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 September 30, 2013

OR

o 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    o  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    o  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	o
Non-accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	o

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

There were 48,985,749shares of $0.001 par value common stock outstanding on October 18, 2013.

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	30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	48
Item 4.	Controls and Procedures	49
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 3.	Defaults Upon Senior Securities	50
Item 4.	Mine Safety Disclosures	50
Item 5.	Other Information	50
Item 6.	Exhibits	50
SIGNATURES		53

2

PART I. FINANCIAL INFORMATION

ITEM 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2013			December 31, 2012
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	60,530		$	79,445
Accounts receivable, net of allowance for doubtful accounts	99,537			112,011
Derivative assets	3,506			29,980
Prepayments and other current assets	5,478			6,903
Total current assets	169,051			228,339
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	2,675,696			3,331,267
Unproved oil and gas properties, excluded from amortization	362,386			457,207
Oil and gas properties held for sale, net	382,554			—
Furniture, equipment and other	42,252			45,636
	3,462,888			3,834,110
Accumulated depreciation, depletion, amortization and impairment	(929,743		)	(1,222,773		)
Total property and equipment, net	2,533,145			2,611,337
Deferred financing costs and other noncurrent assets	24,065			29,773
Total	$	2,726,261		$	2,869,449
Liabilities and Stockholders’ Equity:
Current liabilities:
Accounts payable and accrued liabilities	$	123,409		$	125,017
Amounts payable to oil and gas property owners	22,367			19,663
Production taxes payable	41,803			45,624
Derivative liabilities	2,271			—
Deferred income taxes	11,833			13,752
Current portion of long-term debt	4,554			9,077
Total current liabilities	206,237			213,133
Long-term debt	1,255,243			1,156,654
Asset retirement obligations	38,292			46,050
Liabilities associated with assets held for sale	59,445			—
Deferred income taxes	156,034			266,364
Derivatives and other noncurrent liabilities	4,012			4,473
Stockholders’ equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 48,985,320 and 48,150,475 shares issued and outstanding at September 30, 2013 and December 31, 2012, respectively, with 1,393,438 and 870,794 shares subject to restrictions, respectively	48			47
Additional paid-in capital	897,367			883,923
Retained earnings	107,939			293,473
Treasury stock, at cost: zero shares at September 30, 2013 and December 31, 2012, respectively	—			—
Accumulated other comprehensive income	1,644			5,332
Total stockholders’ equity	1,006,998			1,182,775
Total	$	2,726,261		$	2,869,449

See notes to Unaudited Consolidated Financial Statements.

3

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands, except share and per share data)
Operating and Other Revenues:
Oil, gas and NGL production	$	149,345		$	180,024		$	424,130		$	516,556
Other	(790		)	842			5,001			3,838
Total operating and other revenues	148,555			180,866			429,131			520,394
Operating Expenses:
Lease operating expense	18,280			17,003			53,138			54,671
Gathering, transportation and processing expense	16,374			26,725			50,734			79,939
Production tax expense	8,183			8,094			21,915			21,193
Exploration expense	(24		)	3,562			212			8,063
Impairment, dry hole costs and abandonment expense	219,363			38,540			227,646			60,179
Depreciation, depletion and amortization	72,047			91,392			214,792			251,417
General and administrative expense	14,402			17,965			48,257			51,441
Total operating expenses	348,625			203,281			616,694			526,903
Operating Loss	(200,070		)	(22,415		)	(187,563		)	(6,509		)
Other Income and Expense:
Interest and other income	52			53			123			128
Interest expense	(20,078		)	(24,527		)	(69,346		)	(70,029		)
Commodity derivative gain (loss)	(25,595		)	(38,340		)	(18,607		)	53,431
Gain (loss) on extinguishment of debt	(21,460		)	—			(21,460		)	1,601
Total other income and expense	(67,081		)	(62,814		)	(109,290		)	(14,869		)
Loss before Income Taxes	(267,151		)	(85,229		)	(296,853		)	(21,378		)
Benefit from Income Taxes	(100,495		)	(32,603		)	(111,319		)	(7,943		)
Net Loss	$	(166,656	)	$	(52,626	)	$	(185,534	)	$	(13,435	)
Net Loss Per Common Share, Basic	$	(3.51	)	$	(1.11	)	$	(3.91	)	$	(0.28	)
Net Loss Per Common Share, Diluted	$	(3.51	)	$	(1.11	)	$	(3.91	)	$	(0.28	)
Weighted Average Common Shares Outstanding, Basic	47,535,124			47,230,473			47,452,865			47,172,656
Weighted Average Common Shares Outstanding, Diluted	47,535,124			47,230,473			47,452,865			47,172,656

See notes to Unaudited Consolidated Financial Statements.

4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Net Loss	$	(166,656	)	$	(52,626	)	$	(185,534	)	$	(13,435	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(1,186		)	(12,739		)	(3,688		)	(41,644		)
Other comprehensive loss	(1,186		)	(12,739		)	(3,688		)	(41,644		)
Comprehensive Loss	$	(167,842	)	$	(65,365	)	$	(189,222	)	$	(55,079	)

See notes to Unaudited Consolidated Financial Statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2013			2012
	(in thousands)
Operating Activities:
Net Loss	$	(185,534	)	$	(13,435	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	214,792			251,417
Deferred income tax benefit	(110,036		)	(7,669		)
Impairment, dry hole costs and abandonment expense	227,646			60,179
Total commodity derivative (gain) loss	18,607			(53,431		)
Settlements of commodity derivatives	2,971			35,014
Stock compensation and other non-cash charges	12,681			14,249
Amortization of debt discounts and deferred financing costs	4,535			6,710
(Gain) loss on extinguishment of debt	21,460			(1,601		)
Gain on sale of properties	(3,102		)	(108		)
Change in operating assets and liabilities:
Accounts receivable	12,343			4,475
Prepayments and other assets	1,475			1,515
Accounts payable, accrued and other liabilities	(24,801		)	(4,813		)
Amounts payable to oil and gas property owners	6,510			567
Production taxes payable	(3,245		)	(2,466		)
Net cash provided by operating activities	196,302			290,603
Investing Activities:
Additions to oil and gas properties, including acquisitions	(335,597		)	(751,545		)
Additions of furniture, equipment and other	(1,506		)	(5,519		)
Proceeds from sale of properties and other investing activities	784			91
Net cash used in investing activities	(336,319		)	(756,973		)
Financing Activities:
Proceeds from debt	390,000			785,826
Principal and redemption premium payments on debt	(269,125		)	(343,163		)
Proceeds from stock option exercises	1,653			672
Deferred financing costs and other	(1,426		)	(10,363		)
Net cash provided by financing activities	121,102			432,972
Decrease in Cash and Cash Equivalents	(18,915		)	(33,398		)
Beginning Cash and Cash Equivalents	79,445			57,331
Ending Cash and Cash Equivalents	$	60,530		$	23,933

See notes to Unaudited Consolidated Financial Statements.

6

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 at December 31, 2011	$	47	$	869,856		$	292,891		$	—		$	56,044		$	1,218,838
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	—		673			—			(2,513		)	—			(1,840		)
APIC pool for excess tax benefits related to share-based compensation	—		32			—			—			—			32
Stock-based compensation	—		16,874			—			—			—			16,874
Retirement of treasury stock	—		(2,513		)	—			2,513			—			—
Settlement of convertible notes	—		(999		)	—			—			—			(999		)
Net income	—		—			582			—			—			582
Effect of derivative financial instruments, net of $30,458 of taxes	—		—			—			—			(50,712		)	(50,712		)
Balance at December 31, 2012	$	47	$	883,923		$	293,473		$	—		$	5,332		$	1,182,775
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	1		1,652			—			(1,415		)	—			238
Stock-based compensation	—		13,207			—			—			—			13,207
Retirement of treasury stock	—		(1,415		)	—			1,415			—			—
Net loss	—		—			(185,534		)	—			—			(185,534		)
Effect of derivative financial instruments, net of $2,216 of taxes	—		—			—			—			(3,688		)	(3,688		)
Balance at September 30, 2013	$	48	$	897,367		$	107,939		$	—		$	1,644		$	1,006,998

See notes to Unaudited Consolidated Financial Statements.

7

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2013

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, natural gas and natural gas liquids (“NGLs”). 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 include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

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, natural gas and NGL 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 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.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of September 30, 2013			As of December 31, 2012
	(in thousands)
Accrued oil, gas and NGL sales	$	68,013		$	69,482
Due from joint interest owners	28,489			36,300
Other	3,058			6,554
Allowance for doubtful accounts	(23		)	(325		)
Total accounts receivable	$	99,537		$	112,011

Oil and Gas Properties. The Company’s oil, gas and NGL 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 and are included within additions to oil and gas properties within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows when incurred. The costs of development wells are capitalized whether proved reserves are added or not. Oil and gas lease acquisition costs are also capitalized.

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

8

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, natural gas and NGL producing activities:

	As of September 30, 2013			As of December 31, 2012
	(in thousands)
Proved properties	$	422,083		$	387,242
Wells and related equipment and facilities	2,080,178			2,625,891
Support equipment and facilities	163,242			304,914
Materials and supplies	10,193			13,220
Total proved oil and gas properties	$	2,675,696		$	3,331,267
Unproved properties	307,557			384,486
Wells and facilities in progress	54,829			72,721
Total unproved oil and gas properties, excluded from amortization	$	362,386		$	457,207
Oil and gas properties held for sale, net (1)	378,449			—
Accumulated depreciation, depletion, amortization and impairment	(907,222		)	(1,203,495		)
Total oil and gas properties, net	$	2,509,309		$	2,584,979

(1) The oil and gas properties held for sale balance shown in this table is different from the balance on the Unaudited Consolidated Balance Sheet because it does not include $4.1 million of furniture, equipment and other, net.

All exploratory wells are evaluated for economic viability within one year of well completion. 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 September 30, 2013 and December 31, 2012, there were no exploratory well costs that had been capitalized for a period greater than one year since the completion of drilling.

The Company reviews proved oil and gas properties on a field-by-field basis for impairment on an annual basis or 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 will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors. The Company has no guarantee that the undiscounted future cash flows analysis of its proved property represents the applicable market value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The Company recognized non-cash impairment charges, which were included within impairment, dry hole costs and abandonment expense in the Unaudited Consolidated Statements of Operations, as follows:

9

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013		2012
	(in thousands)
Non-cash impairment of proved oil and gas properties (1)	$	198,787		$	—	$	198,787	$	—
Non-cash impairment of unproved oil and gas properties (2) (3)	17,777			18,772		17,777		37,109
Dry hole costs	(36		)	15,658		928		15,891
Abandonment expense	2,835			4,110		10,154		7,179
Total non-cash impairment, dry hole costs and abandonment expense	$	219,363		$	38,540	$	227,646	$	60,179

(1) Non-cash impairment of proved oil and gas properties for the three and nine months ended September 30, 2013 related to assets classified as held for sale at September 30, 2013. The impairment was the result of an analysis of the carrying value of the related properties relative to their estimated fair values.

(2) Non-cash impairment of unproved oil and gas properties for the three and nine months ended September 30, 2013 was comprised of $15.3 million related to certain unproved oil and gas properties within exploration projects primarily as a result of no future plans to evaluate the remaining acreage and an estimated market value below our carrying value and $2.5 million related to unproved properties held for sale at September 30, 2013.

(3) Non-cash impairment of unproved oil and gas properties for the three months ended September 30, 2012 of $18.8 million related to certain unproved oil and gas properties within exploration projects primarily as a result of unfavorable natural gas exploratory results, unfavorable market conditions or no future plans to evaluate the remaining acreage. The additional $18.3 million unproved oil and gas properties impairment expense for the nine months ended September 30, 2012 also related to unproved oil and gas properties within other exploration and development projects primarily as a result of unfavorable market conditions or no future 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 and NGLs are converted to natural gas equivalents, Mcfe, at the standard 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:

	As of September 30, 2013		As of December 31, 2012
	(in thousands)
Accrued drilling, completion and facility costs	$	63,618	$	42,094
Accrued lease operating, gathering, transportation and processing expenses	19,481		16,862
Accrued general and administrative expenses	8,542		13,054
Trade payables and other	31,768		53,007
Total accounts payable and accrued liabilities	$	123,409	$	125,017

Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.

Revenue Recognition. The Company records revenues from the sales of crude oil, natural gas and NGLs when delivery to the purchaser has occurred. The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenue is recorded on the basis of gas and NGLs actually sold by the Company. In addition, the Company records revenues for its share of gas and NGLs sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenues for other owners’ gas and NGLs sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under- produced gas and NGLs balancing positions are considered in the Company’s proved oil, gas and NGL reserves. Imbalances at September 30, 2013 and December 31, 2012 were not material.

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 NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities.

10

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

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized.

Earnings/Loss Per Share. Basic net loss per common share is calculated by dividing net loss attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net loss per common share is calculated by dividing net loss 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. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and nine months ended September 30, 2013 and 2012.

In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. As of September 30, 2013, 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 March 20, 2015. The Convertible Notes have not been dilutive since their issuance in March 2008 and, therefore, did not impact the diluted net loss per common share calculation for the three and nine months ended September 30, 2013 and 2012. The diluted net loss per common share excludes the anti-dilutive effect of 2,450,539 and 3,799,612 shares of stock options and nonvested equity shares of common stock for the three months ended September 30, 2013 and 2012, respectively, and 2,731,578 and 3,829,825 shares of stock options and nonvested equity shares of common stock for the nine months ended September 30, 2013 and 2012, respectively.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands, except per share amounts)
Net loss	$	(166,656	)	$	(52,626	)	$	(185,534	)	$	(13,435	)
Basic weighted-average common shares outstanding in period	47,535			47,230			47,453			47,173
Add dilutive effects of stock options and nonvested equity shares of common stock	—			—			—			—
Diluted weighted-average common shares outstanding in period	47,535			47,230			47,453			47,173
Basic net loss per common share	$	(3.51	)	$	(1.11	)	$	(3.91	)	$	(0.28	)
Diluted net loss per common share	$	(3.51	)	$	(1.11	)	$	(3.91	)	$	(0.28	)

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

New Accounting Pronouncements. In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-1, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which amended FASB Accounting Standards Codification (“ASC”) Topic 210, Balance Sheet. The main objective in developing this update was to address implementation issues about the scope of ASU 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities. The amendments clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar

11

agreement. This provision is effective for fiscal years beginning on or after January 1, 2013. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

In February 2013, the FASB issued ASU 2013-2, Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which amended ASC Topic 220, Comprehensive Income. The objective of this update was to improve the reporting of reclassifications out of accumulated other comprehensive income. The amendment did not change the requirements for reporting net income or other comprehensive income in financial statements. However, the amendment required an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This provision is effective for interim and annual periods beginning after December 15, 2012. Adoption of this update did not have a material impact on the Company’s disclosures or financial statements.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Nine Months Ended September 30,
	2013			2012
	(in thousands)
Cash paid for interest, net of amount capitalized	$	61,796		$	49,040
Cash paid for income taxes	1,861			11
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities	75,265			75,092
Net increase in asset retirement obligations	2,924			280
Retirement of treasury stock	(1,415		)	(2,430		)

4. Divestitures and Assets Held For Sale

Divestitures

On December 31, 2012, the Company completed the sale of natural gas assets including 100% of its Wind River Basin, 100% of the Powder River Basin coalbed methane assets, and a non-operating working interest in its Gibson Gulch-Piceance Basin development property (the “2012 Divestiture”). The Company received $325.3 million in cash proceeds and recognized a $4.5 million pre-tax loss included in other operating revenues for the year ended December 31, 2012. The final 2012 Divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized during 2013.

Assets Held for Sale

During the third quarter of 2013, the Company began marketing the West Tavaputs natural gas assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale on the Unaudited Consolidated Balance Sheet as of September 30, 2013. Upon the classification as held for sale, the carrying value of the related properties was analyzed in relation to the estimated fair value. As a result, we recognized $198.8 million of proved property impairment expense and $2.5 million of unproved property impairment expense during the three months ended September 30, 2013. As part of the previously announced sale of the West Tavaputs natural gas assets in the Uinta Basin (the “West Tavaputs Sale”), the purchaser will assume approximately 51% of the Company's lease financing arrangement with Bank of America Leasing & Capital, LLC as the lead bank that relates to compressor units on the West Tavaputs property (the “Lease Financing Obligation”.) See the table below for detail of the assets held for sale included on the Unaudited Consolidated Balance Sheet:

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	As of September 30, 2013
	(in thousands)
Assets
Proved properties	$	1,070,400
Unproved properties	12,469
Furniture, equipment and other	4,205
Accumulated depreciation, depletion, amortization and impairment	(704,520		)
Total assets held for sale	$	382,554
Liabilities
Asset retirement obligation held for sale	13,082
Lease financing obligation held for sale	46,363
Total liabilities held for sale	$	59,445
Net assets	$	323,109

5. Long-Term Debt

The Company’s outstanding debt is summarized below:

		As of September 30, 2013						As of December 31, 2012
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount			Carrying Amount
		(in thousands)
Amended Credit Facility (1)	October 31, 2016	$	390,000	$	—	$	390,000	$	—	$	—		$	—
9.875% Senior Notes (2)	July 15, 2016	—		—		—		250,000		(7,209		)	242,791
Convertible Notes (3)	March 15, 2028 (4)	25,344		—		25,344		25,344		—			25,344
7.625% Senior Notes (5)	October 1, 2019	400,000		—		400,000		400,000		—			400,000
7.0% Senior Notes (6)	October 15, 2022	400,000		—		400,000		400,000		—			400,000
Lease Financing Obligation (7)	August 10, 2020	44,453		—		44,453		97,596		—			97,596
Total Debt		$	1,259,797	$	—	$	1,259,797	$	1,172,940	$	(7,209	)	$	1,165,731
Less: Current Portion of Long-Term Debt		4,554		—		4,554		9,077		—			9,077
Total Long-Term Debt (8)		$	1,255,243	$	—	$	1,255,243	$	1,163,863	$	(7,209	)	$	1,156,654

(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 $271.9 million as of December 31, 2012 based on reported market trades of these instruments. The 9.875% Senior Notes were redeemed in full on July 15, 2013.

(3) The aggregate estimated fair value of the Convertible Notes was approximately $25.2 million and $25.3 million as of September 30, 2013 and December 31, 2012, respectively, based on reported market trades of these instruments.

(4) The Company has the right at any time, 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 $410.0 million and $435.0 million as of September 30, 2013 and December 31, 2012, respectively, based on reported market trades of these instruments.

(6) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $390.0 million and $413.8 million as of September 30, 2013 and December 31, 2012, respectively, based on reported market trades of these instruments.

(7) The aggregate estimated fair value of the full Lease Financing Obligation was approximately $88.1 million as of September 30, 2013, 51% of which is held for sale at September 30, 2013, and $97.7 million as of December 31, 2012, respectively. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.

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(8) The total long-term debt balance excludes $46.4 million related to the Lease Financing Obligation that is included in liabilities associated with assets held for sale in the Unaudited Consolidated Balance Sheet. See Note 4 for additional information.

Amended Credit Facility

The Company’s Amended Credit Facility has a maturity date of October 31, 2016 and current commitments and borrowing base of $825.0 million. Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility was 2.1% and 1.8% for the three months ended September 30, 2013 and 2012, and 2.0% and 1.9% for the nine months ended September 30, 2013 and 2012, respectively.

The borrowing base is required to be re-determined twice per year. On October 25, 2013, the borrowing base was redetermined at $825.0 million based on mid-year reserves and hedge position. The borrowing base will be reduced upon closing of the West Tavaputs Sale, as discussed in Note 13. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.

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 since issuance. As of September 30, 2013, the Company had $390.0 million outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduces the current borrowing capacity of the Amended Credit Facility to $409.0 million.

9.875% Senior Notes Due 2016

On July 15, 2013, the Company redeemed the entire outstanding $250.0 million principal amount of 9.875% Senior Notes for a redemption price of 104.938% of the principal amount of the notes, or $262.3 million. Unamortized debt discount and deferred financing costs related to the notes resulted in a loss upon settlement of $21.5 million for the three and nine months ended September 30, 2013.

5% Convertible Senior Notes Due 2028

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. 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. 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 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.

7.625% Senior Notes Due 2019

On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The 7.625% Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit the Company from paying dividends. The

14

Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. The 7.625% Senior Notes are redeemable at the Company’s option at a redemption price of 103.813% of the principal amount of the notes on October 1, 2015.

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 mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. 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, including the Company’s Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at the Company's option on October 15, 2017 at a redemption price of 103.5% of the principal amount of the notes. 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 and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.

Lease Financing Obligation Due 2020

In July, 2012, the Company entered into the Lease Financing Obligation, whereby the Company received $100.8 million through the sale and subsequent leaseback of existing compressors and related facilities owned by the Company. The Lease Financing Obligation expires on August 10, 2020, and the Company has the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option where the Company may purchase the equipment for $36.6 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. See Note 11 for discussion of aggregate minimum future lease payments. As part of the West Tavaputs Sale, the purchaser will assume approximately 51% of the Lease Financing Obligation, including the buy-out options. See Note 13.

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, Convertible Notes, 7.625% Senior Notes, 7.0% Senior Notes and the Lease Financing Obligation along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in thousands)
Amended Credit Facility (1)
Cash interest	$	2,296	$	1,453	$	4,211	$	3,707
Non-cash interest	$	585	$	586	$	1,756	$	1,757
9.875% Senior Notes (2)
Cash interest	$	1,029	$	6,172	$	13,373	$	18,516
Non-cash interest	$	—	$	657	$	1,361	$	1,911
Convertible Notes (3)
Cash interest	$	310	$	317	$	943	$	2,585
Non-cash interest	$	1	$	1	$	4	$	1,770
7.625% Senior Notes (4)
Cash interest	$	7,625	$	7,625	$	22,875	$	22,875
Non-cash interest	$	272	$	262	$	798	$	803
7.0% Senior Notes (5)
Cash interest	$	7,000	$	7,000	$	21,000	$	15,397
Non-cash interest	$	203	$	197	$	592	$	464
Lease Financing Obligation (6)
Cash interest	$	750	$	548	$	2,305	$	548
Non-cash interest	$	8	$	6	$	24	$	6

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(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 was 9.875% per annum with an effective interest rate of 11.2% per annum. The Company redeemed the 9.875% Senior Notes in full on July 15, 2013.

(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 8.0% 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.

(6) The effective interest rate for the Lease Financing Obligation is 3.3% per annum.

6. Asset Retirement Obligations

A reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2013 is as follows (in thousands):

As of December 31, 2012	$	47,616
Liabilities incurred	2,095
Liabilities settled	(824		)
Disposition of properties	(387		)
Accretion expense	2,604
Revisions to estimate	1,218
As of September 30, 2013	$	52,322
Less: liabilities associated with properties held for sale	13,082
Less: current asset retirement obligations	948
Long-term asset retirement obligations	$	38,292

7. 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 5, approximates its fair value due to its floating rate structure based on the LIBOR spread and the Company's borrowing base utilization.

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

16

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 less observable than objective sources. 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 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 September 30, 2013
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	920	$	—	$	—	$	920
Cash Equivalents - Money Market Funds	53		—		—		53
Commodity Derivatives	—		16,881		—		16,881
Liabilities
Commodity Derivatives	$	—	$	11,804	$	—	$	11,804

	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	966	$	—	$	—	$	966
Cash Equivalents - Money Market Funds	53		—		—		53
Commodity Derivatives	—		40,432		—		40,432
Liabilities
Commodity Derivatives	$	—	$	7,875	$	—	$	7,875

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

Level 1 Fair Value Measurements – The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 10) 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. The fair values of the Company’s fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $800.0 million as of September 30, 2013. The fair values of the Company’s fixed rate 9.875% Senior Notes, 7.625% Senior Notes and 7.0% Senior Notes totaled $1,120.7 million as of December 31, 2012. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

Level 2 Fair Value Measurements – The fair value of crude oil, natural gas and NGL 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

17

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.

There is no active, public market for the Company’s Amended Credit Facility, Convertible Notes or Lease Financing Obligation. The Amended Credit Facility balance of $390.0 million and zero as of September 30, 2013 and December 31, 2012, respectively, approximates its fair value due to its floating rate structure. The Convertible Notes fair value of $25.2 million and $25.3 million as of September 30, 2013 and December 31, 2012, respectively, are measured based on market-based parameters of the various components of the Convertible Notes and over the counter trades. The Lease Financing Obligation fair values of $88.1 million and $97.7 million as of September 30, 2013 and December 31, 2012, respectively, are measured based on market-based parameters of comparable term secured financing instruments. The fair value measurements for the Amended Credit Facility, Convertible Notes and Lease Financing Obligation represent Level 2 inputs.

Level 3 Fair Value Measurements – As of September 30, 2013 and December 31, 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 on its property and equipment when required. During the nine months ended September 30, 2013 the Company recorded impairment charges of  $216.6 million on proved and unproved oil and gas properties. Included in the total impairment charge of $216.6 million was $201.3 million of impairment charges related to assets held for sale at September 30, 2013 for both proved and unproved oil and gas properties for which the Company utilized third party purchase offers as the basis for determining fair value. The inputs used to determine such fair value for other non-recurring impairment testes are primarily based upon internally developed cash flow models as well as available external market data and would generally be classified within Level 3.

The Company also applied fair value accounting guidance to measure the assets and liabilities in the 2012 Divestiture. The 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 4 for additional discussion of the 2012 Divestiture. Additionally, the Company uses fair value to determine the 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.

8. 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 contracts related to the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of oil, natural gas and NGLs 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, natural gas and NGL 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 on the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts of all derivative instruments presented on the Unaudited Consolidated Balance Sheets as of the dates indicated.

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	As of September 30, 2013
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
				(in thousands)
Derivative assets	$	12,217		$	(8,711	)	(1)	$	3,506
Deferred financing costs and other noncurrent assets	4,664			(822		)	(1)	3,842			(2)
Total derivative assets	$	16,881		$	(9,533	)		$	7,348
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
				(in thousands)
Derivative liabilities	$	(10,982	)	$	8,711		(3)	$	(2,271	)
Derivatives and other noncurrent liabilities	(822		)	822			(3)	—
Total derivative liabilities	$	(11,804	)	$	9,533			$	(2,271	)
	As of December 31, 2012
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
				(in thousands)
Derivative assets	$	34,828		$	(4,848	)	(1)	$	29,980
Deferred financing costs and other noncurrent assets	5,604			(2,623		)	(1)	2,981			(2)
Total derivative assets	$	40,432		$	(7,471	)		$	32,961
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
				(in thousands)
Derivative liabilities	$	(4,848	)	$	4,848		(3)	$	—
Derivatives and other noncurrent liabilities	(3,027		)	2,623			(3)	(404		)	(4)
Total derivative liabilities	$	(7,875	)	$	7,471			$	(404	)

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

(2) As of September 30, 2013 and December 31, 2012, this line item on the Unaudited Consolidated Balance Sheets includes $20.2 million and $26.8 million of deferred financing costs and other noncurrent assets, respectively.

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

(4) As of December 31, 2012, this line item on the Unaudited Consolidated Balance Sheets includes $4.1 million of other noncurrent liabilities.

The following table summarizes the cash flow hedge gains, 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 September 30,				Nine Months Ended September 30,
		2013		2012		2013		2012
		(in thousands)
Amount of Gain Reclassified from AOCI into Income (net of tax) (1) (2)	Commodity Hedges	$	1,186	$	12,739	$	3,688	$	41,644

(1) Gains reclassified from AOCI into income are included in the oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations.

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(2) Presented net of income tax expense of $0.7 million and $7.7 million for the three months ended September 30, 2013 and 2012, respectively, and $2.2 million and $25.0 million for the nine months ended September 30, 2013 and 2012, respectively.

As of September 30, 2013, the Company had financial instruments in place to hedge the following volumes for the periods indicated:

	October –December 2013	For the year 2014	For the  year 2015
Oil (Bbls)	806,300	2,972,200	401,200
Natural Gas (MMbtu)	11,355,000	30,415,000	3,650,000
Natural Gas Liquids (Bbls)	98,214	35,714	—

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Commodity derivative settlements on derivatives designated as cash flow hedges (1)	$	1,899		$	20,391		$	5,902		$	66,654
Total commodity derivative gain (loss) (2)	(25,595		)	(38,340		)	(18,607		)	53,431

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

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

The Company’s derivative financial instruments 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 had hedges in place with 11 different counterparties as of September 30, 2013. 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. One counterparty that was a lender 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 creditworthiness of this counterparty during the remaining duration of the derivatives that were entered into while that counterparty was a lender 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, it 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. The Company does not have any derivative balances that are offset by cash collateral.

9. 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 nine months ended September 30, 2013, there was no change to the Company’s liability for uncertain tax positions.

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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 nine months ended September 30, 2013.

Income tax benefit for the three and nine months ended September 30, 2013 and 2012 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.

10. 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).

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in thousands)
Common stock options	$	681	$	1,626	$	3,898	$	5,299
Nonvested equity common stock	1,562		1,711		5,550		5,485
Nonvested equity common stock units	277		371		989		371
Nonvested performance-based equity	712		372		1,410		1,175
Total	$	3,232	$	4,080	$	11,847	$	12,330

Unrecognized compensation cost as of September 30, 2013 was $22.2 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 2.4 years.

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

	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012
	Number of Options	Weighted Average Price Per Share		Number of Options	Weighted Average Price Per Share
Options to purchase shares of common stock	—	$	—	26,602	$	20.23
	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012
	Number of Shares	Weighted Average Grant Date Fair Value Per Share		Number of Shares	Weighted Average Grant Date Fair Value Per Share
Nonvested equity common stock	57,792	$	22.36	31,664	$	21.64
Nonvested equity common stock units	2,210	$	25.11	52,917	$	18.94
Nonvested performance-based equity shares	154,314	$	20.86	3,400	$	23.48
Total shares granted	214,316			87,981

	Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	Number of Options	Weighted Average Price Per Share		Number of Options	Weighted Average Price Per Share
Options to purchase shares of common stock	—	$	—	582,284	$	27.16
	Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	Number of Shares	Weighted Average Grant Date Fair Value Per Share		Number of Shares	Weighted Average Grant Date Fair Value Per Share
Nonvested equity common stock	615,052	$	17.80	260,778	$	26.06
Nonvested equity common stock units	54,429	$	22.17	52,917	$	18.94
Nonvested performance-based equity shares	442,300	$	18.08	179,987	$	26.26
Total shares granted	1,111,781			493,682

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”). Upon commencement of the 2010 Program and during

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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. 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.

The 2010 Program has both performance-based and market-based goals. All compensation expense related to the market-based goals will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. Based on Company performance in 2011, 26.6% of the 2010 Program performance shares vested in February 2012, and the Company recorded zero and $0.2 million of non-cash stock-based compensation expense related to these awards for the three and nine months ended September 30, 2012. Based upon the Company’s performance in 2012, none of the 2010 Program performance shares vested in February 2013. The Company recorded $0.1 million and $0.3 million of non-cash stock-based compensation expense for the nine months ended September 30, 2013 and 2012, respectively.

In March 2012, the Compensation Committee approved a new performance share program (the “2012 Program”). The performance-based awards contingently vest in May 2015, depending on the level at which the performance goals are achieved. The Company recorded $0.1 million and $0.3 million of non-cash stock-based compensation expense related to these awards for the three months ended September 30, 2013 and 2012, respectively, and $0.1 million and $0.7 million of non-cash stock-based compensation expense for the nine months ended September 30, 2013 and 2012, respectively.

In February 2013, the Compensation Committee approved the performance metrics used to measure potential vesting of the performance shares in the 2010 Program based on 2013 performance. For the year ending December 31, 2013, the performance goals consist of the Company’s total shareholder return (“TSR”) ranking relative to a defined peer group’s individual TSR (weighted at 40%), the Company’s discretionary cash flow (weighted at 30%) and PV10 of proved oil, natural gas and NGL reserves (weighted at 30%). In February 2013, 86,223 performance-based nonvested equity shares of common stock in the 2010 Program became subject to a new grant date, and the fair value of the shares was remeasured at the grant date. All remaining unvested shares could potentially vest if all performance goals are met at the stretch level, and all shares that remain unvested based on 2013 performance will expire in 2014. 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, natural gas and NGL reserves metric will be based upon the number of shares expected to vest at the end of the one year period. The Company recorded $0.1 million and 0.3 million of non-cash stock-based compensation expense related to these awards during the three and nine months ended September 30, 2013, respectively.

In February 2013, the Compensation Committee established 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 TSR ranking relative to a defined peer group’s individual TSRs. In February 2013, 22,710 market-based nonvested equity shares of common stock became subject to a new grant date, and the fair value of the shares was remeasured at the grant date. All shares that remain unvested based on 2013 performance will expire in 2014. 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 recorded $0.03 million and $0.08 million of non-cash stock-based compensation expense related to these awards for the three and nine months ended September 30, 2013, respectively.

In February 2013, the Compensation Committee approved a new performance share program (the “2013 Program”) pursuant to the 2012 Equity Incentive Plan (“2012 Incentive Plan”). The performance-based awards contingently vest in May 2016, 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, 2015, consist of the Company’s TSR ranking relative to a defined peer group’s individual TSR (“Relative TSR”) (weighted at 33 1/3%), the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group’s percentage calculation (“DCF per Debt Adjusted Share”) (weighted at 33 1/3%) and percentage change in proved oil, natural gas and NGL reserves per debt adjusted share (“Reserves per Debt Adjusted Share”) (weighted at 33 1/3%). The Relative TSR and DCF per Debt Adjusted Share goals will vest at 25% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. The Reserves per Debt Adjusted Share goal will vest at 50% of the total award for performance met at the threshold level, 100% at the target level and 200% 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 prorated based on 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

22

period, any shares that have not vested will be forfeited. A total of 100,434 and 388,420 shares were granted under this program during the three and nine months ended September 30, 2013. All compensation expense related to the Relative 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 DCF per Debt Adjusted Share metric and the Reserves per Debt Adjusted Share metric will be based upon the number of shares expected to vest at the end of the three year period. The Company recorded $0.4 million and $0.8 million of non-cash stock-based compensation expense related to these awards for the three and nine months ended September 30, 2013, respectively.

Director Fees. The Company’s non-employee, or outside, directors, may elect to receive all or a portion of their annual retainer and meeting fees in the form of restricted stock units (“RSUs”), which are settled with shares of the Company’s common stock, issued pursuant to the Company’s 2012 Incentive Plan. After each quarter, RSUs with a value equal to the fees payable for that quarter, calculated using the closing price for the Company’s common stock on the last trading day of the quarter, will be delivered to each outside director who elected before that quarter to receive RSUs for payment of director fees. These nonvested RSUs will vest immediately at the end of the applicable quarter. Once vested, the RSUs will settle at the end of the applicable quarter or such later date elected by the director.

A summary of the Company’s directors’ fees and equity-based compensation for the three and nine months ended September 30, 2013 and 2012 is presented below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Director fees (shares)	2,210		3,732		14,116		6,907
Stock-based compensation (in thousands)	$	56	$	92	$	297	$	167

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, subject to statutory limitations.

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 for the three months ended September 30, 2013 and 2012, and $1.6 million for the nine months ended September 30, 2013 and 2012.

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. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.

The deferred compensation liability was $0.9 million and $1.0 million as of September 30, 2013 and December 31, 2012, respectively, of which $0.5 million and $0.3 million were classified as current as of September 30, 2013 and December 31, 2012, respectively.

The Company has established a rabbi trust to offset the deferred compensation liability and protect the interests of the plan participants. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability.

11. Commitments and Contingencies

Lease Financing Obligation. The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments are presented below:

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	As of September 30, 2013
	(in thousands)
2013	$	3,034
2014	12,139
2015	12,139
2016	12,139
2017	12,139
Thereafter	32,368
Total (1)	$	83,958

(1) The balance shown in this table includes the approximately 51% of the Lease Financing Obligation that the purchaser will assume upon closing of the West Tavaputs Sale in December 2013. See Note 13.

Transportation Demand and Firm Processing Charges. The Company has entered into contracts that provide firm transportation capacity on pipeline systems and firm processing charges. The remaining terms on these contracts range from 2 to 10 years and require the Company to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by the Company. The Company paid $9.5 million and $27.8 million of transportation demand charges for the three and nine months ended September 30, 2013, respectively. The Company paid $1.4 million and $3.5 million of firm processing charges for the three and nine months ended September 30, 2013, respectively. All transportation costs, including demand charges and processing charges, are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations. The Company paid $11.3 million and $33.7 million of transportation demand charges for the three and nine months ended September 30, 2012, respectively. The Company paid $1.6 million and $4.6 million of firm processing charges for the three and nine months ended September 30, 2012, respectively.

The amounts in the table below represent the Company’s gross future minimum transportation demand and firm processing charges. However, the Company will record in its financial statements only the Company’s proportionate share based on the Company’s working interest and net revenue interest, which will vary from property to property.

	As of September 30, 2013
	(in thousands)
2013	$	14,450
2014	57,929
2015	58,065
2016	56,464
2017	51,824
Thereafter	147,984
Total (1)	$	386,716

(1) The balance shown in this table includes $137.7 million of transportation demand and firm processing charges that the purchaser will assume upon closing of the West Tavaputs Sale in December 2013. See Note 13.

Lease and Other Commitments. The Company has one take-or-pay purchase agreement for supply of carbon dioxide (“CO2”), which has a total financial commitment of $1.7 million. The CO2 is for use in fracture stimulation operations. Under this contract, the Company is obligated to purchase a minimum monthly volume at a set price. If the Company takes delivery of less than the minimum required amount, the Company is responsible for full payment (deficiency payment) in December 2015.

The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Office lease expense was $0.5 million and $1.5 million for both the three and nine months ended September 30, 2013 and 2012, respectively. Additionally, the Company has entered into various long-term agreements for telecommunication services. Future minimum annual payments under lease and other agreements are as follows:

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	As of September 30, 2013
	(in thousands)
2013	$	1,069
2014	4,561
2015	3,099
2016	2,593
2017	2,517
Thereafter	3,158
Total	$	16,997

Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the course of ordinary business. It is the opinion of the Company’s management that current claims and litigation involving the Company are not likely to have a material adverse effect on its unaudited consolidated balance sheet, cash flows or statements of operations.

12. Guarantor Subsidiaries

In addition to the Amended Credit Facility, 7.625% Senior Notes, 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 unaudited condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) 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 unaudited condensed consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the Unaudited Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the intercompany eliminations column.

Condensed Consolidating Balance Sheets

	As of September 30, 2013
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Assets:
Current assets	$	165,436		$	3,615		$	—	$	169,051
Property and equipment, net	2,410,495			122,650			—		2,533,145
Intercompany receivable (payable)	156,414			(156,414		)	—		—
Investment in subsidiaries	(35,826		)	—			35,826		—
Noncurrent assets	24,065			—			—		24,065
Total assets	$	2,720,584		$	(30,149	)	$	35,826	$	2,726,261
Liabilities and Stockholders’ Equity:
Current liabilities	$	205,331		$	906		$	—	$	206,237
Long-term debt	1,255,243			—			—		1,255,243
Deferred income taxes	153,847			2,187			—		156,034
Other noncurrent liabilities	99,165			2,584			—		101,749
Stockholders’ equity	1,006,998			(35,826		)	35,826		1,006,998
Total liabilities and stockholders’ equity	$	2,720,584		$	(30,149	)	$	35,826	$	2,726,261

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	As of December 31, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Assets:
Current assets	$	226,013		$	2,326		$	—	$	228,339
Property and equipment, net	2,514,240			97,097			—		2,611,337
Intercompany receivable (payable)	141,272			(141,272		)	—		—
Investment in subsidiaries	(47,533		)	—			47,533		—
Noncurrent assets	29,773			—			—		29,773
Total assets	$	2,863,765		$	(41,849	)	$	47,533	$	2,869,449
Liabilities and Stockholders’ Equity:
Current liabilities	$	212,117		$	1,016		$	—	$	213,133
Long-term debt	1,156,654			—			—		1,156,654
Deferred income taxes	264,113			2,251			—		266,364
Other noncurrent liabilities	48,106			2,417			—		50,523
Stockholders’ equity	1,182,775			(47,533		)	47,533		1,182,775
Total liabilities and stockholders’ equity	$	2,863,765		$	(41,849	)	$	47,533	$	2,869,449

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	139,286		$	9,269		$	—		$	148,555
Operating expenses	(329,791		)	(4,432		)	—			(334,223		)
General and administrative	(14,402		)	—			—			(14,402		)
Interest income and other income (expense)	(67,081		)	—			—			(67,081		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(271,988		)	4,837			—			(267,151		)
Benefit from income taxes	100,495			—			—			100,495
Equity in earnings of subsidiaries	4,837			—			(4,837		)	—
Net income (loss)	$	(166,656	)	$	4,837		$	(4,837	)	$	(166,656	)

	Nine Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	405,057		$	24,074		$	—		$	429,131
Operating expenses	(556,070		)	(12,367		)	—			(568,437		)
General and administrative	(48,257		)	—			—			(48,257		)
Interest income and other income (expense)	(109,290		)	—			—			(109,290		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(308,560		)	11,707			—			(296,853		)
Benefit from income taxes	111,319			—			—			111,319
Equity in earnings of subsidiaries	11,707			—			(11,707		)	—
Net income (loss)	$	(185,534	)	$	11,707		$	(11,707	)	$	(185,534	)

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	Three Months Ended September 30, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	172,054		$	8,812		$	—		$	180,866
Operating expenses	(179,917		)	(5,399		)	—			(185,316		)
General and administrative	(17,965		)	—			—			(17,965		)
Interest and other income (expense)	(62,814		)	—			—			(62,814		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(88,642		)	3,413			—			(85,229		)
Benefit from income taxes	32,603			—			—			32,603
Equity in earnings of subsidiaries	3,413			—			(3,413		)	—
Net income (loss)	$	(52,626	)	$	3,413		$	(3,413	)	$	(52,626	)

	Nine Months Ended September 30, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	502,175		$	18,219		$	—		$	520,394
Operating expenses	(461,243		)	(14,219		)	—			(475,462		)
General and administrative	(51,441		)	—			—			(51,441		)
Interest and other income (expense)	(14,869		)	—			—			(14,869		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(25,378		)	4,000			—			(21,378		)
Benefit from income taxes	7,943			—			—			7,943
Equity in earnings of subsidiaries	4,000			—			(4,000		)	—
Net income (loss)	$	(13,435	)	$	4,000		$	(4,000	)	$	(13,435	)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(166,656	)	$	4,837	$	(4,837	)	$	(166,656	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(1,186		)	—		—			(1,186		)
Other comprehensive loss	(1,186		)	—		—			(1,186		)
Comprehensive income (loss)	$	(167,842	)	$	4,837	$	(4,837	)	$	(167,842	)
	Nine Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(185,534	)	$	11,707	$	(11,707	)	$	(185,534	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(3,688		)	—		—			(3,688		)
Other comprehensive loss	(3,688		)	—		—			(3,688		)
Comprehensive income (loss)	$	(189,222	)	$	11,707	$	(11,707	)	$	(189,222	)

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	Three Months Ended September 30, 2012
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(52,626	)	$	3,413	$	(3,413	)	$	(52,626	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(12,739		)	—		—			(12,739		)
Other comprehensive loss	(12,739		)	—		—			(12,739		)
Comprehensive income (loss)	$	(65,365	)	$	3,413	$	(3,413	)	$	(65,365	)
	Nine Months Ended September 30, 2012
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(13,435	)	$	4,000	$	(4,000	)	$	(13,435	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(41,644		)	—		—			(41,644		)
Other comprehensive loss	(41,644		)	—		—			(41,644		)
Comprehensive income (loss)	$	(55,079	)	$	4,000	$	(4,000	)	$	(55,079	)

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	179,003		$	17,299		$	—	$	196,302
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(303,366		)	(32,231		)	—		(335,597		)
Additions to furniture, fixtures and other	(1,506		)	—			—		(1,506		)
Proceeds from sale of properties and other investing activities	784			—			—		784
Cash flows from financing activities:
Proceeds from debt	390,000			—			—		390,000
Principal and redemption premium payments on debt	(269,125		)	—			—		(269,125		)
Intercompany transfers	(14,932		)	14,932			—		—
Other financing activities	227			—			—		227
Change in cash and cash equivalents	(18,915		)	—			—		(18,915		)
Beginning cash and cash equivalents	79,395			50			—		79,445
Ending cash and cash equivalents	$	60,480		$	50		$	—	$	60,530

28

	Nine Months Ended September 30, 2012
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	284,188		$	6,415		$	—	$	290,603
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(727,818		)	(23,727		)	—		(751,545		)
Additions to furniture, fixtures and other	(5,519		)	—			—		(5,519		)
Proceeds from sale of properties and other investing activities	91			—			—		91
Cash flows from financing activities:
Proceeds from debt	785,826			—			—		785,826
Principal and redemption premium payments on debt	(343,163		)	—			—		(343,163		)
Intercompany transfers	(17,312		)	17,312			—		—
Other financing activities	(9,691		)	—			—		(9,691		)
Change in cash and cash equivalents	(33,398		)	—			—		(33,398		)
Beginning cash and cash equivalents	57,281			50			—		57,331
Ending cash and cash equivalents	$	23,883		$	50		$	—	$	23,933

13. Subsequent Events

On October 22, 2013, the Company entered into a purchase and sale agreement for the sale of the Company’s West Tavaputs natural gas property located in the Uinta Basin, Utah. Total consideration, prior to customary closing adjustments, for the West Tavaputs Sale is $371.5 million and includes approximately $46.0 million for the purchaser’s assumption of the Lease Financing Obligation. The transaction is expected to close by the end of 2013. The Company recognized impairment expense of $201.3 million related to these assets in the three months ended September 30, 2013.

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

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements as to our future plans, estimates, beliefs and expected performance. 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”);

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

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

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

• economic and competitive conditions;

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

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

• changes in estimates of proved reserves;

• compliance with environmental and other regulations;

• derivative and hedging activities;

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

• occurrence of property divestitures or acquisitions;

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

• 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;

• exploration risks such as drilling unsuccessful wells;

• capital expenditures and other contractual obligations;

• debt and equity market conditions;

• 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;

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

• 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, 2012 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”) develops oil, natural gas and NGLs in the Rocky Mountain region of the United States. We seek to build stockholder value through profitable growth in cash flow, reserves and production through the development of our oil, natural gas and NGL assets. Due to the decline in natural gas prices resulting from the increased supply over the past few years, we have shifted our focus to finding, acquiring and developing oil resources. Therefore, we will see a decrease in gas production due to suspended gas drilling. We seek high quality development projects with the potential to provide 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.

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,

30

we have built our portfolio of 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) and Powder River (Wyoming) Basins in the Rocky Mountain region (the “Rockies”). We also may sell properties when the opportunity arises or when business conditions warrant, as demonstrated by the sale of our Wind River Basin and Powder River Basin properties and a portion of our Piceance Basin properties in December 2012.

We are committed to developing and producing oil, natural gas and NGLs in a responsible and safe 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 development and production of crude oil, natural gas and NGLs, and all of our operations are conducted in the United States. Consequently, we currently report a single reportable segment.

Results of Operations

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

31

Three Months Ended September 30, 2013 Compared with Three Months Ended September 30, 2012

	Three Months Ended September 30,					Increase (Decrease)
	2013			2012		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	149,345		$	180,024	$	(30,679	)	(17	)%
Other	(790		)	842		(1,632		)	(194	)%
Operating Expenses
Lease operating expense	18,280			17,003		1,277			8	%
Gathering, transportation and processing expense	16,374			26,725		(10,351		)	(39	)%
Production tax expense	8,183			8,094		89			1	%
Exploration expense	(24		)	3,562		(3,586		)	(101	)%
Impairment, dry hole costs and abandonment expense	219,363			38,540		180,823			469	%
Depreciation, depletion and amortization	72,047			91,392		(19,345		)	(21	)%
General and administrative expense (1)	11,083			13,912		(2,829		)	(20	)%
Non-cash stock-based compensation expense (1)	3,319			4,053		(734		)	(18	)%
Total operating expenses	$	348,625		$	203,281	$	145,344		71	%
Production Data (2):
Natural gas (MMcf)	12,988			27,010		(14,022		)	(52	)%
Oil (MBbls)	909			714		195			27	%
NGLs (MBbls)	500			—		500			*nm
Combined volumes (MMcfe)	21,442			31,294		(9,852		)	(31	)%
Daily combined volumes (MMcfe/d)	233			340		(107		)	(31	)%
Average Realized Prices (3):
Natural gas (per Mcf) (4)	$	4.30		$	4.90	$	(0.60	)	(12	)%
Oil (per Bbl)	83.51			84.08		(0.57		)	(1	)%
NGLs (per Bbl)	28.74			—		28.74			*nm
Combined (per Mcfe)	6.81			6.15		0.66			11	%
Average Costs (per Mcfe):
Lease operating expense	$	0.85		$	0.54	$	0.31		57	%
Gathering, transportation and processing expense	0.76			0.85		(0.09		)	(11	)%
Production tax expense	0.38			0.26		0.12			46	%
Depreciation, depletion and amortization	3.36			2.92		0.44			15	%
General and administrative expense (5)	0.52			0.44		0.08			18	%

* 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 $14.4 million and $18.0 million for the three months ended September 30, 2013 and 2012, 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) Prior to 2013, NGL volumes were included within natural gas production data, which impacts the comparability for the two periods presented.

(3) Average realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production. This presentation is a non-GAAP measure as it only represents the cash settled portion of our total commodity derivative gain loss in the Unaudited Consolidated Statements of Operations. Management believes the presentation of average prices including the effects of settled commodity derivative gains and losses is useful because

32

the cash settlement portion provides a better understanding of the Company's average prices received for production volumes. We also believe that this disclosure allows for a more accurate comparison to our peers.

(4) Natural gas prices for 2012 include the effect of NGL related revenue.

(5) Excludes non-cash stock-based compensation expense as described in Note 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 $0.67 and $0.57 for the three months ended September 30, 2013 and 2012, respectively.

Production Revenues and Volumes. Historically, we have reported our natural gas production as a single stream of wet gas measured at the well head. Beginning in the first quarter of 2013, we changed our reporting for natural gas volumes to show natural gas and NGL production volumes consistent with title transfer for each product. Effective January 1, 2013, substantially all of our gas processing contracts were amended to designate title transfer of gas and NGLs processed at the tailgate of each processing plant.

Production revenues decreased to $149.3 million for the three months ended September 30, 2013 from $180.0 million for the three months ended September 30, 2012. The decrease in production revenues was primarily due to a 31%decrease in production volumes. The decrease in production reduced production revenues by approximately $68.6 million, while the increase in average prices increased production revenues by approximately $37.9 million.

We discontinued hedge accounting as of 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, gas and NGL production revenues. The amount reclassified to oil, gas and NGL production revenues was a gain of $1.9 million and $20.4 million for the three months ended September 30, 2013 and 2012, respectively.

Total production volumes of 21.4 Bcfe for the three months ended September 30, 2013decreased from 31.3 Bcfe for the three months ended September 30, 2012. We completed a sale of natural gas assets on December 31, 2012, including 100% of our Wind River Basin and Powder River Basin coalbed methane properties (“PRB-CBM”) and an initial 18% interest in the Gibson Gulch assets in the Piceance Basin that progresses to a 26% interest in 2016 (the “2012 Divestiture”). Lower natural gas commodity prices caused us to discontinue drilling activity in the Piceance Basin and West Tavaputs area in the Uinta Basin in 2012 to concentrate on our oil development programs, which has continued to impact 2013 gas production volumes. These decreases were partially offset by a 27% overall increase in oil production with increases in the Uinta Oil Program, DJ Basin and Powder River Oil Program. Additional information concerning production is in the following table:

	Three Months Ended September 30, 2013				Three Months Ended September 30, 2012				% Increase (Decrease)
	Oil	NGL(1)	Natural Gas(1)	Total	Oil	NGL(1)	Natural Gas(1)	Total	Oil	NGL(1)	Natural Gas(1)	Total
	(MBbls)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MBbls)	(MMcf)	(MMcfe)
Piceance Basin	87	410	6,223	9,205	169	—	12,991	14,005	(49)%	*nm	(52)%	(34)%
Uinta- West Tavaputs	4	—	5,353	5,377	17	—	9,351	9,453	(76)%	*nm	(43)%	(43)%
Uinta Oil Program	546	45	845	4,391	399	—	668	3,062	37%	*nm	26%	43%
DJ Basin	184	43	459	1,821	92	—	311	863	100%	*nm	48%	111%
Powder River Oil	88	2	91	631	27	—	21	183	226%	*nm	333%	245%
Other (2)	—	—	17	17	10	—	3,668	3,728	(100)%	*nm	(100)%	(100)%
Total	909	500	12,988	21,442	714	—	27,010	31,294	27%	*nm	(52)%	(31)%

* Not meaningful.

(1) Prior to 2013, NGL volumes were included in natural gas production data, which impacts the comparability for the two periods presented.

(2) Other for the three months ended September 30, 2012 includes PRB–CBM natural gas volumes of 2,714 MMcf for 2012, Wind River natural gas production volumes of 950 MMcf and oil production of 8 MBbls.

Hedging Activities. During the three months ended September 30, 2013, approximately 84% of our oil volumes, 89% of our natural gas volumes and 18% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $6.3 million, partially offset by increases in natural gas revenues of $4.1 million and NGL revenues of $0.8

33

million after settlements for all commodity derivatives. Of the loss on total settlements of $1.4 million for the three months ended September 30, 2013, a gain of $1.9 million was included in oil, gas and NGL production revenues and a loss of $3.3 million was included in commodity derivative gain (loss) in the Unaudited Statements of Operations. During the three months ended September 30, 2012, approximately 69% of our oil volumes, 67% of our natural gas volumes (excluding basis only swaps, which were equivalent to 7% of our natural gas volumes), and 17% of our NGL related volumes were subject to financial hedges, which resulted in increases in oil revenues of $4.4 million and natural gas revenues of $28.3 million after settlements for all commodity derivatives, including basis only and NGL swaps. Of the gain on total settlements of $32.7 million for the three months ended September 30, 2012, $20.4 million was included in oil, gas and NGL production revenues and $12.3 million was included in commodity derivative gain (loss) in the Unaudited Statements of Operations.

Other Operating Revenues. Other operating revenues decreased to a loss of $0.8 million for the three months ended September 30, 2013 from income of $0.8 million for the three months ended September 30, 2012. Other operating revenues for the three months ended September 30, 2013 primarily consisted of $1.0 million in net losses realized from the sale of properties offset by $0.2 million of income from gathering and compression fees received from third parties. Other operating revenues for the three months ended September 30, 2012 consisted of $0.8 million of income from gathering, compression and salt-water disposal fees received from third parties.

Lease Operating Expense. Lease operating expense (“LOE”) increased to $0.85 per Mcfe for the three months ended September 30, 2013 from $0.54 per Mcfe for the three months ended September 30, 2012. LOE on a per Mcfe basis is inherently higher from our oil producing properties such as those in our Uinta Oil and DJ Basin development areas. In addition, the 2012 Divestiture consisted of natural gas properties with lower LOE per Mcfe, which contributed to a higher LOE per Mcfe unit cost in the three months ended September 30, 2013.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing (“GTP”) expense decreased to $0.76 per Mcfe for the three months ended September 30, 2013 from $0.85 per Mcfe for the three months ended September 30, 2012. The decrease is due to a change in reporting an oil transportation deduction related to certain production within the Uinta Oil Program as a charge against production revenues as of January 1, 2013. These costs were previously included within GTP expense for the three months ended September 30, 2012. The effect on the average per unit oil price is approximately $1.84 per barrel, which reduced GTP expense by approximately $0.08 per Mcfe for the three months ended September 30, 2013.

Production Tax Expense. Total production taxes increased to $8.2 million for the three months ended September 30, 2013 from $8.1 million for the three months ended September 30, 2012. Production taxes are primarily based on the wellhead values of production, which excludes gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 5.5% and 5.1% for the three months ended September 30, 2013 and September 30, 2012, respectively.

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 increase in the overall production tax rate is consistent with our production increase in areas with higher production tax rates.

Exploration Expense. Exploration expense for the three months ended September 30, 2013 was zero compared to $3.6 million for the three months ended September 30, 2012. Exploration expense for the three months ended September 30, 2012 consisted of $3.4 million of geological and geophysical seismic programs and $0.2 million for delay rentals across all basins.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $219.4 million for the three months ended September 30, 2013 from $38.5 million for the three months ended September 30, 2012. For the three months ended September 30, 2013, impairment expense was $216.6 million and abandonment expense was $2.8 million with no dry hole costs. The $216.6 million of impairment expense for the three months ended September 30, 2013 included $198.8 million related to proved oil and gas properties and $17.8 million related to unproved oil and gas properties. We classified certain oil and gas properties in the West Tavaputs field in the Uinta Basin as held for sale as of September 30, 2013. Upon the classification as held for sale, the carrying value of the related properties was analyzed relative to the estimated fair value. As a result, we recognized $198.8 million of proved impairment expense and $2.5 million of unproved property impairment expense during the three months ended September 30, 2013. In addition, we recognized $15.3 million of impairment expense related to certain unproved oil and gas properties within exploration projects primarily as a result of no future plans to evaluate the remaining acreage and an estimated market value below our carrying value.

34

For the three months ended September 30, 2012, impairment expense was $18.8 million, abandonment expense associated with exploratory drilling locations was $4.1 million and dry hole costs were $15.6 million. The $18.8 million related to impairing 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.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) decreased to $72.0 million for the three months ended September 30, 2013 compared with $91.4 million for the three months ended September 30, 2012. The decrease of $19.3 million was a result of a 31%decrease in production for the three months ended September 30, 2013 compared with the three months ended September 30, 2012, offset by an increase in the DD&A rate. The decrease in production accounted for a $28.7 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $9.4 million of additional DD&A expense. The increase in the DD&A rate during the three months ended September 30, 2013 was due to an increase in the mix of oil projects in 2013 as compared to 2012, which have higher capital costs compared to natural gas projects.

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 September 30, 2013, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $3.36 per Mcfe compared with $2.92 per Mcfe for the three months ended September 30, 2012. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, decreased to $11.1 million for the three months ended September 30, 2013 from $13.9 million for the three months ended September 30, 2012. The decrease of $2.8 million was primarily the result of a 17% decrease in the number of employees as of September 30, 2013 compared to September 30, 2012. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 32 for a reconciliation and explanation. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $0.52 per Mcfe for the three months ended September 30, 2013 from $0.44 per Mcfe for the three months ended September 30, 2012, primarily related to the 31% decrease in production volumes for the three months ended September 30, 2013 compared with September 30, 2012. This is a non-GAAP measure. See Note 6 to the table on page 32 for a reconciliation and explanation.

Non-cash charges for stock-based compensation for the three months ended September 30, 2013 and 2012 were $3.3 million and $4.1 million, respectively. Non-cash stock-based compensation expense for each of the three months ended September 30, 2013 and 2012 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 September 30, 2013 and 2012 are shown in the following table:

	Three Months Ended September 30,
	2013		2012
	(in thousands)
Stock options and nonvested equity shares of common stock	$	3,117	$	3,823
Shares issued for 401(k) plan	146		138
Shares issued for directors’ fees	56		92
Total	$	3,319	$	4,053

Interest Expense. Interest expense decreased to $20.1 million for the three months ended September 30, 2013 from $24.5 million for the three months ended September 30, 2012. The decrease for the three months ended September 30, 2013 was primarily due to a lower weighted average interest rate as a result of the redemption of the 9.875% Senior Notes on July 15, 2013. Our weighted average interest rate for the three months ended September 30, 2013 was 6.2% compared with 7.8% for the three months ended September 30, 2012.

Commodity Derivative Gain (Loss).Commodity derivative gain (loss) was a loss of $25.6 million for the three months ended September 30, 2013 compared to a loss of $38.3 million for the three months ended September 30, 2012. The decrease in the loss was primarily due to a decrease in our natural gas hedging contracts as a result of fewer natural gas volumes hedged and stable natural gas futures pricing for the three months ended September 30, 2013 compared with September 30, 2012.

35

The table below summarizes the Company's commodity derivative gains and losses that were recognized in the periods presented:

	Three Months Ended September 30,
	2013			2012
	(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges (1)	$	(3,255	)	$	12,295
Unrealized gain (loss) on derivatives not designated as cash flow hedges (1)	(22,340		)	(50,635		)
Total commodity derivative gain (loss)	$	(25,595	)	$	(38,340	)

(1) Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of the Company's hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

Income Tax Benefit. Income tax benefit totaled $100.5 million for the three months ended September 30, 2013 compared with an income tax benefit of $32.6 million for the three months ended September 30, 2012, resulting in effective tax rates of 37.6% and 38.3%, respectively. The increase in income tax benefit was primarily the result of the variations in revenue and expense components as discussed above and the resulting decrease in income before income taxes. The effective tax rate for the three months ended September 30, 2012 reflects a state statutory rate decrease and the related tax benefit as it correlates to the book loss for that period. A similar rate change effect did not occur for the three months ended September 30, 2013. For both the 2013 and 2012 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording 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.

36

Nine Months Ended September 30, 2013 Compared with Nine Months Ended September 30, 2012

	Nine Months Ended September 30,				Increase (Decrease)
	2013		2012		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	424,130	$	516,556	$	(92,426	)	(18	)%
Other	5,001		3,838		1,163			30	%
Operating Expenses
Lease operating expense	53,138		54,671		(1,533		)	(3	)%
Gathering, transportation and processing expense	50,734		79,939		(29,205		)	(37	)%
Production tax expense	21,915		21,193		722			3	%
Exploration expense	212		8,063		(7,851		)	(97	)%
Impairment, dry hole costs and abandonment expense	227,646		60,179		167,467			278	%
Depreciation, depletion and amortization	214,792		251,417		(36,625		)	(15	)%
General and administrative expense (1)	36,278		39,026		(2,748		)	(7	)%
Non-cash stock-based compensation expense (1)	11,979		12,415		(436		)	(4	)%
Total operating expenses	$	616,694	$	526,903	$	89,791		17	%
Production Data (2):
Natural gas (MMcf)	41,959		78,417		(36,458		)	(46	)%
Oil (MBbls)	2,528		1,830		698			38	%
NGLs (MBbls)	1,627		—		1,627			*nm
Combined volumes (MMcfe)	66,889		89,397		(22,508		)	(25	)%
Daily combined volumes (MMcfe/d)	245		326		(81		)	(25	)%
Average Realized Prices (3):
Natural gas (per Mcf) (4)	$	4.10	$	5.04	$	(0.94	)	(19	)%
Oil (per Bbl)	82.50		85.49		(2.99		)	(4	)%
NGLs (per Bbl)	27.79		—		27.79			*nm
Combined (per Mcfe)	6.37		6.17		0.20			3	%
Average Costs (per Mcfe):
Lease operating expense	$	0.79	$	0.61	$	0.18		30	%
Gathering, transportation and processing expense	0.76		0.89		(0.13		)	(15	)%
Production tax expense	0.33		0.24		0.09			38	%
Depreciation, depletion and amortization	3.21		2.81		0.40			14	%
General and administrative expense (5)	0.54		0.44		0.10			23	%

* 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 $48.3 million and $51.4 million for the nine months ended September 30, 2013 and 2012, 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) Prior to 2013, NGL volumes were included within natural gas production data, which impacts the comparability for the two periods presented.

(3) Average realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production. This presentation is a non-GAAP measure as it only represents the cash settled portion of our total commodity derivative gain loss in the Unaudited Consolidated Statements of Operations. Management believes the presentation of average prices including the effects of settled commodity derivative gains and losses is useful because

37

the cash settlement portion provides a better understanding of the Company's average prices received for production volumes. We also believe that this disclosure allows for a more accurate comparison to our peers.

(4) Natural gas prices for 2012 include the effect of NGL related revenue.

(5) Excludes non-cash stock-based compensation expense as described in Note 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 $0.72 and $0.58 for the nine months ended September 30, 2013 and 2012, respectively.

Production Revenues and Volumes. Production revenues decreased to $424.1 million for the nine months ended September 30, 2013 from $516.6 million for the nine months ended September 30, 2012. This decrease is primarily due to a 25%decrease in production volumes. The decrease in production reduced production revenues by approximately $142.7 million, while the increase in average prices increased production revenues by approximately $50.3 million.

Production for the nine months ended September 30, 2013 includes an additional 2.8 Bcfe related to ethane volumes that were rejected from NGL processing in the Piceance Basin for the periods January through June 2013 that were not previously recognized as of June 30, 2013. Of the 2.8 Bcfe production adjustment, 1.7 Bcfe relates to the three months ended March 31, 2013 and 1.1 Bcfe relates to the three months ended June 30, 2013. Production revenues were not affected.

We discontinued hedge accounting as of January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in 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, gas and NGL production revenues. The amount reclassified to oil, gas and NGL production revenues was a gain of $5.9 million and $66.7 million for the nine months ended September 30, 2013 and 2012, respectively.

Total production volumes of 66.9 Bcfe for the nine months ended September 30, 2013decreased from 89.4 Bcfe for the nine months ended September 30, 2012. The decrease primarily relates to the 2012 Divestiture. In addition, lower natural gas commodity prices caused us to discontinue drilling activity in the Piceance Basin and West Tavaputs area in the Uinta Basin in 2012 to concentrate on our oil development programs, which has continued to impact 2013 gas production volumes. These decreases were partially offset by a 38% overall increase in oil production with increases in the Uinta Oil Program, DJ Basin and Powder River Oil Program for the nine months ended September 30, 2013. Additional information concerning production is in the following table:

	Nine Months Ended September 30, 2013				Nine Months Ended September 30, 2012				% Increase (Decrease)
	Oil	NGL(1)	Natural Gas(1)	Total	Oil	NGL(1)	Natural Gas(1)	Total	Oil	NGL(1)	Natural Gas(1)	Total
	(MBbls)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MBbls)	(MMcf)	(MMcfe)
Piceance Basin	262	1,400	20,135	30,107	469	—	36,669	39,483	(44)%	*nm	(45)%	(24)%
Uinta- West Tavaputs	27	—	17,971	18,133	50	—	27,479	27,779	(46)%	*nm	(35)%	(35)%
Uinta Oil Program	1,482	107	2,287	11,821	992	—	1,757	7,709	49%	*nm	30%	53%
DJ Basin	489	116	1,270	4,900	237	—	804	2,226	106%	*nm	58%	120%
Powder River Oil	262	4	200	1,796	61	—	82	448	330%	*nm	144%	301%
Other (2)	6	—	96	132	21	—	11,626	11,752	(71)%	*nm	(99)%	(99)%
Total	2,528	1,627	41,959	66,889	1,830	—	78,417	89,397	38%	*nm	(46)%	(25)%

* Not meaningful.

(1) Prior to 2013, NGL volumes were included in natural gas production data, which impacts the comparability for the two periods presented.

(2) Other includes PRB–CBM natural gas volumes of 8,510 MMcf for 2012 and Wind River natural gas production volumes of 3,059 MMcf and oil production of 15 MBbls for 2012.

Hedging Activities. During the nine months ended September 30, 2013, approximately 83% of our oil volumes, 88% of our natural gas volumes and 15% of our NGL related volumes were subject to financial hedges, which resulted in increases in natural gas revenues of $7.8 million and NGL revenues of $2.4 million, partially offset by a decrease in oil revenues of $1.3 million after settlements for all commodity derivatives. Of the $8.9 million total settlements for the nine months ended

38

September 30, 2013, $5.9 million was included in oil, gas and NGL production revenues and $3.0 million was included in commodity derivative gain (loss) in the Unaudited Statements of Operations. During the nine months ended September 30, 2012, approximately 77% 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 22% of our NGL related volumes were subject to financial hedges, which resulted in a increases in oil revenues of $7.5 million and natural gas revenues of $94.2 million after settlements for all commodity derivatives. Of the $101.7 million total settlements for the nine months ended September 30, 2012, $66.7 million was included in oil, gas and NGL production revenues and $35.0 million was included in commodity derivative gain (loss) in the Unaudited Statements of Operations. We may not always be able to generate increases in revenue based on hedge settlements due to the volatility of prices for oil, natural gas and NGLs and current market conditions.

Other Operating Revenues. Other operating revenues increased to $5.0 million for the nine months ended September 30, 2013 from $3.8 million for the nine months ended September 30, 2012. Other operating revenues for the nine months ended September 30, 2013 primarily consisted of $3.2 million in net gains realized from the sale of properties and $1.8 million of income from gathering and compression fees received from third parties. Other operating revenues for the nine months ended September 30, 2012 consisted of $2.4 million of income from gathering, compression and salt-water disposal fees received from third parties and $1.4 million of income from the sale of seismic data.

Lease Operating Expense. LOE increased to $0.79 per Mcfe for the nine months ended September 30, 2013 from $0.61 per Mcfe for the nine months ended September 30, 2012. LOE on a per Mcfe basis is inherently higher for our oil producing properties such as those in our Uinta Oil and DJ Basin development areas. In addition, the sale of natural gas properties with lower LOE per Mcfe in the 2012 Divestiture also contributed to a higher LOE per Mcfe unit cost in the nine months ended September 30, 2013.

Gathering, Transportation and Processing Expense. GTP expense decreased to $0.76 per Mcfe for the nine months ended September 30, 2013 from $0.89 per Mcfe for the nine months ended September 30, 2012. GTP expense for the nine months ended September 30, 2013 decreased primarily due to a change in reporting an oil transportation deduction related to certain production within the Uinta Oil Program as a charge against production revenues as of January 1, 2013. These costs were previously included within GTP for the nine months ended September 30, 2012. The effect on the average per unit oil price is approximately $1.95 per barrel, which reduces GTP by approximately $0.07 per Mcfe for the nine months ended September 30, 2013.

Production Tax Expense. Total production taxes increased to $21.9 million for the nine months ended September 30, 2013 from $21.2 million for the nine months ended September 30, 2012. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments was 5.2% and 4.7% for the nine months ended September 30, 2013 and 2012, respectively.

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 increase in the overall production tax rate is consistent with our production increase in areas with higher production tax rates.

Exploration Expense. Exploration expense decreased to $0.2 million for the nine months ended September 30, 2013 from $8.1 million for the nine months ended September 30, 2012. Exploration expense for the nine months ended September 30, 2013 consisted of $0.2 million for delay rentals across all basins. Exploration expense for the nine months ended September 30, 2012 consisted of $7.3 million of geological and geophysical seismic programs and $0.8 million for delay rentals across all basins.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $227.6 million for the nine months ended September 30, 2013 from $60.2 million for the nine months ended September 30, 2012. For the nine months ended September 30, 2013, impairment expense was $216.6 million, abandonment expense was $10.1 million and dry hole costs were $0.9 million. The $216.6 million of impairment expense for the nine months ended September 30, 2013 included $198.8 million related to proved oil and gas properties and $17.8 million related to unproved oil and gas properties. We classified our natural gas properties in the West Tavaputs field in the Uinta Basin as held for sale as of September 30, 2013. Upon the classification as held for sale, the carrying value of the related properties was analyzed relative to the estimated fair value. As a result, we recognized $198.8 million of proved impairment expense and $2.5 million of unproved impairment expense during the nine months ended September 30, 2013. In addition, we recognized $15.3 million of impairment expense related to certain unproved oil and gas properties within exploration projects primarily as a result of no future plans to evaluate the remaining acreage and an estimated market value below our carrying value.

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For the nine months ended September 30, 2012, impairment expense was $37.1 million, abandonment expense was $7.2 million and dry hole costs were $15.9 million. The $37.1 million of impairment expense related to impairing 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.

Depreciation, Depletion and Amortization. DD&A decreased to $214.8 million for the nine months ended September 30, 2013 compared with $251.4 million for the nine months ended September 30, 2012. The decrease of $36.6 million was a result of the 25%decrease in production for the nine months ended September 30, 2013 compared with the nine months ended September 30, 2012, offset by an increase in the DD&A rate. The decrease in production accounted for a $63.3 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $26.7 million of additional DD&A expense. The increase in the DD&A rate during the nine months ended September 30, 2013 compared with the nine months ended September 30, 2012 was due to an increase in oil projects, which have higher capital costs compared to natural gas projects.

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 nine months ended September 30, 2013, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $3.21 per Mcfe compared with $2.81 per Mcfe for the nine months ended September 30, 2012. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, decreased to $36.3 million for the nine months ended September 30, 2013 from $39.0 million for the nine months ended September 30, 2012. The decrease of $2.7 million was primarily the result of a 17% decrease in the number of employees as of September 30, 2013 compared to September 30, 2012. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 37 for a reconciliation and explanation. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $0.54 per Mcfe for the nine months ended September 30, 2013 from $0.44 per Mcfe for the nine months ended September 30, 2012, largely due to the 25%decrease in production as the result of the 2012 Divestiture. This is a non-GAAP measure. See Note 5 to the table on page 37 for a reconciliation and explanation.

Non-cash charges for stock-based compensation for the nine months ended September 30, 2013 and the nine months ended September 30, 2012 were $12.0 million and $12.4 million, respectively. Non-cash stock-based compensation expense for each of the nine months ended September 30, 2013 and 2012 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 nine months ended September 30, 2013 and 2012 are shown in the following table:

	Nine Months Ended September 30,
	2013		2012
	(in thousands)
Stock options and nonvested equity shares of common stock	$	11,080	$	11,652
Shares issued for 401(k) plan	602		596
Shares issued for directors’ fees	297		167
Total	$	11,979	$	12,415

Interest Expense. Interest expense decreased to $69.3 million for the nine months ended September 30, 2013 from $70.0 million for the nine months ended September 30, 2012. The decrease for the nine months ended September 30, 2013 was primarily due to a lower weighted average interest rate as a result of the redemption of the 9.875% Senior Notes on July 15, 2013, offset by higher weighted average outstanding borrowings. Our weighted average interest rate for the nine months ended September 30, 2013 was 7.5% compared to 8.5% for the nine months ended September 30, 2012, and our weighted average outstanding borrowings for the nine months ended September 30, 2013 were $1,225.3 million compared with $1,100.6 million for the nine months ended September 30, 2012.

Commodity Derivative Gain (Loss).Commodity derivative gain (loss)decreased to a loss of $18.6 million for the nine months ended September 30, 2013 compared with a gain of $53.4 million for the nine months ended September 30, 2012 primarily due to the decrease in our gains from oil contracts resulting from an increase in future oil commodity pricing, as well

40

as a decrease in gains from natural gas hedging contracts resulting from lower natural gas volumes hedged as of September 30, 2013 compared with September 30, 2012.

The table below summarizes the Company's commodity derivative gains and losses that were recognized in the periods presented:

	Nine Months Ended September 30,
	2013			2012
	(in thousands)
Realized gain on derivatives not designated as cash flow hedges (1)	$	2,971		$	35,014
Unrealized gain (loss) on derivatives not designated as cash flow hedges (1)	(21,578		)	18,417
Total commodity derivative gain (loss)	$	(18,607	)	$	53,431

(1) Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of the Company's hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

Income Tax Benefit. Income tax benefit totaled $111.3 million for the nine months ended September 30, 2013 compared to an income tax benefit of $7.9 million for the nine months ended September 30, 2012, resulting in effective tax rates of 37.5% and 37.2%, respectively. For both the 2013 and 2012 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording 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. The increase in the effective tax rate is mainly a result of the relationship of these items to book income.

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 sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration 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. 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.

Total consideration for the divestiture of our West Tavaputs natural gas assets, prior to customary closing adjustments, will be $371.5 million and includes approximately $46.0 million for the purchaser’s assumption of the Lease Financing Obligation commitment for compressor units on the property. The transaction is expected to close by the end of 2013. Cash proceeds will be used to pay down our outstanding balance under the Amended Credit Facility.

At September 30, 2013, we had cash and cash equivalents of $60.5 million and a $390.0 million balance outstanding under our Amended Credit Facility. As of September 30, 2013, the commitments on our Amended Credit Facility were $825.0 million. Our borrowing capacity is further reduced by $26.0 million to $409.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement. The borrowing base is required to be re-determined twice per year. On October 25, 2013, the borrowing base was redetermined at $825.0 million based on mid-year reserves and hedge position. The borrowing base will be reduced upon closing of the West Tavaputs Sale. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.

Cash Flow from Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2013 and 2012 was $196.3 million and $290.6 million, respectively. Cash provided by operating activities decreased primarily due to the 25% decrease in production volumes, which resulted in a $92.4 million million reduction in revenues, offset by reductions in cash operating expenses.

41

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 contracts to receive fixed prices for a portion of our 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. At September 30, 2013, we had in place crude oil and natural gas swaps covering portions of our 2013, 2014 and 2015 production and NGL swaps covering portions of our 2013 and 2014 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil, natural gas and NGLs that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, gas and NGL 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. All changes in the derivative’s fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.

At September 30, 2013, the estimated fair value of all of our commodity derivative instruments was a net asset of $5.1 million, comprised of current and noncurrent assets and current 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, natural gas and NGL production operating revenues as the hedged production quantities are produced.

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Commodity derivative settlements on derivatives designated as cash flow hedges(1)	$	1,899		$	20,391		$	5,902		$	66,654
Realized gains (losses) on derivatives not designated as cash flow hedges(2) (3)	$	(3,255	)	$	12,295		$	2,971		$	35,014
Unrealized gains (losses) on derivatives not designated as cash flow hedges(2) (3)	(22,340		)	(50,635		)	(21,578		)	18,417
Total commodity derivative gain (loss)	$	(25,595	)	$	(38,340	)	$	(18,607	)	$	53,431

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

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

(3) Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of the Company's hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

The following table summarizes all of our hedges in place as of September 30, 2013:

42

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price(1)	Fair Market Value (in thousands)
Swap Contracts:
2013
Natural gas	460,000	MMBtu	$	5.01	CIG	$	730
Natural gas	10,895,000	MMBtu	$	3.67	NWPL	2,294
Natural gas liquids(2)	98,214	Bbls	$	69.47	Mt. Belvieu	782
Oil	806,300	Bbls	$	98.01	WTI	(2,847		)
2014
Natural gas	30,415,000	MMBtu	$	3.87	NWPL	5,399
Natural gas liquids(2)	35,714	Bbls	$	42.00	Mt. Belvieu	5
Oil	2,972,200	Bbls	$	94.46	WTI	(3,259		)
2015
Natural gas	3,650,000	MMbtu	$	4.25	NWPL	1,583
Oil	401,200	Bbls	$	89.64	WTI	390
Total						$	5,077

The following table includes all hedges entered into subsequent to September 30, 2013 through October 18, 2013:

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price(1)
Swap Contracts:
2014
Oil	55,200	Bbls	$	93.08	WTI
2015
Oil	200,300	Bbls	$	90.84	WTI

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

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

By removing the price volatility from a portion of our oil and natural gas related revenue for 2013, 2014 and 2015 and NGL related revenue for 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.

It is our 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. One counterparty that was a lender in the Amended Credit Facility withdrew from the facility when we amended the facility in October 2011. We will continue to monitor the creditworthiness of this counterparty during the remaining duration of the derivatives that were entered into while that counterparty was a lender in the Amended Credit Facility. Our 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. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed us under derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.

Capital Expenditures

43

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

	Nine Months Ended September 30,
Basin/Area	2013		2012
	(in millions)
Piceance	$	4.5	$	193.2
Uinta – West Tavaputs	0.3		92.3
Uinta Oil Program	193.3		242.6
DJ	119.5		176.5
Powder River Oil	42.0		27.6
Other	3.5		46.3
Total	$	363.1	$	778.5

	Nine Months Ended September 30,
	2013		2012
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	11.0	$	133.7
Drilling, development, exploration and exploitation of oil and natural gas properties (1)	350.8		631.8
Geologic and geophysical costs	0.2		8.0
Furniture, fixtures and equipment	1.1		5.0
Total	$	363.1	$	778.5

(1) Includes related gathering and facilities costs.

Our current estimated capital expenditure budget in 2013 is $465.0 million to $485.0 million, with all drilling activities targeting oil. The budget includes facilities costs and excludes material acquisitions. We may adjust capital expenditures throughout the year as business conditions and operating results warrant. We believe that we have sufficient available liquidity through 2013 and 2014 with available cash under the Amended Credit Facility and cash flow from operations to fund our budgeted capital expenditures. Future cash flows are subject to a number of variables, including our level of oil, natural gas and NGL production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

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

Financing Activities

Amended Credit Facility

Our Amended Credit Facility has a maturity date of October 31, 2016, and current commitments and borrowing base of $825.0 million. Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility was 2.1% and 1.8% for the three months ended September 30, 2013 and 2012, and 2.0% and 1.9% for the nine months ended September 30, 2013 and 2012, respectively.

The borrowing base is required to be re-determined twice per year. On October 25, 2013 the borrowing base was redetermined at $825.0 million based on mid-year reserves and hedge position. The borrowing base will be reduced upon closing of the West Tavaputs Sale. Future semi-annual borrowing bases under our credit facility will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.

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The Amended Credit Facility is secured by oil and natural gas properties representing at least 80% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since origination. As of September 30, 2013, we had $390.0 million outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, which reduced the borrowing capacity of the Amended Credit Facility to $409.0 million as of September 30, 2013.

9.875% Senior Notes Due 2016

On July 15, 2013, we redeemed the entire outstanding $250.0 million principal amount of 9.875% Senior Notes for a redemption price of 104.938% of the principal amount of the notes, or $262.3 million. Unamortized debt discount and deferred financing costs related to the notes resulted in a loss upon settlement of $21.4 million for the three and nine months ended September 30, 2013.

5% Convertible Senior Notes Due 2028

On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to us and were redeemed by us at par. We settled the notes in cash. 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 us. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, are senior in right of payment to all of our future subordinated indebtedness, and are effectively subordinated to all of our 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 our subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, 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 us 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. We have the right with at least 30 days’ notice to call the Convertible Notes.

7.625% Senior Notes Due 2019

On September 27, 2011, we issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The 7.625% Senior Notes are callable by us on October 1, 2015 at 103.813% of the par value of the notes. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. The 7.625% Senior Notes are redeemable at our option at a redemption price of 103.813% of the principal amount of the notes on October 1, 2015.

7.0% Senior Notes Due 2022

On March 12, 2012, we issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes 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 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at our option on October 15, 2017 at a redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

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Lease Financing Obligation Due 2020

On July 23, 2012, we entered into a lease financing arrangement with Bank of America Leasing & Capital, LLC as the lead bank (the “Lease Financing Obligation”) whereby we received $100.8 million through the sale and subsequent leaseback of existing compressors and related facilities owned by us. The Lease Financing Obligation expires on August 10, 2020, and we have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option where we may purchase the equipment for $36.6 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. As part of the previously announced purchase and sale agreement for the Company's West Tavaputs natural gas properties in the Uinta Basin, the purchaser will assume approximately 51% of the lease financing obligation, including the buy-out options.

Our outstanding debt is summarized below:

		As of September 30, 2013						As of December 31, 2012
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount			Carrying Amount
		(in thousands)
Amended Credit Facility (1)	October 31, 2016	$	390,000	$	—	$	390,000	$	—	$	—		$	—
9.875% Senior Notes (2)	July 15, 2016	—		—		—		250,000		(7,209		)	242,791
Convertible Notes (3)	March 15, 2028 (4)	25,344		—		25,344		25,344		—			25,344
7.625% Senior Notes (5)	October 1, 2019	400,000		—		400,000		400,000		—			400,000
7.0% Senior Notes (6)	October 15, 2022	400,000		—		400,000		400,000		—			400,000
Lease Financing Obligation (7)	August 10, 2020	44,453		—		44,453		97,596		—			97,596
Total Debt		$	1,259,797	$	—	$	1,259,797	$	1,172,940	$	(7,209	)	$	1,165,731
Less: Current Portion of Long-Term Debt		4,554		—		4,554		9,077		—			9,077
Total Long-Term Debt (8)		$	1,255,243	$	—	$	1,255,243	$	1,163,863	$	(7,209	)	$	1,156,654

(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 $271.9 million as of December 31, 2012 based on reported market trades of these instruments. We redeemed these notes in full on July 15, 2013.

(3) The aggregate estimated fair value of the Convertible Notes was approximately $25.2 million and $25.3 million as of September 30, 2013 and December 31, 2012, respectively, based on reported market trades of these instruments.

(4) We have the right at any time with at least 30 days’ notice to call the Convertible Notes, and the holders have the right to require us 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 $410.0 million and $435.0 million as of September 30, 2013 and December 31, 2012, respectively, based on reported market trades of these instruments.

(6) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $390.0 million and $413.8 million as of September 30, 2013 and December 31, 2012, respectively, based on reported market trades of these instruments.

(7) The aggregate estimated fair value of the Lease Financing Obligation was approximately 88.1 million and $97.7 million as of September 30, 2013 and December 31, 2012, respectively. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.

(8) The total debt balance shown here excludes $46.4 million related to the Lease Financing Obligation that is included in liabilities associated with assets held for sale line item in the Unaudited Consolidated Balance Sheet, see Note 4 for additional information.

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. Moody’s Investor Services and Standard & Poor’s Rating Services currently rate our 7.625% Senior Notes and 7.0% Senior Notes and have assigned a credit rating. 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, 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.

Contractual Obligations. A summary of our contractual obligations as of and subsequent to September 30, 2013 is provided in the following table:

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	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)	$	553	$	553	$	553	$	390,553	$	322	$	—	$	392,534
7.625% Senior Notes (2)	30,500		30,500		30,500		30,500		30,500		430,500		583,000
7.0% Senior Notes (3)	28,000		28,000		28,000		28,000		28,000		513,167		653,167
Convertible Notes (4)	1,267		25,946		—		—		—		—		27,213
Lease Financing Obligation (5)	12,139		12,139		12,139		12,139		12,139		23,263		83,958
Purchase commitments (6)(7)	—		—		1,681		—		—		—		1,681
Office and office equipment leases and other (8)	3,944		4,073		2,683		2,506		2,523		1,268		16,997
Firm transportation and processing agreements (7)(9)	57,849		58,171		57,187		52,984		50,607		109,918		386,716
Asset retirement obligations (10)	948		704		772		1,125		1,100		47,673		52,322
Derivative liability (11)	2,271		—		—		—		—		—		2,271
Total	$	137,471	$	160,086	$	133,515	$	517,807	$	125,191	$	1,125,789	$	2,199,859

(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.

(2) 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.

(3) 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.

(4) 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 us. We 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 we call the remaining Convertible Notes or the holders put the Convertible Notes to us, which is expected to occur by 2015.

(5) The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments. The balance shown here includes the approximately 51% of the Lease Financing Obligation that the purchaser in the previously mentioned purchase and sale agreement for the Company's natural gas assets in the Uinta Basin will assume upon closing of the transaction in December 2013.

(6) We have one take-or-pay carbon dioxide purchasing agreement that 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. If we do not take delivery of the minimum volume required, we are obligated to pay for the deficiency. As of September 30, 2013, $1.7 million of the future commitment is due by December 31, 2015.

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

(9) 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 2 to 10 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. The balance shown here includes $137.7 million of transportation demand and firm processing charges that the purchaser in the previously mentioned purchase and sale agreement of our West Tavaputs natural gas assets in the Uinta Basin will assume upon closing of the transaction in December 2013.

(10) 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. This balance includes asset retirement obligations of $13.1 million at September 30, 2013 related to the natural gas assets in the Uinta Basin that will be sold in December 2013 in the previously mentioned purchase and sale agreement.

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(11) Derivative liabilities represent the net fair value for oil, gas and NGL commodity derivatives presented as liabilities in our Unaudited Consolidated Balance Sheets as of September 30, 2013. 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, 2012 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, 2012 for a discussion of trends and uncertainties that may affect our financial condition or liquidity.

The well completion technique known as hydraulic fracturing, used to stimulate production of natural gas and oil, has come under increased scrutiny by the environmental community, and at all levels of government. We use this completion technique on substantially all of our wells. Legislation and additional regulation has been proposed, including by ballot initiative in certain local jurisdictions, and moratoria have been imposed or proposed in certain Colorado jurisdictions where we do not currently have operations. Although we cannot predict the outcome of legislative, regulatory and ballot initiative proposals, any new restrictions that may be imposed statewide or in areas in which we conduct business could result in increased compliance costs or additional operating restrictions. If the use of hydraulic fracturing is limited or prohibited, our future ability to develop natural gas and oil would be negatively impacted.

A substantial or extended decline in oil, natural gas or NGL prices may result in impairments of our proved 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. We are currently exploring several property sales or other alternatives which may or may not result in future impairments or losses. To the extent commodity prices or volumes 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. We have protected the cash flow from approximately 70% of our anticipated 2013 production and a portion of our anticipated 2014 and 2015 production with hedges. 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.

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, 2012 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, natural gas and NGL 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. Commodity 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 nine months ended September 30, 2013, our annual revenues would have decreased by approximately $0.3 million for each $1.00 per barrel decrease in crude oil prices, $0.6 million for each $0.10 decrease per MMBtu in natural gas prices and $1.3 million for each $1.00 per barrel decrease in NGL prices. We are more susceptible to proved and unproved property impairments due to the current commodity price environment.

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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. These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations.

As of October 18, 2013, 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.”

	October – December 2013	For the year 2014	For the year 2015
Oil (Bbls)	806,300	3,027,400	601,500
Natural Gas (MMbtu)	11,355,000	30,415,000	3,650,000
Natural Gas Liquids (Bbls)	98,214	35,714	—

Interest Rate Risks

At September 30, 2013, we had $390.0 million outstanding under our Amended Credit Facility, which bears interest at floating rates. The average annual interest rate incurred on this debt for the nine months ended September 30, 2013 was 2.0%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2013 would have resulted in an estimated $1.9 million increase in interest expense assuming a similar average debt level to the nine months ended September 30, 2013. The average annual interest rate incurred on this debt for the nine months ended September 30, 2012 was 1.9%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2012 would have resulted in an estimated $0.6 million increase in interest expense assuming a similar average debt level to the nine months ended September 30, 2012. We also had $25.3 million principal amount of Convertible Notes (with a fixed cash interest rate of 5%), $400.0 million principal amount of 7.625% Senior Notes, $400.0 million principal amount of 7.0% Senior Notes and $90.8 million principal amount of 3.3% Lease Financing Obligation outstanding at September 30, 2013.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of September 30, 2013, 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 September 30, 2013.

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the third fiscal quarter of 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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, 2012. 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, 2012 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

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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 September 30, 2013:

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
July 1 – 31, 2013	1,620	$	21.51	—	—
August 1 – 31, 2013	427	21.39		—	—
September 1 – 30, 2013	1,340	25.12		—	—
Total	3,387	$	22.93	—	—

(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 restricted 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.

Item 5.    Other Information.

Not applicable.

Item 6.   Exhibits.

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Exhibit Number	Description of Exhibits
2	Purchase and Sale Agreement dated October 22, 2013 between Bill Barrett Corporation and Enervest Energy Institutional Fund XIII-A, Enervest Energy Institutional Fund XIII-WIB, L.P., and Enervest Energy Institutional Fund XIII-WIC, L.P. [Incorporated by reference to Exhibit 2 of our Current Report on Form 8-K filed with the Commission on October 25, 2013.]
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Appendix A to 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.]
4.3(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)	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(c)	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.]

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4.4	Form of Rights Agreement concerning Shareholder Rights Plan, which includes, as Exhibit A thereto, the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and, as Exhibit B thereto, the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5	Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.6	Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit 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 September 30, 2013 (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 Comprehensive Income (Loss), (v) the Unaudited Consolidated Statements of Cash Flows, and (vi) Notes to the Unaudited Consolidated Financial Statements.

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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:	October 31, 2013	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President
			(Principal Executive Officer)
Date:	October 31, 2013	By:	/s/ Robert W. Howard
			Robert W. Howard
			Chief Financial Officer
			(Principal Financial Officer)

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