Bill Barrett (BBG) 10-Q 2014 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2014

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 49,650,853 shares of $0.001 par value common stock outstanding on October 17, 2014.

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	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47
Item 4.	Controls and Procedures	48
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Mine Safety Disclosures	49
Item 5.	Other Information	49
Item 6.	Exhibits	49
SIGNATURES		52

2

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2014			December 31, 2013
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	294,778		$	54,595
Accounts receivable, net of allowance for doubtful accounts	88,554			97,586
Derivative assets	11,095			173
Prepayments and other current assets	3,515			4,893
Total current assets	397,942			157,247
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	1,863,478			2,863,923
Unproved oil and gas properties, excluded from amortization	282,822			296,599
Furniture, equipment and other	38,968			41,726
	2,185,268			3,202,248
Accumulated depreciation, depletion, amortization and impairment	(469,015		)	(999,752		)
Total property and equipment, net	1,716,253			2,202,496
Deferred financing costs and other noncurrent assets	23,089			21,770
Total	$	2,137,284		$	2,381,513
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities	$	154,920		$	115,928
Amounts payable to oil and gas property owners	28,510			26,778
Production taxes payable	45,690			39,235
Derivative liabilities	—			5,988
Deferred income taxes	4,065			199
Current portion of long-term debt	441			4,591
Total current liabilities	233,626			192,719
Long-term debt	828,624			979,082
Asset retirement obligations	19,569			39,200
Deferred income taxes	113,524			161,326
Derivatives and other noncurrent liabilities	2,997			3,468
Stockholders' equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 49,660,677 and 49,152,448 shares issued and outstanding at September 30, 2014 and December 31, 2013, respectively, with 1,588,591 and 1,340,060 shares subject to restrictions, respectively	48			48
Additional paid-in capital	912,026			904,261
Retained earnings	26,756			100,740
Treasury stock, at cost: zero shares at September 30, 2014 and December 31, 2013, respectively	—			—
Accumulated other comprehensive income	114			669
Total stockholders' equity	938,944			1,005,718
Total	$	2,137,284		$	2,381,513

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,
	2014			2013			2014			2013
	(in thousands, except share and per share data)
Operating and Other Revenues:
Oil, gas and NGL production	$	134,342		$	149,345		$	397,731		$	424,130
Other	921			(790		)	7,658			5,001
Total operating and other revenues	135,263			148,555			405,389			429,131
Operating Expenses:
Lease operating expense	16,284			18,280			48,367			53,138
Gathering, transportation and processing expense	10,784			16,374			34,238			50,734
Production tax expense	10,495			8,183			27,770			21,915
Exploration expense	23			(24		)	442			212
Impairment, dry hole costs and abandonment expense	29,109			219,363			32,613			227,646
Loss on divestitures	99,466			—			96,896			—
Depreciation, depletion and amortization	69,024			72,047			189,426			214,792
General and administrative expense	11,111			14,402			41,039			48,257
Total operating expenses	246,296			348,625			470,791			616,694
Operating Loss	(111,033		)	(200,070		)	(65,402		)	(187,563		)
Other Income and Expense:
Interest and other income	264			52			991			123
Interest expense	(18,033		)	(20,078		)	(53,285		)	(69,346		)
Commodity derivative gain (loss)	72,299			(25,595		)	369			(18,607		)
Loss on extinguishment of debt	—			(21,460		)	—			(21,460		)
Total other income and expense	54,530			(67,081		)	(51,925		)	(109,290		)
Loss before Income Taxes	(56,503		)	(267,151		)	(117,327		)	(296,853		)
Benefit from Income Taxes	(21,854		)	(100,495		)	(43,343		)	(111,319		)
Net Loss	$	(34,649	)	$	(166,656	)	$	(73,984	)	$	(185,534	)
Net Loss Per Common Share, Basic	$	(0.72	)	$	(3.51	)	$	(1.54	)	$	(3.91	)
Net Loss Per Common Share, Diluted	$	(0.72	)	$	(3.51	)	$	(1.54	)	$	(3.91	)
Weighted Average Common Shares Outstanding, Basic	48,060,086			47,535,124			47,982,992			47,452,865
Weighted Average Common Shares Outstanding, Diluted	48,060,086			47,535,124			47,982,992			47,452,865

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,
	2014			2013			2014			2013
	(in thousands)
Net Loss	$	(34,649	)	$	(166,656	)	$	(73,984	)	$	(185,534	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(219		)	(1,186		)	(555		)	(3,688		)
Other comprehensive loss	(219		)	(1,186		)	(555		)	(3,688		)
Comprehensive Loss	$	(34,868	)	$	(167,842	)	$	(74,539	)	$	(189,222	)

See notes to Unaudited Consolidated Financial Statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Operating Activities:
Net Loss	$	(73,984	)	$	(185,534	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	189,426			214,792
Deferred income tax benefit	(43,604		)	(110,036		)
Impairment, dry hole costs and abandonment expense	32,613			227,646
Total commodity derivative (gain) loss	(369		)	18,607
Settlements of commodity derivatives	(21,580		)	2,971
Stock compensation and other non-cash charges	9,651			12,681
Amortization of debt discounts and deferred financing costs	3,200			4,535
Loss on extinguishment of debt	—			21,460
(Gain) Loss on sale of properties	96,896			(3,102		)
Change in operating assets and liabilities:
Accounts receivable	9,025			12,343
Prepayments and other assets	914			1,475
Accounts payable, accrued and other liabilities	20,723			(24,801		)
Amounts payable to oil and gas property owners	1,936			6,510
Production taxes payable	6,455			(3,245		)
Net cash provided by operating activities	231,302			196,302
Investing Activities:
Additions to oil and gas properties, including acquisitions	(425,978		)	(335,597		)
Additions of furniture, equipment and other	(2,110		)	(1,506		)
Proceeds from sale of properties and other investing activities	557,747			784
Net cash provided by (used in) investing activities	129,659			(336,319		)
Financing Activities:
Proceeds from debt	165,000			390,000
Principal payments on debt	(283,442		)	(269,125		)
Proceeds from stock option exercises	126			1,653
Deferred financing costs and other	(2,462		)	(1,426		)
Net cash provided by (used in) financing activities	(120,778		)	121,102
Increase (Decrease) in Cash and Cash Equivalents	240,183			(18,915		)
Beginning Cash and Cash Equivalents	54,595			79,445
Ending Cash and Cash Equivalents	$	294,778		$	60,530

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, 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		6,384			—			(1,778		)	—			4,607
APIC pool for excess tax benefits related to share-based compensation	—		(1,259		)	—			—			—			(1,259		)
Stock-based compensation	—		16,991			—			—			—			16,991
Retirement of treasury stock	—		(1,778		)	—			1,778			—			—
Net loss	—		—			(192,733		)	—			—			(192,733		)
Effect of derivative financial instruments, net of $2,802 of taxes	—		—			—			—			(4,663		)	(4,663		)
Balance at December 31, 2013	$	48	$	904,261		$	100,740		$	—		$	669		$	1,005,718
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	—		126			—			(2,462		)	—			(2,336		)
Stock-based compensation	—		10,101			—			—			—			10,101
Retirement of treasury stock	—		(2,462		)	—			2,462			—			—
Net loss	—		—			(73,984		)	—			—			(73,984		)
Effect of derivative financial instruments, net of $334 of taxes	—		—			—			—			(555		)	(555		)
Balance at September 30, 2014	$	48	$	912,026		$	26,756		$	—		$	114		$	938,944

See notes to Unaudited Consolidated Financial Statements.

7

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2014

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. The Company's Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company's 2013 Annual Report on Form 10-K.

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 compensation awards.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of September 30, 2014			As of December 31, 2013
	(in thousands)
Accrued oil, gas and NGL sales	$	58,175		$	67,583
Due from joint interest owners	25,339			23,507
Other	5,054			6,517
Allowance for doubtful accounts	(14		)	(21		)
Total accounts receivable	$	88,554		$	97,586

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 remain 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 and remain within cash flows from investing

8

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. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

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. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters.

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

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

	As of September 30, 2014			As of December 31, 2013
	(in thousands)
Proved properties	$	382,867		$	485,427
Wells and related equipment and facilities	1,406,678			2,192,754
Support equipment and facilities	60,588			177,224
Materials and supplies	13,345			8,518
Total proved oil and gas properties	$	1,863,478		$	2,863,923
Unproved properties	185,237			239,925
Wells and facilities in progress	97,585			56,674
Total unproved oil and gas properties, excluded from amortization	$	282,822		$	296,599
Accumulated depreciation, depletion, amortization and impairment	(443,748		)	(976,339		)
Total oil and gas properties, net	$	1,702,552		$	2,184,183

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, 2014 and December 31, 2013, 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 a quarterly 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 revenues, 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.

9

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:

	Three Months Ended September 30,							Nine Months Ended September 30,
	2014			2013				2014			2013
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	11,493	(1)	$	198,787		(2)	$	12,531	(3)	$	198,787	(2)
Non-cash impairment of unproved oil and gas properties	15,250		(1)	17,777			(2)	15,250		(3)	17,777		(2)
Non-cash impairment of inventory	—			—				340			—
Dry hole costs	3			(36		)		96			928
Abandonment expense	2,363			2,835				4,396			10,154
Total non-cash impairment, dry hole costs and abandonment expense	$	29,109		$	219,363			$	32,613		$	227,646

(1) As a result of the Powder River Oil Divestiture (see Note 4) and results of drilling and completion activity in the Paradox Basin during the three months ended September 30, 2014, the remaining carrying values of Powder River Oil and Paradox Basin assets were analyzed relative to their estimated fair market values. As a result, the Company recognized proved and unproved property impairments of $11.5 million and $15.3 million, respectively.

(2) 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 (see Note 4). 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 and 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 various exploration and development projects primarily as a result of no future plans to evaluate the remaining acreage and an estimated market value below our carrying value.

(3) As a result of the Powder River Oil Divestiture and results of drilling and completion activity in the Paradox Basin during the nine months ended September 30, 2014, the remaining carrying values of Powder River Oil and Paradox Basin assets were analyzed relative to their estimated fair market values. As a result, the Company recognized proved and unproved property impairments of $11.5 million and $15.3 million, respectively. In addition, $1.0 million of proved impairment expense was incurred during the nine months ended September 30, 2014 related to the West Tavaputs Divestiture (see Note 4) based upon a true up of previously estimated fair value relative to carrying value.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs 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, 2014		As of December 31, 2013
	(in thousands)
Accrued drilling, completion and facility costs	$	85,517	$	54,750
Accrued lease operating, gathering, transportation and processing expenses	13,025		17,317
Accrued general and administrative expenses	7,042		14,605
Trade payables and other	49,336		29,256
Total accounts payable and accrued liabilities	$	154,920	$	115,928

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. Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured.

10

The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenues are 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 taken into account in determining the Company's proved oil, gas and NGL reserves. Imbalances at September 30, 2014 and 2013 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.

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 income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company's common stock and shares into which the Convertible Notes are convertible. 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, 2014 and 2013.

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, 2014, 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 income (loss) per common share calculation for the three and nine months ended September 30, 2014 and 2013. The diluted net income (loss) per common share excludes the anti-dilutive effect of 1,336,252 and 2,450,539 shares of stock options and nonvested performance-based shares of common stock for the three months ended September 30, 2014 and 2013, and 1,199,451 and 2,731,578 shares of stock options and nonvested performance-based shares of common stock for the nine months ended September 30, 2014 and 2013, respectively.

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

11

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except per share amounts)
Net loss	$	(34,649	)	$	(166,656	)	$	(73,984	)	$	(185,534	)
Basic weighted-average common shares outstanding in period	48,060			47,535			47,983			47,453
Add dilutive effects of stock options and nonvested equity shares of common stock	—			—			—			—
Diluted weighted-average common shares outstanding in period	48,060			47,535			47,983			47,453
Basic net loss per common share	$	(0.72	)	$	(3.51	)	$	(1.54	)	$	(3.91	)
Diluted net loss per common share	$	(0.72	)	$	(3.51	)	$	(1.54	)	$	(3.91	)

New Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the potential impact that the adoption will have on the Company’s disclosures and financial statements.

In June 2014, the FASB issued ASU 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. The objective of this update is to provide guidance on the treatment of a performance target that could be achieved after the requisite service period. ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company's consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The objective of this update is to provide guidance in GAAP about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The adoption of this standard will not have an impact on the Company's consolidated financial statements.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Cash paid for interest	$	36,267		$	61,796
Cash paid for income taxes	1			1,861
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities	90,381			75,265
Net increase (decrease) in asset retirement obligations	(23,327		)	2,924
Retirement of treasury stock	(2,462		)	(1,415		)
Fair value of properties exchanged in non-cash transactions	77,078			—
Relief from lease financing obligation	36,106			45,190

4. Divestitures

On December 10, 2013, the Company completed the sale of its West Tavaputs natural gas assets in the Uinta Basin (the "West Tavaputs Divestiture"). The Company received $308.7 million in cash proceeds, after closing adjustments. The divestiture proceeds were subject to various purchase price adjustments incurred in the normal course of business and were

12

finalized during 2014. The Company recognized an impairment loss of $1.0 million during the nine months ended September 30, 2014 related to these assets based upon a true up of previously estimated fair value relative to carrying value. An initial impairment loss of $209.5 million related to these assets was recognized during the year ended December 31, 2013.

During the three months ended September 30, 2014, the Company completed the sale or exchange of the majority of its Powder River Basin assets (the "Powder River Oil Divestiture") in four separate transactions with effective dates of April 1, 2014 for net cash proceeds of $27.4 million, after initial closing adjustments. Three transactions involved the cumulative sale of 17,497 net mineral acres. The fourth transaction involved an exchange of 29,015 net mineral acres in the Powder River Basin for 7,856 net mineral acres within the southern block of the Company’s operated Northeast Wattenberg area of the Denver-Julesburg Basin, valued at $71.0 million. Assets sold or exchanged as part of the overall Powder River Oil Divestiture included $85.7 million in proved and $39.7 million in unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of $33.1 million and $1.3 million in asset retirement obligations. A loss on sale of $25.7 million related to these transactions is included within operating expenses in the Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2014. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized in early 2015.

On September 30, 2014, the Company completed the sale of its Gibson Gulch natural gas program in the Piceance Basin (the "Piceance Divestiture") with an effective date of July 1, 2014. The Company received $503.6 million in cash proceeds, after initial closing estimates. In addition to the cash proceeds, the Company recognized non-cash proceeds of $22.4 million related to the relief of the Company's asset retirement obligation and $36.1 million related to relief from the Company's lease financing obligation described in Note 5 (the "Lease Financing Obligation"). A loss on sale of $74.8 million related to this transaction is included within operating expenses in the Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2014. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized in early 2015. The carrying amounts by major asset class within the disposal group for the Piceance Divestiture are summarized below (in thousands):

Assets:
Proved properties	$	1,320,757
Furniture, equipment and other	4,907
Accumulated depreciation, depletion, amortization and impairment	(688,864		)
Other assets	173
Total assets	$	636,973
Liabilities:
Asset retirement obligation	$	22,448
Lease financing obligation	36,106
Total liabilities	$	58,554
Net assets	$	578,419

5. Long-Term Debt

The Company's outstanding debt is summarized below:

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		As of September 30, 2014						As of December 31, 2013
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount		Carrying Amount
		(in thousands)
Amended Credit Facility (1)	October 31, 2016	$	—	$	—	$	—	$	115,000	$	—	$	115,000
Convertible Notes (2)	March 15, 2028 (3)	25,344		—		25,344		25,344		—		25,344
7.625% Senior Notes (4)	October 1, 2019	400,000		—		400,000		400,000		—		400,000
7.0% Senior Notes (5)	October 15, 2022	400,000		—		400,000		400,000		—		400,000
Lease Financing Obligation (6)	August 10, 2020	3,721		—		3,721		43,329		—		43,329
Total Debt		$	829,065	$	—	$	829,065	$	983,673	$	—	$	983,673
Less: Current Portion of Long-Term Debt		441		—		441		4,591		—		4,591
Total Long-Term Debt		$	828,624	$	—	$	828,624	$	979,082	$	—	$	979,082

(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 Convertible Notes was approximately $25.4 million and $25.1 million as of September 30, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.

(3) 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.

(4) The aggregate estimated fair value of the 7.625% Senior Notes was approximately $407.3 million and $430.2 million as of September 30, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.

(5) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $416.0 million and $417.0 million as of September 30, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.

(6) The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.5 million as of September 30, 2014, and $41.7 million as of December 31, 2013. The decrease in estimated fair value is primarily related to the sale of equipment in the West Tavaputs and Piceance Divestitures. 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.

Amended Credit Facility

The Company's Amended Credit Facility has a maturity date of October 31, 2016 and current commitments and borrowing base of $375.0 million. As of September 30, 2014, the Company had no amounts 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 reduced the borrowing capacity of the Amended Credit Facility as of September 30, 2014 to $349.0 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 were 2.0% and 2.1% for the three months ended September 30, 2014 and 2013, and 1.9% and 2.0% for the nine months ended September 30, 2014 and 2013, respectively.

The borrowing base is required to be re-determined twice per year. On September 30, 2014, the borrowing base was reduced to $375.0 million based on year-end 2013 reserves as adjusted for the Piceance and Powder River Oil Divestitures and the Company's hedge position. Future semi-annual 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 contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.

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

14

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

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

On July 23, 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 the result of the disposition of equipment in the West Tavaputs Divestiture and the Piceance Divestiture, the Company's remaining Lease Financing Obligation has been reduced to $3.7 million as of September 30, 2014 and the early buyout option has been reduced to $1.8 million.

The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, the 9.875% Senior Notes that were redeemed in full on July 15, 2013, 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:

15

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)
Amended Credit Facility (1)
Cash interest	$	1,771	$	2,296	$	4,392	$	4,211
Non-cash interest	$	586	$	585	$	1,757	$	1,756
9.875% Senior Notes (2)
Cash interest	$	—	$	1,029	$	—	$	13,373
Non-cash interest	$	—	$	—	$	—	$	1,361
Convertible Notes (3)
Cash interest	$	306	$	310	$	940	$	943
Non-cash interest	$	1	$	1	$	4	$	4
7.625% Senior Notes (4)
Cash interest	$	7,625	$	7,625	$	22,875	$	22,875
Non-cash interest	$	273	$	272	$	817	$	798
7.0% Senior Notes (5)
Cash interest	$	7,000	$	7,000	$	21,000	$	21,000
Non-cash interest	$	204	$	203	$	610	$	592
Lease Financing Obligation (6)
Cash interest	$	248	$	750	$	765	$	2,305
Non-cash interest	$	3	$	8	$	11	$	24

(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. The decrease in cash interest from $0.8 million to $0.2 million for the three months ended September 30, 2013 and September 30, 2014, respectively, and from $2.3 million to $0.8 million for the nine months ended September 30, 2013 and September 30, 2014, respectively, is due to the West Tavaputs Divestiture. The purchaser assumed approximately 51% of the Lease Financing Obligation, including the buyout option, related to West Tavaputs equipment.

6. Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the nine months ended September 30, 2014 is as follows (in thousands):

As of December 31, 2013	$	43,005
Liabilities incurred	3,627
Liabilities settled	(4,383		)
Disposition of properties	(23,722		)
Accretion expense	2,532
Revisions to estimate	1,151
As of September 30, 2014	$	22,210
Less: Current asset retirement obligations	2,641
Long-term asset retirement obligations	$	19,569

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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 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, 2014
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	914	$	—	$	—	$	914
Cash Equivalents - Money Market Funds	53		—		—		53
Commodity Derivatives	—		20,530		—		20,530
Liabilities
Commodity Derivatives	$	—	$	2,757	$	—	$	2,757

17

	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	941	$	—	$	—	$	941
Cash Equivalents - Money Market Funds	53		—		—		53
Commodity Derivatives	—		11,483		—		11,483
Liabilities
Commodity Derivatives	$	—	$	14,771	$	—	$	14,771

All fair values reflected in the table above and in 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 in 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 $823.3 million as of September 30, 2014. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $847.2 million as of December 31, 2013. 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 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 zero and $115.0 million as of September 30, 2014 and December 31, 2013, respectively, approximates its fair value due to its floating rate structure. The Convertible Notes fair value of $25.4 million and $25.1 million as of September 30, 2014 and December 31, 2013, 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 $3.5 million and $41.7 million as of September 30, 2014 and December 31, 2013, 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, 2014 and December 31, 2013, 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. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified within Level 3. During the three months ended September 30, 2014 and 2013, the Company recorded impairment charges of $26.7 million and $216.6 million, respectively, on proved and unproved oil and gas properties. During the nine months ended September 30, 2014 and 2013, the Company recorded impairment charges of $27.8 million and $216.6 million, respectively, on proved and unproved oil and gas properties. See Note 2 for additional details related to impairment expense recognized during these periods.

18

The Company also applied fair value accounting guidance to measure the assets and liabilities in the Piceance Divestiture and Powder River Oil Divestiture (see Note 4). The fair values of these items were primarily determined using the accepted offers from third-party purchasers. Because of the unobservable nature of these inputs, they are 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 in 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 in the Unaudited Consolidated Balance Sheets as of the dates indicated.

	As of September 30, 2014
Balance Sheet	Gross Amounts of Recognized Derivative Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Derivative Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	13,623		$	(2,528	)	(1)	$	11,095
Deferred financing costs and other noncurrent assets	6,907			(229		)	(1)	6,678			(3)
Total derivative assets	$	20,530		$	(2,757	)		$	17,773
	Gross Amounts of Recognized Derivative Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Derivative Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(2,528	)	$	2,528		(2)	$	—
Derivatives and other noncurrent liabilities	(229		)	229			(2)	—			(4)
Total derivative liabilities	$	(2,757	)	$	2,757			$	—
	As of December 31, 2013
Balance Sheet	Gross Amounts of Recognized Derivative Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Derivative Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	8,259		$	(8,086	)	(1)	$	173
Deferred financing costs and other noncurrent assets	3,224			(685		)	(1)	2,539			(3)
Total derivative assets	$	11,483		$	(8,771	)		$	2,712
	Gross Amounts of Recognized Derivative Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Derivative Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(14,074	)	$	8,086		(2)	$	(5,988	)
Derivatives and other noncurrent liabilities	(697		)	685			(2)	(12		)	(4)
Total derivative liabilities	$	(14,771	)	$	8,771			$	(6,000	)

19

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

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

(3) As of September 30, 2014 and December 31, 2013, this line item in the Unaudited Consolidated Balance Sheets included $16.4 million and $19.2 million of deferred financing costs and other noncurrent assets, respectively.

(4) As of September 30, 2014 and December 31, 2013, this line item in the Unaudited Consolidated Balance Sheets included $3.0 million and $3.5 million of other noncurrent liabilities, respectively.

The following table summarizes the cash flow hedge gains, net of tax, as of the periods indicated:

Derivatives Qualifying as Cash Flow Hedges		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
		(in thousands)
Amount of gain reclassified from AOCI into income (net of tax) (1)(2)	Commodity Hedges	$	219	$	1,186	$	555	$	3,688

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

(2) Presented net of income tax expense of $0.1 million and $0.7 million for the three months ended September 30, 2014 and 2013, respectively, and $0.3 million and $2.2 million for the nine months ended September 30, 2014 and 2013, respectively.

As of September 30, 2014, the Company had financial derivative instruments in place related to the sale of a portion of the Company's production for the following volumes for the periods indicated:

	October – December 2014	For the year 2015	For the  year 2016	For the  year 2017
Oil (Bbls)	975,200	4,077,500	1,554,000	182,500
Natural gas (MMbtu)	1,762,500	7,300,000	1,830,000	—
Natural gas liquids (Bbls)	—	—	—	—

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,
	2014		2013			2014		2013
	(in thousands)
Commodity derivative gain settlements on derivatives designated as cash flow hedges (1)	$	351	$	1,899		$	889	$	5,902
Total commodity derivative gain (loss) (2)	72,299		(25,595		)	369		(18,607		)

(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 derivatives in place with eight different counterparties as of September 30, 2014. 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. The Company's

20

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. During the three and nine months ended September 30, 2014, the Company had no uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and nine months ended September 30, 2014 and 2013.

Income tax benefit for the three and nine months ended September 30, 2014 and 2013 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 stock-based compensation, political lobbying expense, political contributions, nondeductible officer compensation, and other operating expenses that are 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,
	2014		2013		2014		2013
	(in thousands)
Common stock options	$	482	$	681	$	1,608	$	3,898
Nonvested equity common stock	1,760		1,562		4,979		5,550
Nonvested equity common stock units	274		277		783		989
Nonvested performance-based equity	955		712		1,919		1,410
Total	$	3,471	$	3,232	$	9,289	$	11,847

Unrecognized compensation cost as of September 30, 2014 was $21.6 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 2.5 years.

Nonvested Equity Shares. The following table presents the equity awards granted pursuant to the Company's various stock compensation plans:

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	Three Months Ended September 30, 2014			Three Months Ended September 30, 2013
	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	26,828	$	21.53	57,792	$	22.36
Nonvested equity common stock units	850	$	22.04	2,210	$	25.11
Nonvested performance-based equity shares	10,073	$	18.52	154,314	$	20.86
Total shares granted	37,751			214,316
	Nine Months Ended September 30, 2014			Nine Months Ended September 30, 2013
	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	516,768	$	22.49	615,052	$	17.80
Nonvested equity common stock units	44,282	$	24.98	54,429	$	22.17
Nonvested performance-based equity shares	303,188	$	19.77	442,300	$	18.08
Total shares granted	864,238			1,111,781

Performance Share Programs

2014 Program. In February 2014, the Compensation Committee approved a new performance share program (the "2014 Program") pursuant to the 2012 Equity Incentive Plan. The performance-based awards contingently vest in May 2017, 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, 2016, consist of the Company's total shareholder return ("TSR") ranking relative to a defined peer group's individual TSRs ("Relative TSR") (weighted at 60%) and 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 40%). 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. 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 period, any shares that have not vested will be forfeited. 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 will be based upon the number of shares expected to vest at the end of the three year period.

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, including both principal and interest components, are presented below:

	As of September 30, 2014
	(in thousands)
2014	$	134
2015	537
2016	537
2017	537
2018	537
Thereafter	1,826
Total	$	4,108

Transportation Charges. The Company has entered into two firm transportation contracts to provide capacity on natural gas pipeline systems. The remaining term on these contracts is seven years. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. These transportation costs are

22

included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations. As a result of the divestitures discussed in Note 4, the Company will likely not utilize the firm capacity on the natural gas pipelines.

The amounts in the table below represent the Company's future minimum transportation charges.

	As of September 30, 2014
	(in thousands)
2014	$	4,577
2015	18,692
2016	18,692
2017	18,692
2018	18,692
Thereafter	48,287
Total	$	127,632

Purchase 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.

Lease and Other Commitments. The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Additionally, the Company has entered into various long-term agreements for telecommunication services.

The Company has entered into a sales throughput contract in the South Altamont area of the Uinta Oil Basin. Under this contract, the Company is obligated to sell and deliver a minimum volume commitment ("MVC") of 380.0 MMcf for the period of October 1, 2013 to November 30, 2014. If the minimum volume is not delivered, the Company must make a deficiency payment in the amount of up to $0.6 million. This contract replaces the initial capital expenditures associated with the connection of South Altamont wells that would otherwise be incurred as connected. As of September 30, 2014, the Company had satisfied approximately 172.5 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.3 million due December 1, 2014. Additionally, the Company has agreed to a MVC of 450.0 MMcf for the period of December 1, 2014 to November 30, 2015, with a deficiency payment of up to $0.8 million. Payment for any volume deficiency from this MVC will be due December 1, 2015.

Future minimum annual payments under lease and other agreements are as follows:

	As of September 30, 2014
	(in thousands)
2014	$	1,322
2015	3,968
2016	2,817
2017	2,612
2018	2,528
Thereafter	633
Total	$	13,880

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, the 7.625% Senior Notes, 7.0% Senior Notes and Convertible Notes, which are registered securities, are jointly and severally guaranteed on a full and unconditional basis by the Company's 100% owned

23

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.

During the three months ended June 30, 2014, Bill Barrett Corporation, as parent, merged two of the Company's 100% owned subsidiaries, CBM Production Company and GB Acquisition Corporation, into the parent company. The unaudited condensed consolidating financial statements reflect the new guarantor structure for all periods presented.

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, 2014
	Parent Issuer		Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Current assets	$	397,890	$	52		$	—		$	397,942
Property and equipment, net	1,636,831		79,422			—			1,716,253
Intercompany receivable (payable)	55,634		(55,634		)	—			—
Investment in subsidiaries	18,179		—			(18,179		)	—
Noncurrent assets	23,089		—			—			23,089
Total assets	$	2,131,623	$	23,840		$	(18,179	)	$	2,137,284
Liabilities and Stockholders' Equity:
Current liabilities	$	232,748	$	878		$	—		$	233,626
Long-term debt	828,624		—			—			828,624
Deferred income taxes	110,269		3,255			—			113,524
Other noncurrent liabilities	21,038		1,528			—			22,566
Stockholders' equity	938,944		18,179			(18,179		)	938,944
Total liabilities and stockholders' equity	$	2,131,623	$	23,840		$	(18,179	)	$	2,137,284

	As of December 31, 2013
	Parent Issuer		Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Current assets	$	154,986	$	2,261		$	—		$	157,247
Property and equipment, net	2,127,624		74,872			—			2,202,496
Intercompany receivable (payable)	59,076		(59,076		)	—			—
Investment in subsidiaries	12,063		—			(12,063		)	—
Noncurrent assets	21,770		—			—			21,770
Total assets	$	2,375,519	$	18,057		$	(12,063	)	$	2,381,513
Liabilities and Stockholders' Equity:
Current liabilities	$	192,106	$	613		$	—		$	192,719
Long-term debt	979,082		—			—			979,082
Deferred income taxes	158,071		3,255			—			161,326
Other noncurrent liabilities	40,542		2,126			—			42,668
Stockholders' equity	1,005,718		12,063			(12,063		)	1,005,718
Total liabilities and stockholders' equity	$	2,375,519	$	18,057		$	(12,063	)	$	2,381,513

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Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	128,235		$	7,028		$	—		$	135,263
Operating expenses	(230,021		)	(5,164		)	—			(235,185		)
General and administrative	(11,111		)	—			—			(11,111		)
Interest income and other income (expense)	54,530			—			—			54,530
Income (loss) before income taxes and equity in earnings of subsidiaries	(58,367		)	1,864			—			(56,503		)
Benefit from income taxes	21,854			—			—			21,854
Equity in earnings (loss) of subsidiaries	1,864			—			(1,864		)	—
Net income (loss)	$	(34,649	)	$	1,864		$	(1,864	)	$	(34,649	)
	Nine Months Ended September 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	385,703		$	19,686		$	—		$	405,389
Operating expenses	(416,147		)	(13,605		)	—			(429,752		)
General and administrative	(41,039		)	—			—			(41,039		)
Interest income and other income (expense)	(51,960		)	35			—			(51,925		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(123,443		)	6,116			—			(117,327		)
Benefit from income taxes	43,343			—			—			43,343
Equity in earnings (loss) of subsidiaries	6,116			—			(6,116		)	—
Net income (loss)	$	(73,984	)	$	6,116		$	(6,116	)	$	(73,984	)

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	Three Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	139,689		$	8,866		$	—		$	148,555
Operating expenses	(329,949		)	(4,274		)	—			(334,223		)
General and administrative	(14,402		)	—			—			(14,402		)
Interest and other income (expense)	(67,081		)	—			—			(67,081		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(271,743		)	4,592			—			(267,151		)
Benefit from income taxes	100,495			—			—			100,495
Equity in earnings of subsidiaries	4,592			—			(4,592		)	—
Net income (loss)	$	(166,656	)	$	4,592		$	(4,592	)	$	(166,656	)
	Nine Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	407,048		$	22,083		$	—		$	429,131
Operating expenses	(556,811		)	(11,626		)	—			(568,437		)
General and administrative	(48,257		)	—			—			(48,257		)
Interest and other income (expense)	(109,290		)	—			—			(109,290		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(307,310		)	10,457			—			(296,853		)
Benefit from income taxes	111,319			—			—			111,319
Equity in earnings (loss) of subsidiaries	10,457			—			(10,457		)	—
Net income (loss)	$	(185,534	)	$	10,457		$	(10,457	)	$	(185,534	)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended September 30, 2014
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(34,649	)	$	1,864	$	(1,864	)	$	(34,649	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(219		)	—		—			(219		)
Other comprehensive loss	(219		)	—		—			(219		)
Comprehensive income (loss)	$	(34,868	)	$	1,864	$	(1,864	)	$	(34,868	)
	Nine Months Ended September 30, 2014
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(73,984	)	$	6,116	$	(6,116	)	$	(73,984	)
Other Comprehensive Loss, net of tax:
Effect of derivative financial instruments	(555		)	—		—			(555		)
Other comprehensive loss	(555		)	—		—			(555		)
Comprehensive income (loss)	$	(74,539	)	$	6,116	$	(6,116	)	$	(74,539	)

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	Three Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(166,656	)	$	4,592	$	(4,592	)	$	(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	)	$	4,592	$	(4,592	)	$	(167,842	)
	Nine Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(185,534	)	$	10,457	$	(10,457	)	$	(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	)	$	10,457	$	(10,457	)	$	(189,222	)

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	214,521		$	16,781		$	—		$	231,302
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(410,417		)	(15,561		)	—			(425,978		)
Additions to furniture, fixtures and other	(2,110		)	—			—			(2,110		)
Proceeds from sale of properties and other investing activities	555,926			1,821			—			557,747
Intercompany transfers	3,041			—			(3,041		)	—
Cash flows from financing activities:
Proceeds from debt	165,000			—			—			165,000
Principal payments on debt	(283,442		)	—			—			(283,442		)
Intercompany transfers	—			(3,041		)	3,041			—
Other financing activities	(2,336		)	—			—			(2,336		)
Change in cash and cash equivalents	240,183			—			—			240,183
Beginning cash and cash equivalents	54,545			50			—			54,595
Ending cash and cash equivalents	$	294,728		$	50		$	—		$	294,778

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	Nine Months Ended September 30, 2013
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	180,399		$	15,903		$	—	$	196,302
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(303,774		)	(31,823		)	—		(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 payments on debt	(269,125		)	—			—		(269,125		)
Intercompany transfers	(15,920		)	15,920			—		—
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

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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:

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

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

• derivative and hedging activities;

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

• risks associated with operating in one geographic area;

• compliance with environmental and other regulations;

• economic and competitive conditions;

• occurrence of property divestitures or acquisitions;

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

• future processing volumes and pipeline throughput;

• impact of health and safety issues on operations;

• operational risks, including industrial accidents and natural disasters;

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

• debt and equity market conditions;

• 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;

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

• changes in estimates of proved reserves;

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

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

• exploration risks such as drilling unsuccessful wells;

• capital expenditures and other contractual obligations;

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

• changes in tax laws and statutory 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, 2013 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. We seek high quality development projects with the potential to provide long-term drilling inventories that generate high returns. 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 have less natural gas production due to the sale of certain gas producing properties. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGLs recovery at market prices.

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We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering. Since inception, we have built our portfolio of properties primarily through acquisitions where we seek to add value through our geologic and operational expertise. We continue to manage our asset portfolio through acquisitions and divestitures in order to maximize value and to concentrate capital and operations on core assets. Beginning in 2011, we shifted our focus from acquiring and developing primarily dry natural gas properties to acquiring and developing oil resources through acquisitions in the Uinta Basin in Utah and Denver-Julesburg ("DJ") Basin in Colorado. In 2012, we began divesting our dry natural gas properties through the sale of our Wind River Basin natural gas properties, Powder River Basin coalbed methane properties and a portion of our Piceance Basin natural gas properties. We continued to divest natural gas properties in 2013 and 2014 with the divestitures of our West Tavaputs properties in the Uinta Basin and all of our Piceance Basin properties, as well as certain non core oil prospects in the Powder River Basin. During the third quarter of 2014, we completed the Piceance Divestiture and the Powder River Oil Divestiture. The total value of the transactions included $531.0 million in net cash proceeds, $71.0 million estimated value for assets acquired in the Northeast Wattenberg area of the DJ Basin that were exchanged for assets in the Powder River Basin, $36.1 million for the purchaser’s assumption of a lease financing obligation, $23.7 million related to the relief of the Company's asset retirement obligations and $84.0 million in future commitments assumed by the purchaser for firm gathering and transportation obligations. As of September 30, 2014, we are focused on the development of oil resources in the Uinta and DJ Basins.

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 Rocky Mountain region of 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:

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Three Months Ended September 30, 2014 Compared with Three Months Ended September 30, 2013

	Three Months Ended September 30,					Increase (Decrease)
	2014		2013			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	134,342	$	149,345		$	(15,003	)	(10	)%
Other	921		(790		)	1,711			217	%
Operating Expenses
Lease operating expense	16,284		18,280			(1,996		)	(11	)%
Gathering, transportation and processing expense	10,784		16,374			(5,590		)	(34	)%
Production tax expense	10,495		8,183			2,312			28	%
Exploration expense	23		(24		)	47			196	%
Impairment, dry hole costs and abandonment expense	29,109		219,363			(190,254		)	(87	)%
Loss on divestitures	99,466		—			99,466			*nm
Depreciation, depletion and amortization	69,024		72,047			(3,023		)	(4	)%
General and administrative expense (1)	7,591		11,083			(3,492		)	(32	)%
Non-cash stock-based compensation expense (1)	3,520		3,319			201			6	%
Total operating expenses	$	246,296	$	348,625		$	(102,329	)	(29	)%
Production Data:
Oil (MBbls)	1,107		909			198			22	%
Natural gas (MMcf)	6,834		12,988			(6,154		)	(47	)%
NGLs (MBbls)	408		500			(92		)	(18	)%
Combined volumes (MBoe)	2,654		3,574			(920		)	(26	)%
Daily combined volumes (Boe/d)	28,848		38,848			(10,000		)	(26	)%
Average Realized Prices (2):
Oil (per Bbl)	$	79.98	$	83.51		$	(3.53	)	(4	)%
Natural gas (per Mcf)	4.27		4.30			(0.03		)	(1	)%
NGLs (per Bbl)	33.19		28.74			4.45			15	%
Combined (per Boe)	49.46		40.88			8.58			21	%
Average Costs (per Boe):
Lease operating expense	$	6.14	$	5.11		$	1.03		20	%
Gathering, transportation and processing expense	4.06		4.58			(0.52		)	(11	)%
Production tax expense	3.95		2.29			1.66			72	%
Depreciation, depletion and amortization	26.01		20.16			5.85			29	%
General and administrative expense (3)	2.86		3.10			(0.24		)	(8	)%

* 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 $11.1 million and $14.4 million for the three months ended September 30, 2014 and 2013, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.

(2) Average realized prices shown in the table 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 the cash settlement portion provides a better understanding of our average prices received for production volumes. We also believe that this disclosure allows for a more accurate comparison to our peers.

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(3) Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Consolidated Statements of Operations, were $4.19 and $4.03 for the three months ended September 30, 2014 and 2013, respectively.

Production Revenues and Volumes. Production revenues decreased to $134.3 million for the three months ended September 30, 2014 from $149.3 million for the three months ended September 30, 2013. The decrease in production revenues was due to a 26%decrease in production volumes offset by an increase in average prices. The decrease in production reduced production revenues by approximately $46.5 million, while the increase in average prices increased production revenues by approximately $31.5 million.

We discontinued cash flow 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 amounts reclassified to oil, gas and NGL production revenues were gains of $0.4 million and $1.9 million for the three months ended September 30, 2014 and 2013, respectively.

Total production volumes of 2.7 MMBoe for the three months ended September 30, 2014decreased from 3.6 MMBoe for the three months ended September 30, 2013. The decrease relates to the West Tavaputs Divestiture, natural production declines in the Piceance Basin and lower NGL yields from our primary NGL processor in the Piceance Basin. These decreases were partially offset by a 22% overall increase in oil production with increases in the DJ Basin and the Powder River Basin. Additional information concerning production is in the following table:

	Three Months Ended September 30, 2014				Three Months Ended September 30, 2013				% Increase (Decrease)
	Oil	NGL	Natural Gas	Total	Oil	NGL	Natural Gas	Total	Oil		NGL		Natural Gas		Total
	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)		(MBbls)		(MMcf)		(MBoe)
Piceance Basin	60	253	4,794	1,112	87	410	6,223	1,534	(31	)%	(38	)%	(23	)%	(28	)%
Uinta Oil Program	489	32	630	626	546	45	845	732	(10	)%	(29	)%	(25	)%	(14	)%
DJ Basin	444	116	1,206	761	184	43	459	304	141	%	170	%	163	%	150	%
Powder River Oil	113	7	198	153	88	2	91	105	28	%	250	%	118	%	46	%
Other (1)	1	—	6	2	4	—	5,370	899	(75	)%	*nm		(100	)%	(100	)%
Total	1,107	408	6,834	2,654	909	500	12,988	3,574	22	%	(18	)%	(47	)%	(26	)%

* Not meaningful.

(1) Other includes Uinta - West Tavaputs natural gas volumes of 5,353 MMcf and oil production of 4 MBbls for 2013.

Hedging Activities. During the three months ended September 30, 2014, approximately 88% of our oil volumes, 88% of our natural gas volumes and 23% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil revenues of $3.2 million partially offset by an increase in natural gas revenues of $0.2 million and NGL revenues of $0.2 million after settlements for all commodity derivatives. Of the $2.7 million loss on total settlements for the three months ended September 30, 2014, a gain of $0.4 million was included in oil, gas and NGL production revenues and a loss of $3.1 million was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

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 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 Consolidated Statements of Operations.

Other Operating Revenues. Other operating revenues increased to income of $0.9 million for the three months ended September 30, 2014 from a loss of $0.8 million for the three months ended September 30, 2013. Other operating revenues for the three months ended September 30, 2014 consisted of income from gathering and compression fees received from third parties. Other operating revenues for the three months ended September 30, 2013 consisted of $1.0 million in net losses

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realized from the sale of properties offset by $0.2 million of income from gathering and compression fees received from third parties.

Lease Operating Expense ("LOE"). Lease operating expense increased to $6.14 per Boe for the three months ended September 30, 2014 from $5.11 per Boe for the three months ended September 30, 2013. LOE on a per Boe basis is inherently higher from our oil producing properties such as those in our Uinta and DJ Basin development areas. The sale of natural gas properties with lower LOE per Boe in the West Tavaputs Divestiture also contributed to higher LOE per Boe for the three months ended September 30, 2014.

Gathering, Transportation and Processing Expense ("GTP"). Gathering, transportation and processing expense decreased to $4.06 per Boe for the three months ended September 30, 2014 from $4.58 per Boe for the three months ended September 30, 2013. GTP on a per Boe basis decreased due to inherently lower GTP from our oil producing properties such as those in our Uinta and DJ Basin development areas, offset by an increase on a per Boe basis in the Piceance Basin due to a decrease in production with fixed gathering and transportation expenses. The sale of our natural gas properties with higher GTP per Boe in the West Tavaputs Divestiture also contributed to lower GTP per Boe for the three months ended September 30, 2014.

Production Tax Expense. Total production taxes increased to $10.5 million for the three months ended September 30, 2014 from $8.2 million for the three months ended September 30, 2013. 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 were 7.8% and 5.5% for the three months ended September 30, 2014 and September 30, 2013, 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.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the three months ended September 30, 2014 and 2013 is summarized below:

	Three Months Ended September 30,
	2014		2013
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	11,493	$	198,787
Non-cash impairment of unproved oil and gas properties	15,250		17,777
Dry hole costs	3		(36		)
Abandonment expense	2,363		2,835
Total non-cash impairment, dry hole costs and abandonment expense	$	29,109	$	219,363

As a result of the Powder River Oil Divestiture and results of drilling and completion activity in the Paradox Basin during the three months ended September 30, 2014, the remaining carrying values of Powder River Oil and Paradox Basin assets were analyzed relative to their estimated fair market values. As a result, we recognized proved and unproved property impairment of $11.5 and $15.3 million, respectively.

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 values of the related properties were analyzed relative to their estimated fair market values. 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 during the three months ended September 30, 2013 related to certain unproved oil and gas properties within various exploration and development projects primarily as a result of no future plans to evaluate the remaining acreage and estimated market values below our carrying values.

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Loss on Divestitures. Loss on divestitures for the three months ended September 30, 2014 consisted of a $74.8 million loss related to the Piceance Divestiture and a $25.7 million loss related to the Powder River Oil Divestiture, partially offset by $1.0 million in net gains realized from the sale of other oil and gas properties.

Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $69.0 million for the three months ended September 30, 2014 compared with $72.0 million for the three months ended September 30, 2013. The decrease of $3.0 million was a result of a 26% decrease in production for the three months ended September 30, 2014 compared with the three months ended September 30, 2013, partially offset by an increase in the DD&A rate. The decrease in production accounted for a $18.5 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $15.5 million of additional DD&A expense.

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, 2014, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $26.01 per Boe compared with $20.16 per Boe for the three months ended September 30, 2013. The increase in the DD&A rate during the three months ended September 30, 2014 compared with the three months ended September 30, 2013 was due to an increase in oil development, which has higher capital cost per Boe compared to natural gas development. 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 $7.6 million for the three months ended September 30, 2014 from $11.1 million for the three months ended September 30, 2013. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 31 for a reconciliation and explanation. On a per Boe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $2.86 per Boe for the three months ended September 30, 2014 from $3.10 per Boe for the three months ended September 30, 2013, as a result of a decrease in employee compensation and benefits offset by a 26% decrease in production volumes, which would increase expense on a per Boe basis, for the three months ended September 30, 2014 compared with the three months ended September 30, 2013.

Non-cash charges for stock-based compensation for the three months ended September 30, 2014 and 2013 were $3.5 million and $3.3 million, respectively. Non-cash stock-based compensation expense for each of the three months ended September 30, 2014 and 2013 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, 2014 and 2013 are shown in the following table:

	Three Months Ended September 30,
	2014		2013
	(in thousands)
Stock options and nonvested equity shares of common stock	$	3,395	$	3,117
Shares issued for 401(k) plan	106		146
Shares issued for directors' fees	19		56
Total	$	3,520	$	3,319

Interest Expense. Interest expense decreased to $18.0 million for the three months ended September 30, 2014 from $20.1 million for the three months ended September 30, 2013. The decrease for the three months ended September 30, 2014 was primarily due to using the proceeds from the West Tavaputs Divestiture to lower the average debt balance. Our weighted average interest rate for the three months ended September 30, 2014 was 6.3% compared to 6.2% for the three months ended September 30, 2013.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $72.3 million for the three months ended September 30, 2014 compared with a loss of $25.6 million for the three months ended September 30, 2013. The gain or loss on commodity derivatives is related to fluctuations of oil, natural gas and NGL future pricing compared to actual pricing of commodity hedges in place as of September 30, 2014 and 2013.

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

	Three Months Ended September 30,
	2014			2013
	(in thousands)
Realized loss on derivatives not designated as cash flow hedges (1)	$	(3,054	)	$	(3,255	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges (1)	75,353			(22,340		)
Total commodity derivative gain (loss)	$	72,299		$	(25,595	)

(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 our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

Income Tax Benefit. Income tax benefit totaled $21.9 million for the three months ended September 30, 2014 compared with income tax benefit of $100.5 million for the three months ended September 30, 2013, resulting in effective tax rates of 38.7% and 37.6%, respectively. The tax benefit decrease is due to variations in revenue and expense items as discussed above resulting in lower pretax book loss for the three months ended September 30, 2014. For both the 2014 and 2013 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer's compensation as well as the effect of state income taxes. The increase in the effective tax rate is due to the relationship of the permanent items to the projected annual pretax book loss. For the three months ended September 30, 2014 there was an increase of $0.8 million for permanent items which increased the projected annual tax rate by 1.1%.

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Nine Months Ended September 30, 2014 Compared with Nine Months Ended September 30, 2013

	Nine Months Ended September 30,				Increase (Decrease)
	2014		2013		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	397,731	$	424,130	$	(26,399	)	(6	)%
Other	7,658		5,001		2,657			53	%
Operating Expenses
Lease operating expense	48,367		53,138		(4,771		)	(9	)%
Gathering, transportation and processing expense	34,238		50,734		(16,496		)	(33	)%
Production tax expense	27,770		21,915		5,855			27	%
Exploration expense	442		212		230			108	%
Impairment, dry hole costs and abandonment expense	32,613		227,646		(195,033		)	(86	)%
Loss on divestitures	96,896		—		96,896			*nm
Depreciation, depletion and amortization	189,426		214,792		(25,366		)	(12	)%
General and administrative expense (1)	31,408		36,278		(4,870		)	(13	)%
Non-cash stock-based compensation expense (1)	9,631		11,979		(2,348		)	(20	)%
Total operating expenses	$	470,791	$	616,694	$	(145,903	)	(24	)%
Production Data:
Oil (MBbls)	3,056		2,528		528			21	%
Natural gas (MMcf)	19,950		41,959		(22,009		)	(52	)%
NGLs (MBbls)	1,330		1,627		(297		)	(18	)%
Combined volumes (MBoe)	7,711		11,148		(3,437		)	(31	)%
Daily combined volumes (Boe/d)	28,245		40,835		(12,590		)	(31	)%
Average Realized Prices (2):
Oil (per Bbl)	$	79.52	$	82.50	$	(2.98	)	(4	)%
Natural gas (per Mcf)	4.50		4.10		0.40			10	%
NGLs (per Bbl)	32.61		27.79		4.82			17	%
Combined (per Boe)	48.78		38.20		10.58			28	%
Average Costs (per Boe):
Lease operating expense	$	6.27	$	4.77	$	1.50		31	%
Gathering, transportation and processing expense	4.44		4.55		(0.11		)	(2	)%
Production tax expense	3.60		1.97		1.63			83	%
Depreciation, depletion and amortization	24.57		19.27		5.30			28	%
General and administrative expense (3)	4.07		3.25		0.82			25	%

* 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 $41.0 million and $48.3 million for the nine months ended September 30, 2014 and 2013, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.

(2) Average realized prices shown in the table 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 the cash settlement portion provides a better understanding of our average prices received for production volumes. We also believe that this disclosure allows for a more accurate comparison to our peers.

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(3) Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Consolidated Statements of Operations, were $5.32 and $4.33 for the nine months ended September 30, 2014 and 2013, respectively.

Production Revenues and Volumes. Production revenues decreased to $397.7 million for the nine months ended September 30, 2014 from $424.1 million for the nine months ended September 30, 2013. The decrease in production revenues was due to a 31%decrease in production volumes offset by an increase in average prices. The decrease in production volumes reduced production revenues by approximately $177.3 million, while the increase in average prices increased production revenues by approximately $150.9 million.

We discontinued cash flow 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 $0.9 million and $5.9 million for the nine months ended September 30, 2014 and 2013, respectively.

Total production volumes of 7.7 MMBoe for the nine months ended September 30, 2014decreased from 11.1 MMBoe for the nine months ended September 30, 2013. The decrease relates to the West Tavaputs Divestiture, natural gas production declines in the Piceance Basin and lower NGL yields at our primary NGL processor in the Piceance Basin. These decreases were partially offset by a 21% overall increase in oil production with increases in the DJ Basin and Powder Deep Oil Program for the nine months ended September 30, 2014. Additional information concerning production is in the following table:

	Nine Months Ended September 30, 2014				Nine Months Ended September 30, 2013				% Increase (Decrease)
	Oil	NGL	Natural Gas	Total	Oil	NGL	Natural Gas	Total	Oil		NGL		Natural Gas		Total
	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)		(MBbls)		(MMcf)		(MBoe)
Piceance Basin	174	908	14,724	3,536	262	1,400	20,135	5,018	(34	)%	(35	)%	(27	)%	(30	)%
Uinta Oil Program	1,373	94	1,740	1,757	1,482	107	2,287	1,970	(7	)%	(12	)%	(24	)%	(11	)%
DJ Basin	1,177	308	3,018	1,988	489	116	1,270	817	141	%	166	%	138	%	143	%
Powder Deep Oil Program	327	20	456	423	262	4	200	299	25	%	400	%	128	%	41	%
Other (1)	5	—	12	7	33	—	18,067	3,044	(85	)%	*nm		(100	)%	(100	)%
Total	3,056	1,330	19,950	7,711	2,528	1,627	41,959	11,148	21	%	(18	)%	(52	)%	(31	)%

* Not meaningful.

(1) Other includes Uinta - West Tavaputs natural gas volumes of 17,971 MMcf and oil production of 27 MBbls for 2013.

Hedging Activities. During the nine months ended September 30, 2014, approximately 85% of our oil volumes, 89% of our natural gas volumes and 20% of our NGL related volumes were subject to financial hedges, which resulted in decreased oil revenues of $13.8 million, natural gas revenues of $6.6 million and NGL revenues of $0.3 million after settlements for all commodity derivatives. Of the $20.7 million loss on settlements for the nine months ended September 30, 2014, a $0.9 million gain was included in oil, gas and NGL production revenues and a $21.6 million loss was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

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 gain on settlements for the nine months ended 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 Consolidated Statements of Operations.

Other Operating Revenues. Other operating revenues increased to $7.7 million for the nine months ended September 30, 2014 from $5.0 million for the nine months ended September 30, 2013. Other operating revenues for the nine months ended September 30, 2014 consisted of $5.9 million related to the recovery of processing deductions on NGL revenues and $1.8 million of income from gathering and compression fees received from third parties. The $5.9 million related to the recovery of

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processing deductions on NGL revenues is based on guidance provided by the Federal Office of Natural Resources Revenue ("ONRR"). Additional processing deductions were taken against NGL royalties paid on Federal and State leases from 2008 through July 2013 in the West Tavaputs area of the Uinta Basin. The West Tavaputs properties were sold in December 2013. 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.

Lease Operating Expense. LOE increased to $6.27 per Boe for the nine months ended September 30, 2014 from $4.77 per Boe for the nine months ended September 30, 2013. LOE on a per Boe basis is inherently higher for our oil producing properties such as those in our Uinta and DJ Basin development areas. The sale of natural gas properties with lower LOE per Boe in the West Tavaputs Divestiture also contributed to a higher LOE per Boe for the nine months ended September 30, 2014.

Gathering, Transportation and Processing Expense. GTP expense decreased to $4.44 per Boe for the nine months ended September 30, 2014 from $4.55 per Boe for the nine months ended September 30, 2013. GTP on a per Boe basis decreased due to inherently lower GTP from our oil producing properties such as those in our Uinta and DJ Basin development areas, offset by an increase on a per Boe basis in the Piceance Basin due to a decrease in production with fixed gathering and transportation expenses. The sale of natural gas properties with higher GTP per Boe in the West Tavaputs Divestiture also contributed to lower GTP per Boe for the nine months ended September 30, 2014.

Production Tax Expense. Total production taxes increased to $27.8 million for the nine months ended September 30, 2014 from $21.9 million for the nine months ended September 30, 2013. 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 were 7.0% and 5.2% for the nine months ended September 30, 2014 and 2013, 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 increased to $0.4 million for the nine months ended September 30, 2014 from $0.2 million for the nine months ended September 30, 2013. Exploration expense for the nine months ended September 30, 2014 consisted of $0.3 million for geological and geophysical seismic programs and $0.1 million for delay rentals across all basins. Exploration expense for the nine months ended September 30, 2013 consisted of $0.2 million for delay rentals across all basins.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the nine months ended September 30, 2014 and 2013 is summarized below:

	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	12,531	$	198,787
Non-cash impairment of unproved oil and gas properties	15,250		17,777
Non-cash impairment of inventory	340		—
Dry hole costs	96		928
Abandonment expense	4,396		10,154
Total non-cash impairment, dry hole costs and abandonment expense	$	32,613	$	227,646

As a result of the Powder River Oil Divestiture and results of drilling and completion activity in the Paradox Basin during the nine months ended September 30, 2014, the remaining carrying values of Powder River Oil and Paradox Basin assets were analyzed relative to their estimated fair market values. As a result, we recognized proved and unproved property impairment of $11.5 and $15.3 million, respectively. In addition, $1.0 million of impairment expense was incurred during the nine months

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ended September 30, 2014 related to the West Tavaputs Divestiture based upon a true up of previously estimated fair value relative to carrying value.

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 during the nine months ended September 30, 2013 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 estimated market values below our carrying values.

Loss on Divestitures. Loss on divestitures for the nine months ended September 30, 2014 consisted of a $74.8 million loss related to the Piceance Divestiture and a $25.7 million loss related to the Powder River Oil Divestiture, offset by $3.6 million in net gains realized from the sale of other properties.

Depreciation, Depletion and Amortization. DD&A decreased to $189.4 million for the nine months ended September 30, 2014 compared with $214.8 million for the nine months ended September 30, 2013. The decrease of $25.4 million was a result of the 31%decrease in production for the nine months ended September 30, 2014 compared with the nine months ended September 30, 2013, partially offset by an increase in the DD&A rate. The decrease in production accounted for a $66.3 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $40.9 million of additional DD&A expense.

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, 2014, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $24.57 per Boe compared with $19.27 per Boe for the nine months ended September 30, 2013. The increase in the DD&A rate during the nine months ended September 30, 2014 compared with the nine months ended September 30, 2013 was due to an increase in oil development, which has higher capital cost per Boe compared to natural gas development. 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 $31.4 million for the nine months ended September 30, 2014 from $36.3 million for the nine months ended September 30, 2013. The decrease of $4.9 million was primarily the result of a 14% decrease in the number of employees as of September 30, 2014 compared to September 30, 2013. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 36 for a reconciliation and explanation. On a per Boe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $4.07 per Boe for the nine months ended September 30, 2014 from $3.25 per Boe for the nine months ended September 30, 2013, primarily due to the 31% decrease in production as the result of the West Tavaputs Divestiture.

Non-cash charges for stock-based compensation for the nine months ended September 30, 2014 and the nine months ended September 30, 2013 were $9.6 million and $12.0 million, respectively. Non-cash stock-based compensation expense for each of the nine months ended September 30, 2014 and 2013 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, 2014 and 2013 are shown in the following table:

	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Stock options and nonvested equity shares of common stock	$	9,075	$	11,080
Shares issued for 401(k) plan	499		602
Shares issued for directors' fees	57		297
Total	$	9,631	$	11,979

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Interest Expense. Interest expense decreased to $53.3 million for the nine months ended September 30, 2014 from $69.3 million for the nine months ended September 30, 2013. The decrease for the nine months ended September 30, 2014 was primarily due to using the proceeds from the West Tavaputs Divestiture to lower the average debt balance. Our weighted average interest rate for the nine months ended September 30, 2014 was 6.6% compared to 7.5% for the nine months ended September 30, 2013.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) changed to a gain of $0.4 million for the nine months ended September 30, 2014 compared with a loss of $18.6 million for the nine months ended September 30, 2013. The gain or loss on commodity derivatives is related to fluctuations of oil, natural gas and NGL future pricing compared to actual pricing of commodity hedges in place as of September 30, 2014 and 2013.

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

	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges (1)	$	(21,580	)	$	2,971
Unrealized gain (loss) on derivatives not designated as cash flow hedges (1)	21,949			(21,578		)
Total commodity derivative gain (loss)	$	369		$	(18,607	)

(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 our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

Income Tax Benefit. Income tax benefit totaled $43.3 million for the nine months ended September 30, 2014 compared with an income tax benefit of $111.3 million for the nine months ended September 30, 2013, resulting in effective tax rates of 36.9% and 37.5%, respectively. For both the 2014 and 2013 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer's compensation as well as the effect of state income taxes. The change in the effective tax rate is a result of the relationship of these items to the projected book loss for each year.

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, 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 sufficient liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital.

During the third quarter of 2014, we completed the Piceance Divestiture and the Powder River Oil Divestiture. We received net cash proceeds from the transactions of $531.0 million. We applied the cash proceeds to pay off the outstanding balance of $280 million under the Revolving Credit Facility and retained the remainder of the cash proceeds for reinvestment into our core development programs.

At September 30, 2014, we had cash and cash equivalents of $294.8 million and no amounts outstanding under our Amended Credit Facility. Our borrowing base is dependent on our proved reserves and hedge position and as of September 30, 2014 was $375.0 million. Our remaining borrowing capacity was reduced by $26.0 million to $349.0 million as of September 30, 2014 due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

Cash Flow from Operating Activities

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Net cash provided by operating activities for the nine months ended September 30, 2014 and 2013 was $231.3 million and $196.3 million, respectively. The increase in net cash provided by operating activities was due to an increase in the changes in operating assets and liabilities and a decrease in cash operating expenses, offset by a decrease in production revenues and derivative settlements.

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 revenues. At September 30, 2014, we had in place crude oil swaps covering portions of our 2014, 2015, 2016 and 2017 production and natural gas swaps covering portions of our 2014, 2015 and 2016 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil and natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, 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, 2014, the estimated fair value of all of our commodity derivative instruments was a net asset of $17.8 million, comprised of current and noncurrent assets. 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, gas and NGL production 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, natural gas and NGL derivative instruments for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)
Commodity derivative settlements on derivatives designated as cash flow hedges (1)	$	351		$	1,899		$	889		$	5,902
Realized gains (losses) on derivatives not designated as cash flow hedges (2)(3)	$	(3,054	)	$	(3,255	)	$	(21,580	)	$	2,971
Unrealized gains (losses) on derivatives not designated as cash flow hedges (2)(3)	75,353			(22,340		)	21,949			(21,578		)
Total commodity derivative gain (loss)	$	72,299		$	(25,595	)	$	369		$	(18,607	)

(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 our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

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The following table summarizes all of our hedges in place as of September 30, 2014:

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price (1)	Fair Market Value (in thousands)
Swap Contracts:
2014
Oil	975,200	Bbls	$	93.88	WTI	$	3,584
Natural gas	1,762,500	MMBtu	$	3.57	NWPL	(866		)
Natural gas liquids (2)	—	Bbls	n/a		Mt. Belvieu	187
2015
Oil	4,077,500	Bbls	$	90.13	WTI	9,479
Natural gas	7,300,000	MMBtu	$	4.13	NWPL	1,874
2016
Oil	1,554,000	Bbls	$	87.84	WTI	2,820
Natural gas	1,830,000	MMBtu	$	4.10	NWPL	421
2017
Oil	182,500	Bbls	$	86.35	WTI	274
Total						$	17,773

(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange ("NYMEX"). 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.

(2) For 2014 NGL hedges, all volumes hedged have offsetting hedges resulting in total volumes hedged of zero.

The following table includes all hedges entered into subsequent to September 30, 2014 through October 17, 2014:

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price
Swap Contracts:
2016
Oil	183,000	Bbls	$	84.15	WTI
2017
Oil	182,500	Bbls	$	83.13	WTI

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

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Capital Expenditures

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

	Nine Months Ended September 30,
Basin/Area	2014		2013
	(in millions)
Piceance	$	—	$	4.5
Uinta Oil Program	119.2		193.3
DJ	283.5		119.5
Powder Deep Oil Program	25.0		42.0
Other	2.3		3.8
Total (1)	$	430.0	$	363.1

(1) Capital expenditures exclude $79.0 million related to property acquired through exchanges.

	Nine Months Ended September 30,
	2014		2013
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	11.1	$	11.0
Drilling, development, exploration and exploitation of oil and natural gas properties (1)	415.7		350.8
Geologic and geophysical costs	0.5		0.2
Furniture, fixtures and equipment	2.7		1.1
Total	$	430.0	$	363.1

(1) Includes related gathering and facilities costs.

Our current estimated capital expenditure budget in 2014 is $560 million to $570 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. 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.

We believe that we have sufficient available liquidity with available cash under the Amended Credit Facility and cash flow from operations to fund our 2014 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.

Financing Activities

Amended Credit Facility

Our Amended Credit Facility has a maturity date of October 31, 2016, and current commitments and borrowing base of $375.0 million. As of September 30, 2014, we had no amounts 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

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Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of September 30, 2014 to $349.0 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 were 2.0% and 2.1% for the three months ended September 30, 2014 and 2013, and 1.9% and 2.0% for the nine months ended September 30, 2014 and 2013, respectively.

The borrowing base is required to be re-determined twice per year. On September 30, 2014, the borrowing base was reduced to $375.0 million based on year-end 2013 reserves as adjusted for the Piceance and Powder River Oil Divestitures and our hedge position. 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 of our other outstanding debt.

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 contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

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 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 redeemable on October 1, 2015 at our option at a redemption price of 103.813% of the principal amount of the 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.

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

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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.

Lease Financing Obligation Due 2020

In July, 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 the result of the disposition of equipment in the West Tavaputs Divestiture and the Piceance Divestiture, our remaining Lease Financing Obligation has been reduced to $3.7 million as of September 30, 2014 and the early buyout option has been reduced to $1.8 million.

Our outstanding debt is summarized below:

		As of September 30, 2014						As of December 31, 2013
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount		Carrying Amount
		(in thousands)
Amended Credit Facility (1)	October 31, 2016	$	—	$	—	$	—	$	115,000	$	—	$	115,000
Convertible Notes (2)	March 15, 2028 (3)	25,344		—		25,344		25,344		—		25,344
7.625% Senior Notes (4)	October 1, 2019	400,000		—		400,000		400,000		—		400,000
7.0% Senior Notes (5)	October 15, 2022	400,000		—		400,000		400,000		—		400,000
Lease Financing Obligation (6)	August 10, 2020	3,721		—		3,721		43,329		—		43,329
Total Debt		$	829,065	$	—	$	829,065	$	983,673	$	—	$	983,673
Less: Current Portion of Long-Term Debt		441		—		441		4,591		—		4,591
Total Long-Term Debt		$	828,624	$	—	$	828,624	$	979,082	$	—	$	979,082

(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 Convertible Notes was approximately $25.4 million and $25.1 million as of September 30, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.

(3) 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.

(4) The aggregate estimated fair value of the 7.625% Senior Notes was approximately $407.3 million and $430.2 million as of September 30, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.

(5) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $416.0 million and $417.0 million as of September 30, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.

(6) The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.5 million and $41.7 million as of September 30, 2014 and December 31, 2013, respectively. The decrease in estimated fair value is primarily related to the sale of equipment in the West Tavaputs and Piceance Divestitures. 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.

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.

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Contractual Obligations. A summary of our contractual obligations as of and subsequent to September 30, 2014 is provided in the following table:

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	Twelve Months Ended September 30, 2015		Twelve Months Ended September 30, 2016		Twelve Months Ended September 30, 2017		Twelve Months Ended September 30, 2018		Twelve Months Ended September 30, 2019		After September 30, 2019
	(in thousands)
Notes payable (1)	$	553	$	553	$	553	$	77	$	—	$	—	$	1,736
7.625% Senior Notes (2)	30,500		30,500		30,500		30,500		430,500		—		552,500
7.0% Senior Notes (3)	28,000		28,000		28,000		28,000		28,000		485,167		625,167
Convertible Notes (4)	25,999		—		—		—		—		—		25,999
Lease Financing Obligation (5)	537		537		537		537		1,960		—		4,108
Purchase commitments (6)(7)	—		1,695		—		—		—		—		1,695
Drilling rig commitments(7)(8)	1,462		—		—		—		—		—		1,462
Office and office equipment leases and other (9)(10)	3,783		3,642		2,657		2,531		1,267		—		13,880
Firm transportation and processing agreements (7)(11)	18,596		18,692		18,692		18,692		18,692		34,268		127,632
Asset retirement obligations (12)	2,641		601		490		464		439		17,575		22,210
Total	$	112,071	$	84,220	$	81,429	$	80,801	$	480,858	$	537,010	$	1,376,389

(1) 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. There is currently no balance outstanding under our Amended Credit Facility due October 31, 2016.

(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. The next put date is in March 2015.

(5) The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.

(6) We have one take-or-pay CO2 purchasing agreement that expires in December 2015. The agreement imposes a minimum volume commitment ("MVC") 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, 2014, $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) We currently have two drilling rigs under contract, which expire in 2014. These contracts can be terminated, but we would be required to pay a penalty of $1.5 million. All other rigs currently performing work for us are on a well-by-well basis and, therefore, can be released without penalty at the conclusion of drilling on the current well. These latter types of drilling obligations have not been included in the table above.

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

(10) Includes a sales throughput contract in the South Altamont area of the Uinta Oil Basin. Under this contract, we are obligated to sell and deliver a MVC of 380.0 MMcf for the period of October 1, 2013 to November 30, 2014. If the minimum volume is not delivered, we must make a deficiency payment of up to $0.6 million. As of September 30, 2014, we have satisfied approximately 172.5 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.3 million due December 1, 2014. Additionally, we have agreed to a MVC of 450.0 MMcf for the period of December 1, 2014 to November 30, 2015, with a deficiency payment of up to $0.8 million. Payment for any volume deficiency during this period will be due December 1, 2015.

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(11) We have entered into contracts that provide firm transportation capacity on pipeline systems. The remaining term on these contracts is seven years. The contracts require us to pay transportation demand and processing charges regardless of the amount of gas we deliver to the processing facility or pipeline.

(12) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2013 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

Trends and Uncertainties

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, 2013 for a discussion of trends and uncertainties that may affect our financial condition or liquidity.

Several statewide ballot initiatives were proposed in early 2014 that would have restricted or limited oil and natural gas development in Colorado, notably by amending the Colorado constitution (i) to impose a 2,000 foot statewide drilling setback from occupied structures and (ii) to establish an environmental bill of rights increasing local government authority to enact environmental regulations that are more restrictive than those adopted by the state government. Proponents of these initiatives withdrew them in August 2014 under a political compromise reached with Colorado Governor John Hickenlooper. Under the compromise, the Governor appointed a 21 member oil and gas task force (the "Task Force") by Executive Order, directing it to examine a range of issues and policy options to respond to the public concerns inherent in the withdrawn ballot initiatives. The Task Force is to make its report to the Governor and the Colorado General Assembly by March 2015. The outcome of this Task Force process is unclear, especially considering the potential impact of the 2014 gubernatorial and legislative elections. It is possible, however, that recommendations could be made, and subsequently adopted by legislation or regulation, that might impede our planned drilling activities in Colorado, including increasing regulatory and operational costs.

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, 2013 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. oil and 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. For example, the West Texas Intermediate price per Bbl as quoted on the NYMEX was $105.15 per Bbl at June 30, 2014 compared to $93.03 per Bbl at September 30, 2014. 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, 2014, our annual revenues would have decreased by approximately $0.2 million for each $1.00 per barrel decrease in crude oil prices, $0.2 million for each $0.10 decrease per MMBtu in natural gas prices and $1.0 million for each $1.00 per barrel decrease in NGL prices.

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.

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As of October 17, 2014, 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 2014	For the year 2015	For the year 2016	For the year 2017
Oil (Bbls)	975,200	4,077,500	1,737,000	365,000
Natural Gas (MMbtu)	1,762,500	7,300,000	1,830,000	—
Natural Gas Liquids (Bbls) (1)	—	—	—	—

(1) For 2014 NGL hedges, all volumes hedged have offsetting hedges resulting in total volumes hedged of zero.

Interest Rate Risks

At September 30, 2014, we had no amounts 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, 2014 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, 2014 would have resulted in an estimated $1.6 million increase in interest expense assuming a similar average debt level to the nine months ended September 30, 2014. The average annual interest rate incurred on this debt for the nine months ended September 30, 2013 was 2.0%.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of September 30, 2014, 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, 2014.

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the third fiscal quarter of 2014 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, 2013. 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, 2013 and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

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

Unregistered Sales of Securities

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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, 2014:

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, 2014	13,401	$	25.10	—	—
August 1 – 31, 2014	2,617	21.13		—	—
September 1 – 30, 2014	968	21.42		—	—
Total	16,986	$	24.28	—	—

(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.

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.]
2.1	Amendment to Purchase and Sale Agreement, dated December 10, 2013, among Bill Barrett Corporation, Enervest Energy Institutional Fund XIII-A, L.P., Enervest Energy Institutional Fund XIII-WIB, L.P. and Enervest Energy Institutional Fund XIII-WIC, L.P. [Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed with the Commission on December 11, 2013.]
2.2	Purchase and Sale Agreement, dated September 15, 2014, among Bill Barrett Corporation, Vanguard Operating, LLC and Vanguard Natural Resources, LLC. [Incorporated by reference to Exhibit 2 of our Current Report on Form 8-K filed with the Commission on October 3, 2014.]
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.]

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Exhibit Number	Description of Exhibits
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.]
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.]
4.7	Amendment No. 1 to Rights Agreement, dated as of March 18, 2013, between Bill Barrett Corporation and Computershare Shareowner Services LLC. [Incorporated by reference to Exhibit 4.5 to Amendment No. 2 to our Registration Statement on Form 8-A filed with the Commission on March 18, 2013.]

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Exhibit Number	Description of Exhibits
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.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Furnished herewith.

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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:	November 6, 2014	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President
			(Principal Executive Officer)
Date:	November 6, 2014	By:	/s/ Robert W. Howard
			Robert W. Howard
			Chief Financial Officer
			(Principal Financial Officer)

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