilities		70,222			3,086			0		73,308
Stockholders’ equity		1,235,382			(46,800	)		46,800		1,235,382
Total liabilities and stockholders’ equity	$	2,939,917		$	(31,271	)	$	46,800	$	2,955,446
	As of December 31, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Assets:
Current assets	$	244,256		$	2,087		$	0	$	246,343
Property and equipment, net		2,301,355			105,409			0		2,406,764
Intercompany receivable (payable)		139,692			(139,692	)		0		0
Investment in subsidiaries		(47,384	)		0			47,384		0
Noncurrent assets		34,823			0			0		34,823
Total assets	$	2,672,742		$	(32,196	)	$	47,384	$	2,687,930
Liabilities and Stockholders’ Equity:
Current liabilities	$	232,347		$	851		$	0	$	233,198
Long-term debt		882,240			0			0		882,240
Deferred income taxes		270,446			11,343			0		281,789
Other noncurrent liabilities		68,871			2,994			0		71,865
Stockholders’ equity		1,218,838			(47,384	)		47,384		1,218,838
Total liabilities and stockholders’ equity	$	2,672,742		$	(32,196	)	$	47,384	$	2,687,930

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Condensed Consolidating Statements of Operations

	Three Months Ended June 30, 2012
	Parent Issuer		Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	155,587	$	4,765	$	0		$	160,352
Operating expenses		158,252		4,611		0			162,863
General and administrative		15,036		0		0			15,036
Interest and other income		23,225		0		0			23,225
Income before income taxes and equity in earnings of subsidiaries		5,524		154		0			5,678
Provision for income taxes		2,380		0		0			2,380
Equity in earnings (loss) of subsidiaries		154		0		(154	)		0
Net income (loss)	$	3,298	$	154	$	(154	)	$	3,298
	Six Months Ended June 30, 2012
	Parent Issuer		Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	330,121	$	9,407	$	0		$	339,528
Operating expenses		281,323		8,823		0			290,146
General and administrative		33,476		0		0			33,476
Interest income and other income		47,945		0		0			47,945
Income before income taxes and equity in earnings of subsidiaries		63,267		584		0			63,851
Provision for income taxes		24,660		0		0			24,660
Equity in earnings (loss) of subsidiaries		584		0		(584	)		0
Net income (loss)	$	39,191	$	584	$	(584	)	$	39,191

	Three Months Ended June 30, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	194,237		$	3,112		$	0	$	197,349
Operating expenses		112,117			3,714			0		115,831
General and administrative		14,757			0			0		14,757
Interest and other income (expense)		(15,126	)		0			0		(15,126	)
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	$	364,094		$	5,690		$	0	$	369,784
Operating expenses		216,797			7,263			0		224,060
General and administrative		32,453			0			0		32,453
Interest and other income (expense)		(38,217	)		0			0		(38,217	)
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

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended June 30, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	3,298		$	154		$	(154	)	$	3,298
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		(12,997	)		0			0			(12,997	)
Other comprehensive loss		(12,997	)		0			0			(12,997	)
Comprehensive income (loss)	$	(9,699	)	$	154		$	(154	)	$	(9,699	)
	Six Months Ended June 30, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	39,191		$	584		$	(584	)	$	39,191
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		(28,905	)		0			0			(28,905	)
Other comprehensive loss		(28,905	)		0			0			(28,905	)
Comprehensive income (loss)	$	10,286		$	584		$	(584	)	$	10,286
	Three Months Ended June 30, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	32,636		$	(602	)	$	602		$	32,636
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		5,474			0			0			5,474
Other comprehensive income		5,474			0			0			5,474
Comprehensive income (loss)	$	38,110		$	(602	)	$	602		$	38,110

	Six Months Ended June 30, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	47,851		$	(1,573	)	$	1,573	$	47,851
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		(17,839	)		0			0		(17,839	)
Other comprehensive loss		(17,839	)		0			0		(17,839	)
Comprehensive income (loss)	$	30,012		$	(1,573	)	$	1,573	$	30,012

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Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	175,577		$	3,667		$	0	$	179,244
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(451,421	)		(8,638	)		0		(460,059	)
Additions to furniture, fixtures and other		(4,241	)		0			0		(4,241	)
Proceeds from sale of properties and other investing activities		134			0			0		134
Cash flows from financing activities:
Proceeds from debt		525,000			0			0		525,000
Principal payments on debt		(267,156	)		0			0		(267,156	)
Intercompany transfers		(4,971	)		4,971			0		0
Other financing activities		(9,419	)		0			0		(9,419	)
Change in cash and cash equivalents		(36,497	)		0			0		(36,497	)
Beginning cash and cash equivalents		57,281			50			0		57,331
Ending cash and cash equivalents	$	20,784		$	50		$	0	$	20,834

	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

16. Subsequent Events

The Company completed leasehold acquisitions totaling 31,070 net acres in the Denver-Julesburg (“DJ”) Basin, located in the Wattenberg Field northeast extension area (“northeast Wattenberg”), subsequent to quarter-end. The Company also completed lease financing agreements for approximately $88.0 million for existing compressors and related facilities owned by the Company in the West Tavaputs and Gibson Gulch areas. The agreements are with several financial institutions and have an implicit interest rate of less than 3.5% per annum. The Company plans to use the funds received to repay outstanding borrowings under the Amended Credit Facility.

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

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 oil, natural gas and natural gas liquids (“NGLs”);

• ability to receive drilling and other permits, regulatory approvals and required surface access and rights of way;

• economic and competitive conditions;

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• legislative or regulatory changes including initiatives related to drilling and completion techniques including hydraulic fracturing;

• debt and equity market conditions;

• derivative and hedging activities;

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

• changes in estimates of proved reserves;

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

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

• exploration risks such as drilling unsuccessful wells;

• compliance with environmental and other regulations;

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

• future processing volumes and pipeline throughput;

• 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;

• 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;

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

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

• occurrence of property acquisitions or divestitures;

• changes in tax rates; 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, 2011 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 together with our wholly-owned subsidiaries (“the Company”, “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 cashflow, reserves and production, which we expect will include investing in and profitably developing key existing development programs as well as growth through exploration and acquisitions. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGLs recovery at market prices and from the settlement of commodity hedges.

We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. Since inception, we have built our portfolio of exploration and development properties primarily through acquisitions where we seek to add value through our geologic and operational expertise. Our acquisitions have included key assets in the Piceance (Colorado), Uinta (Utah), Denver-Julesburg (Colorado and Wyoming), Powder River (Wyoming) and Wind River (Wyoming) Basins in the Rocky Mountain region (the “Rockies”).

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We are committed to exploring for, developing and producing oil and natural gas in a responsible manner. We work diligently with environmental, wildlife and community organizations to ensure that our exploration and development activities are designed with all stakeholders in mind.

We operate in one industry segment, which is the exploration, development and production of crude oil and natural gas, and all of our operations are conducted in the United States. Consequently, we currently report a single reportable segment. See “Financial Statements” and the notes to our Unaudited Consolidated Financial Statements for financial information about this reportable segment.

Results of Operations

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

Three Months Ended June 30, 2012 Compared with Three Months Ended June 30, 2011

	Three Months Ended June 30,				Increase (Decrease)
	2012		2011		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil and gas production	$	159,490	$	194,328	$	(34,838	)		(18	)%
Other		862		3,021		(2,159	)		(71	)%
Operating Expenses
Lease operating expense		19,030		14,075		4,955			35	%
Gathering, transportation and processing expense		25,862		21,338		4,524			21	%
Production tax expense		6,892		9,781		(2,889	)		(30	)%
Exploration expense		4,062		697		3,365			*nm
Impairment, dry hole costs and abandonment expense		21,075		1,093		19,982			*nm
Depreciation, depletion and amortization		85,942		68,847		17,095			25	%
General and administrative expense(1)		11,314		10,739		575			5	%
Non-cash stock-based compensation expense(1)		3,722		4,018		(296	)		(7	)%
Total operating expenses	$	177,899	$	130,588	$	47,311			36	%
Production Data:
Natural gas (MMcf)		26,094		24,506		1,588			6	%
Oil (MBbls)		634		331		303			92	%
Combined volumes (MMcfe)		29,898		26,492		3,406			13	%
Daily combined volumes (MMcfe/d)		329		291		38			13	%
Average Prices:
Natural gas (per Mcf) (2)	$	4.16	$	6.82	$	(2.66	)		(39	)%
Oil (per Bbl)		80.11		82.40		(2.29	)		(3	)%
Combined (per Mcfe)		5.33		7.34		(2.01	)		(27	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.64	$	0.53	$	0.11			21	%
Gathering, transportation and processing expense		0.87		0.81		0.06			7	%
Production tax expense		0.23		0.37		(0.14	)		(38	)%
Depreciation, depletion and amortization		2.87		2.60		0.27			10	%
General and administrative expense(3)		0.38		0.41		(0.03	)		(7	)%

* 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 $15.0 million and $14.8 million for the three months ended June 30, 2012 and 2011, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure.

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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) Natural gas average prices include the effect of NGL related revenue.

(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 $0.50 and $0.56 for the three months ended June 30, 2012 and 2011, respectively.

Production Revenues and Volumes. Production revenues decreased to $159.5 million for the three months ended June 30, 2012 from $194.3 million for the three months ended June 30, 2011. This decrease is due to a 27% decrease in oil and natural gas prices on a per Mcfe basis, including the effects of cash flow hedges, partially offset by a 13% increase in production volumes. The decrease in average prices decreased production revenues by approximately $53.0 million, while the net increase in production added approximately $18.2 million of production revenues.

The three months ended June 30, 2011 included settlements of $19.8 million from financial hedging instruments that were designated as cash flow hedges and excluded those that did 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 were included in the line item commodity derivative gain (loss) within other income in the Unaudited Consolidated Statements of Operations. See below for more information related to the commodity derivative gain (loss) line item. We discontinued hedge accounting effective January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in accumulated other comprehensive income (“AOCI”) as of January 1, 2012 and will remain in AOCI until the underlying transaction occurs. As the underlying transaction occurs, these gains or losses are reclassified from AOCI into oil and gas production revenues. The amount reclassified to oil and gas production revenues was a gain of $20.8 million for the three months ended June 30, 2012.

Total production volumes of 29.9 Bcfe for the three months ended June 30, 2012 increased from 26.5 Bcfe for the three months ended June 30, 2011 due to increased production in the Piceance Basin, Uinta Basin and DJ Basin. The increase in production was partially offset by decreases in production from the Wind River Basin and the Coalbed Methane (“CBM”) area in the Powder River Basin. Additional information concerning production is in the following table:

	Three Months Ended June 30, 2012						Three Months Ended June 30, 2011						% 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		162		12,251		13,223		121		11,121		11,847		34	%		10	%		12	%
Uinta-West Tavaputs		18		9,114		9,222		15		8,215		8,305		20	%		11	%		11	%
Uinta Oil Program		327		582		2,544		180		417		1,497		82	%		40	%		70	%
DJ Basin		96		248		824		—		—		—		*nm			*nm			*nm
Powder River-CBM		—		2,788		2,788		—		3,297		3,297		0	%		(15	)%		(15	)%
Powder River Deep		25		20		170		8		34		82		213	%		(41	)%		107	%
Wind River Basin		5		1,041		1,071		6		1,383		1,419		(17	)%		(25	)%		(25	)%
Other		1		50		56		1		39		45		0	%		28	%		24	%
Total		634		26,094		29,898		331		24,506		26,492		92	%		6	%		13	%

* Not meaningful.

The production increase in the Piceance Basin was primarily the result of our initial sales from 151 new gross wells from July 1, 2011 to June 30, 2012. The production increase in the West Tavaputs area of the Uinta Basin resulted primarily from our development activities with initial sales from 83 new gross wells from July 1, 2011 to June 30, 2012. In addition, we had production growth in our Uinta Oil Program at Blacktail Ridge and Lake Canyon, where we had initial sales from 58 new gross wells from July 1, 2011 to June 30, 2012 as well as added production of 732 barrels of oil equivalent per day (Boe/d) for the three months ended June 30, 2012 from the acquisition of East Bluebell in June 2011. The production increase in the Powder River Basin was due to increased oil production in the Powder River Deep area due to initial sales on nine new gross conventional wells from July 1, 2011 to June 30, 2012, offset by natural production declines in our natural gas producing coalbed methane fields with no significant drilling or recompletion activities to offset these declines. Further, the DJ Basin added 1,509 Boe/d during the three months ended June 30, 2012. The production decrease in the Wind River Basin was due to natural production declines with no significant drilling or recompletion activities to offset these declines.

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Hedging Activities. During the three months ended June 30, 2012, approximately 76% of our oil volumes, 66% of our natural gas volumes (excluding basis only swaps, which were equivalent to 7% of our natural gas volumes), and 26% of our NGL related volumes were subject to financial hedges, which resulted in an increase in oil revenues of $3.8 million and an increase in natural gas revenues of $35.9 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the three months ended June 30, 2011, approximately 71% of our oil volumes, 66% of our natural gas volumes (excluding basis only swaps, which were equivalent to 7% of our natural gas volumes), and 63% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $2.3 million and an increase in gas revenues of $13.5 million after settlements for all commodity derivatives, including basis only and NGL swaps. We may not always be able to generate increases in revenue due to the expiration of hedges entered into at higher prices, and our ability to enter into new hedges at those prices has decreased as natural gas prices have fallen since entering into those hedges.

Lease Operating Expense. Lease operating expense increased to $0.64 per Mcfe for the three months ended June 30, 2012 from $0.53 per Mcfe for the three months ended June 30, 2011. The increase in lease operating expense is primarily related to acquisitions of oil producing properties in the Uinta and DJ Basins with inherently higher lifting costs per Mcfe compared to gas properties. In addition, the above lease operating expense rates include approximately $0.02 per Mcfe of compressor overhaul expenses for the period ended June 30, 2012 and approximately $0.05 and $0.03 per Mcfe of workover expenses for the periods ended June 30, 2012 and 2011, respectively.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.87 per Mcfe for the three months ended June 30, 2012 from $0.81 per Mcfe for the three months ended June 30, 2011. Increased production from the West Tavaputs field within the Uinta Basin has led to an increase in volumes gathered, transported and processed under higher cost agreements, which resulted in higher costs on a per unit basis. As a result, gathering, transportation and processing expense increased approximately $0.06 per Mcfe for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. The increase in transportation costs related to West Tavaputs was primarily the result of firm transportation agreements that became effective in late July 2011 for the Ruby Pipeline and Wyoming Interstate Company.

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. 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 $0.38 and $0.27 per Mcfe of firm transportation and gathering expense and $0.05 and $0.06 per Mcfe of firm processing expense from long-term contracts for the three months ended June 30, 2012 and 2011, respectively. The increase in firm transportation and gathering expense to $0.38 per Mcfe for the three months ended June 30, 2012 compared with $0.27 per Mcfe for the three months ended June 30, 2011 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.

Production Tax Expense. Total production taxes decreased to $6.9 million for the three months ended June 30, 2012 from $9.8 million for the three months ended June 30, 2011. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense decreased during the three months ended June 30, 2012 primarily due to a 21.0% decrease in wellhead values of production, excluding hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments was 5.0% for the three months ended June 30, 2012, which included a reduction of 0.7% related to the nonrecurring items associated with the Colorado and Utah production taxes. Production taxes as a percentage of oil and natural gas sales before hedging adjustments was 5.6% for the three months ended June 30, 2011.

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, excluding the nonrecurring items associated with the Wyoming, Utah and Colorado severance taxes, is consistent with our production decrease in states with higher production tax rates.

Exploration Expense. Exploration expense increased to $4.1 million for the three months ended June 30, 2012 from $0.7 million for the three months ended June 30, 2011. Exploration expense for the three months ended June 30, 2012 consisted of $3.7 million of geological and geophysical seismic programs across several basins and $0.4 million for delay rentals across all basins. 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.

35

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $21.1 million for the three months ended June 30, 2012 from $1.1 million for the three months ended June 30, 2011. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. For the three months ended June 30, 2012, impairment expense was $18.3 million, abandonment expense associated with exploratory drilling locations was $1.8 million, expired leasehold costs were $0.9 million and dry hole costs were $0.1 million. The Company recorded a non-cash impairment charge of $18.3 million related to certain unproved oil and gas properties within various exploration and development projects primarily as a result of unfavorable market conditions or no future plans to evaluate the remaining acreage. For the three months ended June 30, 2011, expired leasehold costs were $0.9 million and dry hole costs were $0.2 million.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization (“DD&A”) increased to $85.9 million for the three months ended June 30, 2012 compared with $68.8 million for the three months ended June 30, 2011. The increase of $17.1 million was a result of a 13% increase in production for the three months ended June 20, 2012 compared with the three months ended June 30, 2011 coupled with an increase in the DD&A rate. The increase in production accounted for $8.8 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for an $8.3 million increase in DD&A expense. For the three months ended June 30, 2012 and 2011, the weighted average DD&A rates were $2.87 per Mcfe and $2.60 per Mcfe, respectively.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended June 30 2012, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $2.87 per Mcfe compared with $2.60 per Mcfe for the three months ended June 30, 2011. Future depletion rates will be adjusted to reflect capital expenditures, changes in commodity prices, proved reserve changes and well performance.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $11.3 million in the three months ended June 30, 2012 from $10.7 million in the three months ended June 30, 2011. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 33 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, 2012. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $0.38 per Mcfe for the three months ended June 30, 2012 from $0.41 per Mcfe for the three months ended June 30, 2011, largely due to the 13% increase in production in the three months ended June 30, 2012.

Non-cash charges for stock-based compensation for the three months ended June 30, 2012 and the three months ended June 30, 2011 were $3.7 million and $4.0 million, respectively. Non-cash stock-based compensation expense for each of the three months ended June 30, 2012 and 2011 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, 2012 and 2011 are shown in the following table:

	Three Months Ended June 30,
	2012		2011
	(in thousands)
Stock options and nonvested equity shares of common stock	$	3,539	$	3,805
Shares issued for 401(k) plan		147		112
Shares issued for directors’ fees		36		101
Total	$	3,722	$	4,018

Interest Expense.Interest expense increased to $23.9 million for the three months ended June 30, 2012 from $12.3 million for the three months ended June 30, 2011. The increase for the three months ended June 30, 2012 was primarily due to higher debt balances partially offset by lower borrowing costs. Our weighted average interest rate for the three months ended June 30, 2012, including interest and amortization of discounts and deferred financing fees on our Amended Credit Facility, the Convertible Notes, 9.875% Senior Notes, 7.625% Senior Notes and 7.0% Senior Notes, was 8.8% compared to 11.3% for 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. We capitalized interest costs of $0.1 million and $0.5 million for the three months ended June 30, 2012 and 2011, respectively.

36

Commodity Derivative Gain (Loss).We discontinued hedge accounting effective January 1, 2012. Therefore, the commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations was comprised of changes in the derivative’s fair value for all discontinued cash flow hedges. As a result of discontinuing hedge accounting on January 1, 2012, the mark-to-market value of all commodity hedge instruments within AOCI at December 31, 2011 were frozen in AOCI as of the de-designation date, January 1, 2012, and will be reclassified into earnings in future periods as the original hedged transactions occur. As such, subsequent to January 1, 2012, we have recognized unrealized gains and losses from prospective changes in commodity derivative fair values immediately in the Unaudited Consolidated Statements of Operations in the commodity derivative gain (loss) line item rather than deferring any such amounts in AOCI. For the three months ended June 30, 2012, the commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations also includes realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as cash flow hedges, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item. This change in reporting had no impact on our reported cash flows, although future results of operations will be affected by unrealized gains and losses, which fluctuate with volatile oil and gas prices.

For the three months ended June 30, 2011, the commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations was comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that did not qualify for cash flow hedge accounting or were not designated as cash flow hedges. Ineffectiveness on cash flow hedges related to slight differences between the contracted location and the actual delivery location. Unrealized gains and losses include the change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement was presented as realized gains and losses within this same line item.

Commodity derivative gain (loss) increased to a gain of $47.0 million for the three months ended June 30, 2012 from a loss of $2.9 million for the three months ended June 30, 2011 primarily due to the increase in realized and unrealized gains compared to losses as of June 30, 2011 resulting from the decrease in oil and gas commodity pricing for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011, as well as the additional hedges included in the commodity gain (loss) line item for the three months ended June 30, 2012 due to discontinuing hedge accounting as of January 1, 2012.

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,
	2012		2011
	(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges	$	18,916	$	(8,590	)
Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges		0		888
Unrealized gain (loss) on derivatives not designated as cash flow hedges		28,108		4,795
Total commodity derivative gain (loss)	$	47,024	$	(2,907	)

Income Tax Expense. Income tax expense totaled $2.4 million for the three months ended June 30, 2012 compared with $19.0 million for the three months ended June 30, 2011, resulting in effective tax rates of 41.9% and 36.8%, 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. Partially offsetting this decrease was the reduction in tax deductible compensation related to stock options for the three months ended June 30, 2012. The effective tax rate change was primarily the result of an increase in projected hedging gains relative to our total revenue, resulting in an increase in income apportioned to higher tax rate jurisdictions. 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, 2012. 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. Additionally, the decrease in tax deductible stock-based compensation for the three months ended June 30, 2012 had an unfavorable impact on the overall effective tax rate. For both the 2012 and 2011 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 not deductible for income tax purposes as well as the effect of state income taxes.

37

Six Months Ended June 30, 2012 Compared with Six Months Ended June, 2011

	Six Months Ended June 30,				Increase (Decrease)
	2012		2011		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil and gas production	$	336,532	$	366,525	$	(29,993	)		(8	)%
Other		2,996		3,259		(263	)		(8	)%
Operating Expenses
Lease operating expense		37,668		27,374		10,294			38	%
Gathering, transportation and processing expense		53,214		40,674		12,540			31	%
Production tax expense		13,099		18,347		(5,248	)		(29	)%
Exploration expense		4,501		2,048		2,453			120	%
Impairment, dry hole costs and abandonment expense		21,639		1,376		20,263			*nm
Depreciation, depletion and amortization		160,025		134,241		25,784			19	%
General and administrative expense(1)		25,114		23,806		1,308			5	%
Non-cash stock-based compensation expense(1)		8,362		8,647		(285	)		(3	)%
Total operating expenses	$	323,622	$	256,513	$	67,109			26	%
Production Data:
Natural gas (MMcf)		51,412		45,941		5,471			12	%
Oil (MBbls)		1,115		628		487			78	%
Combined volumes (MMcfe)		58,102		49,709		8,393			17	%
Daily combined volumes (MMcfe/d)		319		275		44			16	%
Average Prices:
Natural gas (per Mcf) (2)	$	4.70	$	6.88	$	(2.18	)		(32	)%
Oil (per Bbl)		85.01		80.53		4.48			6	%
Combined (per Mcfe)		5.79		7.37		(1.58	)		(21	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.65	$	0.55	$	0.10			18	%
Gathering, transportation and processing expense		0.92		0.82		0.10			12	%
Production tax expense		0.23		0.37		(0.14	)		(38	)%
Depreciation, depletion and amortization		2.75		2.70		0.05			2	%
General and administrative expense(3)		0.43		0.48		(0.05	)		(10	)%

* 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 $33.5 million and $32.5 million for the six months ended June 30, 2012 and 2011, 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) Natural gas average prices include the effect of NGL related revenue.

(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 $0.58 and $0.65 for the six months ended June 30, 2012 and 2011, respectively.

38

Production Revenues and Volumes. Production revenues decreased to $336.5 million for the six months ended June 30, 2012 from $366.5 million for the six months ended June 30, 2011. This decrease was due to a 21% decrease in oil and natural gas prices on a per Mcfe basis, including the effects of cash flow hedges, partially offset by a 17% increase in production volumes. The decrease in average prices decreased production revenues by approximately $78.6 million, while the net increase in production added approximately $48.6 million of production revenue.

The six months ended June 30, 2011 included settlements of $47.7 million from financial hedging instruments that were designated as cash flow hedges and excluded those that did 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 were included in the line item commodity derivative gain (loss) within other income in the Unaudited Consolidated Statements of Operations. See below for more information related to the commodity derivative gain (loss) line item. We discontinued hedge accounting effective January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in AOCI effective January 1, 2012 and will remain in AOCI until the underlying transaction occurs. As the underlying transaction occurs, these gains or losses are reclassified from AOCI into oil and gas production revenues. The amount reclassified to oil and gas production revenues was a gain of $46.3 million for the six months ended June 30, 2012.

Total production volumes of 58.1 Bcfe for the six months ended June 30, 2012 increased from 49.7 Bcfe for the six months ended June 30, 2011 due to increased production in the Piceance Basin, Uinta Basin and DJ Basin. The increase in production was partially offset by decreases in production from the Wind River Basin and the CBM area in the Powder River Basin. Additional information concerning production is in the following table:

	Six Months Ended June 30, 2012						Six Months Ended June 30, 2011						% 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		300		23,678		25,478		261		22,253		23,819		15	%		6	%		7	%
Uinta-West Tavaputs		33		18,128		18,326		21		13,490		13,616		57	%		34	%		35	%
Uinta Oil Program		592		1,095		4,647		319		688		2,602		86	%		59	%		79	%
DJ Basin		144		499		1,363		—		—		—		*nm			*nm			*nm
Powder River-CBM		—		5,796		5,796		—		6,638		6,638		0	%		(13	)%		(13	)%
Powder River Deep		34		61		265		14		40		124		143	%		53	%		114	%
Wind River Basin		8		2,103		2,151		10		2,738		2,798		(20	)%		(23	)%		(23	)%
Other		4		52		76		3		94		112		33	%		(45	)%		(32	)%
Total		1,115		51,412		58,102		628		45,941		49,709		78	%		12	%		17	%

* Not meaningful.

The production increase in the Piceance Basin was primarily the result of our initial sales from 151 new gross wells from July 1, 2011 to June 30, 2012. The production increase in the West Tavaputs area of the Uinta Basin resulted primarily from our development activities with initial sales from 83 new gross wells from July 1, 2011 to June 30, 2012. In addition, we had production growth in our Uinta Oil Program at Blacktail Ridge and Lake Canyon, where we had initial sales from 58 new gross wells from July 1, 2011 to June 30, 2012 as well as added production of 625 barrels of oil equivalent per day (Boe/d) for the six months ended June 30, 2012 from the acquisition of East Bluebell in June 2011. The production increase in the Powder River Basin was due to increased oil production in the Powder River Deep area due to initial sales on nine new gross conventional wells from July 1, 2011 to June 30, 2012, offset by natural production declines in our natural gas producing coalbed methane fields with no significant drilling or recompletion activities to offset these declines. Further, the DJ Basin added 1,248 Boe/d during the six months ended June 30, 2012. The production decrease in the Wind River Basin was due to natural production declines with no significant drilling or recompletion activities to offset these declines.

Hedging Activities. During the six months ended June 30, 2012, approximately 82% of our oil volumes, 65% of our natural gas volumes (excluding basis only swaps, which were equivalent to 7% of our natural gas volumes), and 29% of our NGL related volumes were subject to financial hedges, which resulted in an increase in oil revenues of $3.1 million and an increase in natural gas revenues of $65.9 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the six months ended June 30, 2011, approximately 67% of our oil volumes, 65% of our natural gas volumes (excluding basis only swaps, which were equivalent to 8% of our natural gas volumes), and 54% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $3.1 million and an increase in gas revenues of $36.8 million after settlements for all commodity derivatives, including basis only and NGL swaps. We may not always be able to generate increases in revenue due to the expiration of hedges entered into at higher prices, and our ability to enter into new hedges at those prices has decreased as natural gas prices have fallen since entering into those hedges.

39

Lease Operating Expense. Lease operating expense increased to $0.65 per Mcfe for the six months ended June 30, 2012 from $0.55 per Mcfe for the six months ended June 30, 2011. The increase in lease operating expense is primarily related to acquisitions of oil producing properties in the Uinta and DJ Basins with inherently higher lifting costs per Mcfe compared to gas properties. In addition, the above lease operating expense rates include approximately $0.03 per Mcfe of compressor overhaul expenses for the period ended June 30, 2012 and approximately $0.06 and $0.05 per Mcfe of workover expenses for the periods ended June 30, 2012 and 2011, respectively.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.92 per Mcfe for the six months ended June 30, 2012 from $0.82 per Mcfe for the six months ended June 30, 2011. Increased production from the West Tavaputs field within the Uinta Basin has led to an increase in volumes gathered, transported and processed under higher cost agreements, which resulted in higher costs on a per unit basis. As a result, gathering, transportation and processing expense increased approximately $0.10 per Mcfe for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. The increase in transportation costs related to West Tavaputs was primarily the result of firm transportation agreements that became effective in late July 2011 for the Ruby Pipeline and Wyoming Interstate Company. In addition, we decreased drilling activity in the West Tavaputs area of the Uinta Basin. As a result, we were unable to meet a portion of our minimum volume commitments relating to our firm processing agreements and incurred a one-time charge of approximately $2.5 million in March 2012. The increases above were offset by higher oil production with lower transportation costs on a per Mcfe basis.

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. 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 $0.38 and $0.28 per Mcfe of firm transportation and gathering expense for the six months ended June 30, 2012 and 2011, respectively, and $0.05 per Mcfe of firm processing expense from long-term contracts for both the six months ended June 30, 2012 and 2011. The increase in firm transportation and gathering expense to $0.38 per Mcfe for the six months ended June 30, 2012 compared with $0.28 per Mcfe for the six months ended June 30, 2011 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.

Production Tax Expense. Total production taxes decreased to $13.1 million for the six months ended June 30, 2012 from $18.3 million for the six months ended June 30, 2011. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense decreased during the six months ended June 30, 2012 primarily due to a 9.3 % decrease in wellhead values of production, excluding hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments was 4.5% for the six months ended June 30, 2012, which included a reduction of 1.0% related to the nonrecurring items associated with the Utah, Colorado and Wyoming production tax calculations. Production taxes as a percentage of oil and natural gas sales before hedging adjustments was 5.7% for the six months ended June 30, 2011, which included a reduction of 0.3% related to the nonrecurring items associated with the Utah, Colorado and Wyoming annual severance tax calculations.

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, excluding the nonrecurring items associated with the Utah, Colorado and Wyoming severance taxes, is consistent with our production decrease in states with higher production tax rates.

Exploration Expense. Exploration expense increased to $4.5 million for the six months ended June 30, 2012 from $2.0 million for the six months ended June 20, 2011. Exploration expense for the six months ended June 30, 2012 consisted of $3.9 million of geological and geophysical seismic programs and $0.6 million for delay rentals across all basins. 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.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $21.6 million for the six months ended June 30, 2012 from $1.4 million for the six months ended June 30, 2011. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate

40

impairment in value. For the six months ended June 30, 2012, impairment expense was $18.3 million, abandonment expense associated with exploratory drilling locations was $2.0 million, expired leasehold costs were $1.1 million and dry hole costs were $0.2 million. The Company recorded a non-cash impairment charge of $18.3 million related to certain unproved oil and gas properties within various exploration and development projects primarily as a result of unfavorable market conditions or no future plans to evaluate the remaining acreage. For the six months ended June 30, 2011, expired leasehold costs were $1.1 million and dry hole costs were $0.3 million.

Depreciation, Depletion and Amortization.DD&A increased to $160.0 million for the six months ended June 30, 2012 compared with $134.2 million for the six months ended June 30, 2011. The increase of $25.8 million was a result of a 17% increase in production for the six months ended June 30, 2012 compared with the six months ended June 30, 2011 coupled with an increase in the DD&A rate. The increase in production accounted for $22.7 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for a $3.1 million increase in DD&A expense. For the six months ended June 30, 2012 and 2011, the weighted average DD&A rates were $2.75 per Mcfe and $2.70 per Mcfe, respectively.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the six months ended June 30 2012, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $2.75 per Mcfe compared with $2.70 per Mcfe for the six months ended June 30, 2011. Future depletion rates will be adjusted to reflect capital expenditures, changes in commodity prices, proved reserve changes and well performance.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $25.1 million for the six months ended June 30, 2012 from $23.8 million for the six months ended June 30, 2011. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 38 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, 2012. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $0.43 per Mcfe for the six months ended June 30, 2012 from $0.48 per Mcfe for the six months ended June 30, 2011, largely due to the 17% increase in production in the six months ended June 30, 2012.

Non-cash charges for stock-based compensation for the six months ended June 30, 2012 and the six months ended June 30, 2011 were $8.4 million and $8.6 million, respectively. Non-cash stock-based compensation expense for each of the six months ended June 30, 2012 and 2011 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 six months ended June 30, 2012 and 2011 are shown in the following table:

	Six Months Ended June 30,
	2012		2011
	(in thousands)
Stock options and nonvested equity shares of common stock	$	7,829	$	8,046
Shares issued for 401(k) plan		458		388
Shares issued for directors’ fees		75		213
Total	$	8,362	$	8,647

Interest Expense.Interest expense increased to $45.5 million for the six months ended June 30, 2012 from $24.4 million for the six months ended June 30, 2011. The increase for the six months ended June 30, 2012 was primarily due to higher debt balances partially offset by lower average borrowing costs. Our weighted average interest rate for the six months ended June 30, 2012, including interest and amortization of discounts and deferred financing fees on our Amended Credit Facility, the Convertible Notes, 9.875% Senior Notes, 7.625% Senior Notes and 7.0% Senior Notes was 9.0% compared to 11.8% for 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. We capitalized interest costs of $0.2 million and $1.0 million for the six months ended June 30, 2012 and 2011, respectively.

Commodity Derivative Gain (Loss). We discontinued hedge accounting effective January 1, 2012. Therefore, the commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations was comprised of changes in the derivative’s fair value for all discontinued cash flow hedges. As a result of discontinuing hedge accounting effective January 1, 2012, the mark-to-market value of all commodity hedge instruments within AOCI at December 31, 2011 were frozen in AOCI as of the de-designation date, January 1, 2012, and will be reclassified into earnings in future periods as the original hedged transactions occur. As such, subsequent to January 1, 2012, we have recognized unrealized gains and losses from prospective changes in commodity derivative fair

41

values immediately in the Unaudited Consolidated Statements of Operations in the commodity derivative gain (loss) line item rather than deferring any such amounts in AOCI. For the six months ended June 30, 2012, the commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations also includes realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as cash flow hedges, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item. This change in reporting had no impact on our reported cash flows, although future results of operations will be affected by unrealized gains and losses, which fluctuate with volatile oil and gas prices.

For the six months ended June 30, 2011, the commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations was comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that did not qualify for cash flow hedge accounting or were not designated as cash flow hedges. Ineffectiveness on cash flow hedges related to slight differences between the contracted location and the actual delivery location. Unrealized gains and losses include the change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement was presented as realized gains and losses within this same line item.

The commodity derivative gain (loss) line item increased to a gain of $91.8 million for the six months ended June 30, 2012 from a loss of $14.0 million for the six months ended June 30, 2011 primarily due to the increase in realized and unrealized gains compared to losses as of June 30, 2011 resulting from the decrease in oil and gas commodity pricing for the period ended June 30, 2012 as compared to June 30, 2011, as well as the additional hedges included in the commodity gain (loss) line item for the six months ended June 30, 2012 due to discontinuing hedge accounting as of January 1, 2012.

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,
	2012		2011
	(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges	$	22,719	$	(13,994	)
Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges(2)		0		1,050
Unrealized gain (loss) on derivatives not designated as cash flow hedges		69,052		(1,075	)
Total commodity derivative gain (loss)	$	91,771	$	(14,019	)

Income Tax Expense. Income tax expense totaled $24.7 million for the six months ended June 30, 2012 compared to $27.2 million for the six months ended June 30, 2011, resulting in effective tax rates of 38.6% and 36.2%, 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. Partially offsetting this decrease was the reduction in tax deductible compensation related to stock options for the six months ended June 30, 2012. The effective tax rate change was primarily the result of an increase in projected hedging gains relative to our total revenue for the six months ended June 30, 2012, resulting in an increase in income apportioned to higher tax rate jurisdictions. 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, 2012. 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. Additionally, the decrease in tax deductible stock-based compensation had an unfavorable impact on the effective tax rate. For both the 2012 and 2011 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 exploration, development and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. The credit market dislocation that has existed over the past several years has improved; however, the costs to raise future debt and equity capital may be

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higher than previous issuances and such dislocations may recur. 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. In addition, our hedge positions currently provide relative certainty on a portion of our cash flows from operations through 2013 even with the general decline in oil and natural gas commodity prices. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing, which may be at a higher cost than previous issuances. On June 28, 2012, we filed with the SEC a new universal shelf registration statement that we may use for future securities offerings.

At June 30, 2012, we had cash and cash equivalents of $20.8 million and a $75.0 million balance outstanding under our Amended Credit Facility. On October 18, 2011, we further amended our Amended Credit Facility, to extend the maturity date to October 31, 2016. The amendment also decreased the interest margin to LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and reduced the commitment fee to a range of 0.375% to 0.5% based on borrowing base utilization. The borrowing base was re-determined on May 1, 2012, with a borrowing base of $900.0 million and commitments of $900.0 million based on December 31, 2011 proved reserves, hedge position, senior debt outstanding and lender commodity price benchmarks. Future borrowing bases will be computed based on proved oil and natural gas reserves, hedge position and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company. Our borrowing capacity was reduced by $26.0 million to $874.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

Cash Flow from Operating Activities

Net cash provided by operating activities for the six months ended June 30, 2012 and 2011 was $179.2 million and $211.2 million, respectively. Cash provided by operating activities decreased primarily due to lower commodity prices and higher cash operating expenses, including lease operating expense and gathering, and transportation and processing expense.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, 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.

To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL 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 oil and natural gas production revenue. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. 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, 2012, we had in place crude oil financial swaps covering portions of our 2012, 2013 and 2014 production, crude oil financial collars covering portions of our 2012 production, natural gas swaps covering portions of our 2012, 2013 and 2014 production revenue, basis only swaps covering portions of our 2012 production, and NGL swaps covering portions of our 2012 and 2013 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of natural gas that have varying terms and pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to 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. Before discontinuing hedge accounting effective January 1, 2012, derivative instruments that qualified and were designated as cash flow hedges, changes in fair value, to the extent the hedges are effective, were recognized in AOCI until the forecasted transaction occurs. The ineffective portion of hedge derivatives was reported in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. Realized gains and losses on cash flow hedges were 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 occurred.

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We discontinued hedge accounting effective January 1, 2012. Therefore, the commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations was comprised of changes in the derivative’s fair value for all discontinued cash flow hedges. As a result of discontinuing hedge accounting effective January 1, 2012, the mark-to-market value of all commodity hedge instruments within AOCI at December 31, 2011 were frozen in AOCI as of the de-designation date, January 1, 2012, and will be reclassified into earnings in future periods as the original hedged transactions affect earnings. As such, subsequent to January 1, 2012, we have recognized unrealized gains and losses from prospective changes in commodity derivative fair values immediately in the Unaudited Consolidated Statements of Operations in the commodity derivative gain (loss) line item rather than deferring any such amounts in AOCI. The commodity derivative gain (loss) line item on the Unaudited Consolidated Statements of Operations also includes realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as cash flow hedges. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item. This change in reporting had no impact on our reported cash flows, although future results of operations will be affected by unrealized gains and losses, which fluctuate with volatile oil and gas prices.

In addition, 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. Our basis only swaps were not designated as cash flow hedges, and the 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 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, 2012, the estimated fair value of all of our commodity derivative instruments was a net asset of $106.1 million, comprised of current and noncurrent assets and noncurrent liabilities. We will reclassify the appropriate cash flow hedge amounts from AOCI, related to hedges designated as cash flow hedges prior to January 1, 2012, to gains and losses included in oil and natural gas production operating revenues as the hedged production quantities are produced. As a result of its election to discontinue cash flow hedge accounting effective January 1, 2012, the Company did not have any derivatives designated as cash flow hedging instruments at June 30, 2012.

The table below summarizes the realized and unrealized gains and losses that we recognized related to our oil and natural gas derivative instruments for the periods indicated:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	(in thousands)
Realized gain on derivatives designated as cash flow hedges(1)	$	20,798	$	19,776		$	46,263	$	47,699
Realized gain (loss) on derivatives not designated as cash flow hedges(2)	$	18,916	$	(8,590	)	$	22,719	$	(13,994	)
Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges(2)		0		888			0		1,050
Unrealized gain (loss) on derivatives not designated as cash flow hedges(2)		28,108		4,795			69,052		(1,075	)
Total commodity derivative gain (loss)	$	47,024	$	(2,907	)	$	91,771	$	(14,019	)

(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, 2012:

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:
2012
Oil		73,600	Bbls	$	92.50	$	131.30		N/A		N/A		WTI	$	644
Swap Contracts:
2012
Natural gas		8,135,000	MMBtu		N/A		N/A	$	4.68		N/A		CIG		16,199
Natural gas		26,055,000	MMBtu		N/A		N/A	$	3.91		N/A		NWPL		29,292
Natural gas liquids(3)		15,000,000	Gallons		N/A		N/A	$	1.69		N/A		Mt. Belvieu		7,469
Oil		901,600	Bbls		N/A		N/A	$	101.72		N/A		WTI		13,974
2013
Natural gas		1,825,000	MMBtu		N/A		N/A	$	5.01		N/A		CIG		2,982
Natural gas		46,630,000	MMBtu		N/A		N/A	$	3.63		N/A		NWPL		9,835
Natural gas liquids(3)		9,000,000	MMBtu		N/A		N/A	$	1.78		N/A		NWPL		3,735
Oil		1,679,000	Bbls		N/A		N/A	$	100.40		N/A		WTI		19,821
2014
Natural gas		16,425,000	MMbtu		N/A		N/A	$	3.79		N/A		NWPL		34
Oil		438,000	Bbls		N/A		N/A	$	101.54		N/A		WTI		5,817
Basis Only Swap Contracts(2):
2012
Natural gas		1,840,000	MMBtu		N/A		N/A		N/A	$	(1.24	)	NWPL		(1,950	)
Natural gas		1,840,000	MMBtu		N/A		N/A		N/A	$	(1.20	)	CIG		(1,793	)
Total														$	106,059

The following table includes all hedges entered into subsequent to June 30, 2012 through July 20, 2012:

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:

2013

Oil

182,500

Bbls

N/A

N/A

$

90.70

N/A

WTI

2014

Natural gas

1,825,000

MMbtu

N/A

N/A

$

3. 83

N/A

NWPL

Oil

182,500

Bbls

N/A

N/A

$

90.50

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

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

By removing the price volatility from a portion of our oil, natural gas and NGL related revenue for 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. Derivative financial instruments that hedge the price of oil and gas are generally executed with major financial or commodities trading institutions that expose us to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. It is our policy to enter into derivative contracts with counterparties that are lenders under our Amended Credit Facility, affiliates of lenders in our Amended Credit Facility or potential lenders in our Amended Credit Facility. Two counterparties that were lenders in the Amended Credit Facility withdrew from the facility when we amended the facility in

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October 2011. We will continue to monitor the creditworthiness of these two counterparties during the remaining duration of the derivatives that were entered into while they were lenders in the Amended Credit Facility. Furthermore, where the counterparty is a lender, in the event of an insolvency of such counterparty our hedging agreements and applicable law permit us to set-off amounts we owe under the Amended Credit Facility against amounts owed to us by such counterparty under such hedging agreements. Where the counterparty is not a lender (rather an affiliate of a lender) and the counterparty’s obligations are not guaranteed by a lender, such set off may not be enforceable by a bankruptcy court even where the relevant agreement provides for it.

Capital Expenditures

Our capital expenditures are summarized in the following tables for the periods indicated:

	Six Months Ended June 30,
Basin/Area	2012		2011
	(in millions)
Piceance	$	148.6	$	94.4
Uinta – West Tavaputs		77.9		112.3
Uinta Oil Program		151.4		166.7
DJ Basin		56.3		6.4
Powder River – CBM		0.1		3.5
Powder River Deep		18.0		18.9
Wind River Basin		0.3		1.5
Paradox		10.3		0.9
Other		19.4		3.4
Total	$	482.3	$	408.0
	Six Months Ended June 30,
	2012		2011
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	54.0	$	129.3
Drilling, development, exploration and exploitation of oil and natural gas Properties(1)		420.0		273.8
Geologic and geophysical costs		4.5		2.0
Furniture, fixtures and equipment		3.8		2.9
Total	$	482.3	$	408.0

(1) Includes related gathering and facilities costs.

Our current estimate for a capital expenditure budget in 2012 is $850.0 million to $900.0 million for exploratory and development programs including facilities costs and excluding acquisitions. Capital expenditures may be adjusted throughout the year as business conditions and operating results warrant. If we are successful in exploration activities or overcoming legal and regulatory hurdles, we may consider increasing our capital budget. We believe that we have sufficient available liquidity through 2012 with the Amended Credit Facility, our hedge positions and cash flow from operations to fund our budgeted capital expenditures. However, future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs.

The amount, timing and allocation of capital expenditures is generally discretionary and within our control. 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. If oil and natural gas 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. A substantial or extended decline in oil or natural gas prices may result in impairments of our oil and gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, we will be required to reduce spending or to fund that shortfall through borrowings under our Amended Credit Facility or from sales of properties or debt or equity financings, which may not be on advantageous terms in low commodity price environments.

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Financing Activities

Amended Credit Facility

On October 18, 2011, the Company amended the Amended Credit Facility, to extend the maturity date to October 31, 2016. The amended interest margin is LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee ranges from 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 1.7% and 2.7% for the three months ended June 30, 2012 and June 30, 2011, respectively. The average annual interest rates incurred on the Amended Credit Facility were 1.8% and 2.7% for the six months ended June 30, 2012 and June 30, 2011, respectively. As of June 30, 2012, the Company had a balance of $75.0 million outstanding under the Amended Credit Facility.

The borrowing base is required to be re-determined twice per year. The borrowing base was re-determined on May 1, 2012, with a borrowing base of $900.0 million and commitments of $900.0 million based on December 31, 2011 proved reserves, hedge position, senior debt outstanding and lender commodity price benchmarks. Future borrowing bases will be computed based on proved oil and natural gas reserves, hedge position and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company. The Amended Credit Facility is secured by oil and natural gas 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 is currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods. 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 reduces the current borrowing capacity of the Amended Credit Facility by $26.0 million to $874.0 million.

9.875% Senior Notes Due 2016

The 9.875% Senior Notes have an aggregate principal amount of $250.0 million, 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. The 9.875% Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 each year. The 9.875% Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The 9.875% 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

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. As of January 1, 2009 with the adoption of new authoritative accounting guidance under FASB ASC subtopic 470-20,Debt with Conversion Options, the Company recorded a debt discount of $23.1 million, which represented the fair value of the equity conversion feature as of the date of the issuance of the Convertible Notes. The value of the equity conversion feature was also recorded as APIC, net of $8.6 million of deferred taxes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. The Company settled the notes in cash and recognized a gain on extinguishment of $1.6 million after completing a fair value analysis of the cash consideration transferred to holders of the Convertible Notes compared to the fair value of the Convertible Notes that were redeemed. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. 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, are senior in right of payment to all of the Company’s future subordinated indebtedness, and are effectively subordinated to all of the Company’s secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company’s subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the 9.875% Senior Notes, the 7.625% Senior Notes and the 7.0% Senior Notes.

The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company has the right with at least 30 days’ notice to call the Convertible Notes.

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For the remainder of the Convertible Notes outstanding, the conversion price is approximately $66.33 per share of the Company’s common stock, equal to the applicable conversion rate of 15.0761 shares of common stock, subject to adjustment, for each $1,000 of the principal amount of the Convertible Notes. Upon conversion of the Convertible Notes, holders will receive, at the Company’s election, cash, shares of common stock or a combination of cash and shares of common stock. If the conversion value exceeds $1,000, the Company will also deliver, at its election, cash, shares of common stock or a combination of cash and shares of common stock with respect to the remaining value deliverable upon conversion.

7.625% Senior Notes Due 2019

The 7.625% Senior Notes have an aggregate principal amount of $400.0 million and 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. The 7.625% Senior Notes will mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The 7.625% 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.

7.0% Senior Notes Due 2022

On March 12, 2012, the Company issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes will mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year beginning October 15, 2012. The Company received net proceeds of $392.0 million (net of related offering costs), which were used to repay the outstanding balance under the Amended Credit Facility, settle the Convertible Notes that were redeemed by the Company and for general corporate purposes. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes, the 9.875% Senior Notes and the 7.625% Senior Notes. The 7.0% 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 since issuance.

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

		As of June 30, 2012								As of December 31, 2011
	Maturity Date	Principal			Unamortized Discount			Carrying Amount		Principal		Unamortized Discount			Carrying Amount
Amended Credit Facility(1)	October 31, 2016	$	75,000		$	0		$	75,000	$	70,000	$	0		$	70,000
9.875% Senior Notes(2)	July 15, 2016		250,000			(8,027	)		241,973		250,000		(8,802	)		241,198
Convertible Notes(3)	March 15, 2028 (4)		25,344	(7)		0			25,344		172,500		(1,458	)		171,042
7.625% Senior Notes(5)	October 1, 2019		400,000			0			400,000		400,000		0			400,000
7.0% Senior Notes(6)	October 15, 2022		400,000	��		0			400,000		0		0			0
Total Long-Term Debt		$	1,150,344		$	(8,027	)	$	1,142,317	$	892,500	$	(10,260	)	$	882,240

(1) The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure.

(2) The aggregate estimated fair value of the 9.875% Senior Notes was approximately $274.4 million as of June 30, 2012 based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the Convertible Notes was approximately $23.6 million as of June 30, 2012. 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.

(4) The Company has the right with at least 30 days’ notice to call the Convertible Notes and the holders have the right to require the Company to purchase the notes on each of March 20, 2015, March 20, 2018 and March 20, 2023.

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(5) The aggregate estimated fair value of the 7.625% Senior Notes was approximately $400.0 million as of June 30, 2012 based on reported market trades of these instruments.

(6) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $380.5 million as of June 30, 2012 based on reported market trades of these instruments.

(7) Balance represents the remaining principal for the Convertible Notes after the Company’s redemption of $147.2 million principal amount of Convertible Notes on March 20, 2012.

Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, Convertible Notes, the 9.875% Senior Notes, 7.625% Senior Notes or the 7.0% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Shelf Registration Statement.On June 28, 2012 we filed with the SEC a new universal shelf registration statement to allow us to offer an indeterminate amount of 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, we recognize that 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.

Contractual Obligations.A summary of our contractual obligations as of and subsequent to June 30, 2012 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	$	553	$	553	$	75,553	$	460	$	78,225
9.875% Senior Notes(2)		24,688		24,688		24,688		24,688		251,029		0		349,781
7.625% Senior Notes(3)		30,500		30,500		30,500		30,500		30,500		468,625		621,125
7.0% Senior Notes(4)		28,000		28,000		28,000		28,000		28,000		548,167		688,167
Convertible Notes(5)		1,267		1,267		26,277		0		0		0		28,811
Purchase commitments(6)(7)		7,118		0		0		0		0		0		7,118
Drilling rig commitments(7)(8)		22,214		0		0		0		0		0		22,214
Office and office equipment leases and other(9)		3,528		3,613		3,075		2,536		2,496		4,436		19,684
Firm transportation and processing agreements(7)(10)		62,115		62,035		61,766		60,184		56,468		169,763		472,331
Asset retirement obligations(11)		1,076		2,964		160		462		339		66,120		71,121
Derivative liability(12)		0		59		0		0		0		0		59
Total	$	181,059	$	153,679	$	175,019	$	146,923	$	444,385	$	1,257,571	$	2,358,636

(1) Included in notes payable is the outstanding principal amount under our Amended Credit Facility due October 31, 2016. 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.

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(2) On July 8, 2009, we issued $250.0 million aggregate principal amount of 9.875% Senior Notes. We are obligated to make annual interest payments through maturity in 2016 equal to $24.7 million.

(3) On September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. We are obligated to make annual interest payments through maturity in 2019 equal to $30.5 million.

(4) On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make annual interest payments through maturity in 2022 equal to $28.0 million.

(5) On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012 approximately 85% of the outstanding Convertible Notes, representing $147.2 million of the then outstanding principal amount, were put to the Company. The Company settled the notes in cash and recognized a gain on extinguishment of $1.6 million after completing a fair value analysis of the consideration transferred to holders of the Convertible Notes. After the redemption in March 2012, $25.3 million principal amount of the Convertible Notes is currently outstanding. We are obligated to make semi-annual interest payments on the Convertible Notes until either the Company calls the remaining Convertible Notes or the holders put the Convertible Notes to the Company, which is expected to occur by 2015.

(6) We have one take-or-pay carbon dioxide purchasing agreement that was amended in July 2012 and expires in December 2015. The agreement imposes a minimum volume commitment to purchase CO2 at a contracted price. The contract provides 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. Under contract amendment in July 2012, $2.3 million of the future commitment is due by December 2012 and the remaining $4.8 million is due by December 31, 2015 if minimum volume commitments are not met.

(7) 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.

(8) We currently have five drilling rigs under contract. Three expire in 2012 and two expire in 2013. These contracts may be terminated but we would be required to pay a penalty of $13.9 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.

(9) The lease for our principal offices in Denver, Colorado extends through March 2019.

(10) 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 12 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.

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

(12) Derivative liabilities represent the net fair value for oil and gas commodity derivatives presented as liabilities in our Unaudited Consolidated Balance Sheets as of June 30, 2012. 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, 2011 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.

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, 2011 for a discussion of trends and uncertainties that may affect our financial condition or liquidity.

A substantial or extended decline in oil or natural gas prices may result in impairments of our oil and gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures; we will be required to reduce spending or to fund that shortfall through borrowings under our Amended Credit Facility or from sales of properties or debt or equity financings, which may not be on advantageous terms in low commodity price environments. Through commodity derivatives, we have protected the cash flow from approximately 70% of our anticipated 2012 production, 45% of our anticipated 2013 production, and approximately 15% of our anticipated 2014 production.However, our ability to hedge at price levels similar to those for prior years is unlikely given current futures prices, which will likely result in a decline in our revenue per unit of production.

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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, 2011 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 oil and natural gas 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 oil, natural gas and NGLs 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, 2012, our annual income before income taxes would have decreased by approximately $0.2 million for each $1.00 per barrel decrease in crude oil prices and by approximately $2.2 million for each $0.10 decrease per MMBtu in natural gas prices. The Company is more susceptible to proved and unproved property impairments due to the current commodity price environment.

We routinely enter into commodity 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 commodity hedging activities are intended to support oil and natural gas prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil and natural gas price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, subject to the risk that our counterparty will be unable to perform its obligations under the 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 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 20, 2012, we have financial derivative instruments related to oil, natural gas and NGL volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities.”

	July– December 2012		For the year 2013		For the year 2014
Oil (Bbls)		975,200		1,861,500		620,500
Natural Gas (MMbtu)		34,190,000		48,455,000		18,250,000
Natural Gas Basis (MMbtu)		3,680,000		0		0
Natural Gas Liquids (Gallons)		15,000,000		9,000,000		0

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Interest Rate Risks

At June 30, 2012, the outstanding principal balance under our Amended Credit Facility was $75.0 million, which bears interest at floating rates. Therefore the average annual interest rate incurred on this debt for the six months ended June 30, 2012 was 1.8%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2012 would have resulted in an estimated $0.3 million increase in interest expense assuming a similar average debt level to the six months ended June 30, 2012. The average annual interest rate incurred on this debt for the six months ended June 30, 2011 was 2.7%. 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. We also had $25.3 million principal amount of Convertible Notes (with a fixed cash interest rate of 5%), $250.0 million principal amount of 9.875% Senior Notes, $400.0 million principal amount of 7.625% Senior Notes and $400.0 million principal amount of 7.0% Senior Notes outstanding at June 30, 2012.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of June 30, 2012, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of June 30, 2012.

Changes in Internal Controls.There has been no change in our internal control over financial reporting during the second fiscal quarter of 2012 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.

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, 2011. 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 Annual Report on Form 10-K for the year ended December 31, 2011 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.

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, 2012:

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, 2012		424	$	22.59		0		0
May 1 – 31, 2012		1,384		22.91		0		0
June 1 – 30, 2012		78		16.16		0		0
Total		1,886	$	22.56		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 4. Mine Safety Disclosures

Not applicable

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Item 5. Other Information.

In June 2011, the Financial Accounting Standards Board issued guidance on the presentation of comprehensive income in financial statements. Entities are required to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements. We adopted this standard effective January 1, 2012 and will present net income and other comprehensive income in two separate statements in our annual financial statements. The table below reflects the retrospective application of this guidance for each of the periods presented below. The retrospective application did not have a material impact on our financial condition or results of operations.

	Year Ended December 31,
	2011		2010			2009
	(in thousands, except share and per share amounts)
Net Income	$	30,707	$	80,502		$	50,218
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		8,215		(6,581	)		(137,662	)
Other comprehensive income (loss)		8,215		(6,581	)		(137,662	)
Comprehensive Income (Loss)	$	38,922	$	73,921		$	(87,444	)

The following will be added to the Condensed Consolidated Financial Statements included in the financial statements of Subsidiary Guarantors Note to our annual financial statements:

Condensed Consolidating Statements of Comprehensive Income (Loss)
	Year Ended December 31, 2011
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	30,707		$	(39,912	)	$	39,912	$	30,707
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		8,215			0			0		8,215
Other comprehensive income		8,215			0			0		8,215
Comprehensive income	$	38,922		$	(39,912	)	$	39,912	$	38,922
	Year Ended December 31, 2010
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	80,502		$	(2,802	)	$	2,802	$	80,502
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		(6,581	)		0			0		(6,581	)
Other comprehensive income (loss)		(6,581	)		0			0		(6,581	)
Comprehensive income	$	73,921		$	(2,802	)	$	2,802	$	73,921
	Year Ended December 31, 2009
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	50,218		$	(5,225	)	$	5,225	$	50,218
Other Comprehensive Income, net of tax:
Effect of derivative financial instruments		(137,662	)		0			0		(137,662	)
Other comprehensive income (loss)		(137,662	)		0			0		(137,662	)
Comprehensive income (loss)	$	(87,444	)	$	(5,225	)	$	5,225	$	(87,444	)

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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 A of our Definitive Proxy Statement filed with the Commission on April 4, 2012.]
3.2	Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed with the Commission on May 15, 2012.]
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 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 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 our 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 filed with the Commission on July 8, 2009.]
4.3(c)	Third Supplemental Indenture, dated September 27, 2011, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC, GB Acquisition Corporation, Elk Production, LLC, Aurora Gathering, LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 7.625% Senior Notes due 2019). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on September 27, 2011.]
4.3(d)	Fourth Supplemental Indenture for the Company’s 7% Senior Notes due 2022, dated March 12, 2012, among the Company, the Subsidiary Guarantors and the Trustee. [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2012.]
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.]

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4.6	Form of Right Certificate. [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.]
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, 2012 (and related periods), formatted in XBRL (eXtensible Business Reporting Language) include (i) the Unaudited Consolidated Balance Sheets, (ii) the Unaudited Consolidated Statements of Operations, (iii) the Unaudited Consolidated Statements of Stockholders’ Equity, (iv) the Unaudited Consolidated Statements of Cash Flows, and (v) Notes to the Unaudited Consolidated Financial Statements.*

* 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 2, 2012	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors, Chief Executive Officer and President
		(Principal Executive Officer)
Date: August 2, 2012	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer and Treasurer
		(Principal Financial Officer)

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