BILL BARRETT CORP - FORM 10-Q

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EX-32.1 - EXHIBIT 32.1 - BILL BARRETT CORP	bbg-6302015xex321.htm
EX-31.1 - EXHIBIT 31.1 - BILL BARRETT CORP	bbg-6302015xex311.htm
EX-32.2 - EXHIBIT 32.2 - BILL BARRETT CORP	bbg-6302015xex322.htm
EX-31.2 - EXHIBIT 31.2 - BILL BARRETT CORP	bbg-6302015xex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2015



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.

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 49,951,010 shares of $0.001 par value common stock outstanding on July 24, 2015.

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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	28
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	46
Item 4.	Controls and Procedures	46

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Mine Safety Disclosures	48
Item 5.	Other Information	48
Item 6.	Exhibits	48
SIGNATURES		49

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PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



	June 30, 2015			December 31, 2014
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	35,882		$	165,904
Short-term investments	64,963			—
Accounts receivable, net of allowance for doubtful accounts	47,384			112,209
Derivative assets	90,836			145,226
Prepayments and other current assets	4,382			2,766
Total current assets	243,447			426,105
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	2,202,649			2,009,292
Unproved oil and gas properties, excluded from amortization	118,907			148,834
Oil and gas properties held for sale, net of amortization and impairment	—			9,234
Furniture, equipment and other	40,683			39,963
	2,362,239			2,207,323
Accumulated depreciation, depletion, amortization and impairment	(559,370		)	(454,202		)
Total property and equipment, net	1,802,869			1,753,121
Derivative assets	28,023			49,750
Deferred financing costs and other noncurrent assets	13,362			15,508
Total	$	2,087,701		$	2,244,484
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities	$	92,857		$	126,252
Amounts payable to oil and gas property owners	22,498			19,187
Production taxes payable	24,208			38,060
Deferred income taxes	34,840			55,418
Current portion of long-term debt	1,012			25,770
Total current liabilities	175,415			264,687
Long-term debt	803,004			803,222
Asset retirement obligations	21,858			21,592
Liabilities associated with assets held for sale	—			146
Deferred income taxes	108,136			122,350
Derivatives and other noncurrent liabilities	3,293			2,999
Stockholders' equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 49,957,208 and 49,526,637 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively, with 1,633,035 and 1,407,141 shares subject to restrictions, respectively	48			48
Additional paid-in capital	916,438			913,619
Retained earnings	59,509			115,821
Treasury stock, at cost: zero shares at June 30, 2015 and December 31, 2014, respectively	—			—
Total stockholders' equity	975,995			1,029,488
Total	$	2,087,701		$	2,244,484

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands, except share and per share data)
Operating and Other Revenues:
Oil, gas and NGL production	$	61,382		$	136,220		$	109,868		$	263,389
Other	1,236			8,788			1,784			9,307
Total operating and other revenues	62,618			145,008			111,652			272,696
Operating Expenses:
Lease operating expense	11,405			15,919			25,196			32,083
Gathering, transportation and processing expense	933			11,750			1,875			23,454
Production tax expense	3,816			9,651			6,350			17,275
Exploration expense	92			116			125			419
Impairment, dry hole costs and abandonment expense	1,090			1,743			2,345			3,504
(Gain) Loss on divestitures	(644		)	—			(682		)	—
Depreciation, depletion and amortization	52,674			64,894			104,928			120,402
Unused commitments	4,387			—			8,775			—
General and administrative expense	14,672			14,521			28,001			29,928
Total operating expenses	88,425			118,594			176,913			227,065
Operating Income (Loss)	(25,807		)	26,414			(65,261		)	45,631
Other Income and Expense:
Interest and other income	144			352			419			727
Interest expense	(17,390		)	(17,821		)	(33,820		)	(35,252		)
Commodity derivative gain (loss)	(27,657		)	(46,775		)	6,781			(71,930		)
Gain (Loss) on extinguishment of debt	(818		)	—			1,749			—
Total other income and expense	(45,721		)	(64,244		)	(24,871		)	(106,455		)
Income (Loss) before Income Taxes	(71,528		)	(37,830		)	(90,132		)	(60,824		)
(Provision for) Benefit from Income Taxes	26,947			11,244			33,820			21,489
Net Income (Loss)	$	(44,581	)	$	(26,586	)	$	(56,312	)	$	(39,335	)
Net Income (Loss) Per Common Share, Basic	$	(0.92	)	$	(0.55	)	$	(1.17	)	$	(0.82	)
Net Income (Loss) Per Common Share, Diluted	$	(0.92	)	$	(0.55	)	$	(1.17	)	$	(0.82	)
Weighted Average Common Shares Outstanding, Basic	48,299,157			47,996,816			48,249,329			47,943,806
Weighted Average Common Shares Outstanding, Diluted	48,299,157			47,996,816			48,249,329			47,943,806

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)
Net Income (Loss)	$	(44,581	)	$	(26,586	)	$	(56,312	)	$	(39,335	)
Other Comprehensive Income (Loss), net of tax:
Effect of derivative financial instruments	—			(239		)	—			(336		)
Other comprehensive income (loss)	—			(239		)	—			(336		)
Comprehensive Income (Loss)	$	(44,581	)	$	(26,825	)	$	(56,312	)	$	(39,671	)

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Six Months Ended June 30,
	2015			2014
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(56,312	)	$	(39,335	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	104,928			120,402
Deferred income tax benefit	(33,820		)	(21,531		)
Impairment, dry hole costs and abandonment expense	2,345			3,504
Total commodity derivative (gain) loss	(6,781		)	71,930
Gain (Loss) on settlements of commodity derivatives	82,898			(18,526		)
Stock compensation and other non-cash charges	5,213			6,155
Amortization of debt discounts and deferred financing costs	3,350			2,132
(Gain) Loss on extinguishment of debt	(1,749		)	—
(Gain) Loss on sale of properties	(682		)	(2,570		)
Change in operating assets and liabilities:
Accounts receivable	17,109			5,699
Prepayments and other assets	(1,139		)	1,068
Accounts payable, accrued and other liabilities	(13,678		)	(2,795		)
Amounts payable to oil and gas property owners	3,311			1,936
Production taxes payable	(13,852		)	(651		)
Net cash provided by (used in) operating activities	91,141			127,418
Investing Activities:
Additions to oil and gas properties, including acquisitions	(194,123		)	(264,345		)
Additions of furniture, equipment and other	(878		)	(856		)
Proceeds from sale of properties and other investing activities	66,518			8,175
Cash paid for short-term investments	(114,883		)	—
Proceeds from the sale of short-term investments	50,000			—
Net cash provided by (used in) investing activities	(193,366		)	(257,026		)
Financing Activities:
Proceeds from debt	—			135,000
Principal payments on debt	(24,976		)	(2,285		)
Proceeds from stock option exercises	—			126
Deferred financing costs and other	(2,821		)	(2,049		)
Net cash provided by (used in) financing activities	(27,797		)	130,792
Increase (Decrease) in Cash and Cash Equivalents	(130,022		)	1,184
Beginning Cash and Cash Equivalents	165,904			54,595
Ending Cash and Cash Equivalents	$	35,882		$	55,779

See notes to Unaudited Consolidated Financial Statements.

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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, 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			—			(2,684		)	—			(2,558		)
Stock-based compensation	—		11,916			—			—			—			11,916
Retirement of treasury stock	—		(2,684		)	—			2,684			—			—
Net income (loss)	—		—			15,081			—			—			15,081
Effect of derivative financial instruments, net of $410 of taxes	—		—			—			—			(669		)	(669		)
Balance at December 31, 2014	$	48	$	913,619		$	115,821		$	—		$	—		$	1,029,488
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	—		—			—			(1,015		)	—			(1,015		)
Stock-based compensation	—		5,430			—			—			—			5,430
Retirement of treasury stock	—		(1,015		)	—			1,015			—			—
Settlement of convertible notes	—		(1,596		)	—			—			—			(1,596		)
Net income (loss)	—		—			(56,312		)	—			—			(56,312		)
Balance at June 30, 2015	$	48	$	916,438		$	59,509		$	—		$	—		$	975,995

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

June 30, 2015

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 2014 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 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 proved 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 unproved oil and gas properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based compensation awards.

Short-term Investments. Short-term investments have maturities of more than three months and less than one year. The Company's held-to-maturity securities have a carrying value of $65.0 million, which approximates fair value, as of June 30, 2015, and all have maturity dates of less than one year.

Accounts Receivable. Accounts receivable is comprised of the following:



	As of June 30, 2015			As of December 31, 2014
	(in thousands)
Accrued oil, gas and NGL sales	$	34,283		$	35,099
Due from joint interest owners	10,476			27,937
Other ⁽¹⁾	2,639			49,187
Allowance for doubtful accounts	(14		)	(14		)
Total accounts receivable	$	47,384		$	112,209


(1)	Other as of December 31, 2014 includes a receivable of $47.6 million (including $4.7 million due to another industry partner) related to a settlement agreement with the Department of Interior resulting in the cancellation of certain Cottonwood Gulch natural gas leases during the three months ended December 31, 2014.

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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 activities in the Unaudited Consolidated Statements of Cash Flows. 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 June 30, 2015			As of December 31, 2014
	(in thousands)
Proved properties	$	407,131		$	390,482
Wells and related equipment and facilities	1,713,569			1,537,370
Support equipment and facilities	72,643			68,371
Materials and supplies	9,306			13,069
Total proved oil and gas properties	$	2,202,649		$	2,009,292
Unproved properties	62,667			78,898
Wells and facilities in progress	56,240			69,936
Total unproved oil and gas properties, excluded from amortization	$	118,907		$	148,834
Assets held for sale	—			9,234
Accumulated depreciation, depletion, amortization and impairment	(531,770		)	(427,954		)
Total oil and gas properties, net	$	1,789,786		$	1,739,406

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 June 30, 2015 and December 31, 2014, 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 net cash flows of its oil and gas properties based on the Company's best estimate of development plans, future production, commodity pricing, gathering and transportation deductions, production tax

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rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the proved oil and gas properties, no impairment is to be taken. If the carrying value of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The Company does not believe that the undiscounted future net 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 projected cash flows.

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



	Three Months Ended June 30,							Six Months Ended June 30,
	2015				2014			2015				2014
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	272		⁽¹⁾	$	—		$	272		⁽¹⁾	$	1,038	⁽²⁾
Non-cash impairment of unproved oil and gas properties	173			⁽¹⁾	—			231			⁽¹⁾	—
Non-cash impairment of inventory	—				340			—				340
Dry hole costs	(58		)		(12		)	(43		)		94
Abandonment expense and lease expirations	703				1,415			1,885				2,032
Total non-cash impairment, dry hole costs and abandonment expense	$	1,090			$	1,743		$	2,345			$	3,504


(1)	Non-cash impairment of proved and unproved oil and gas properties for the three and six months ended June 30, 2015 related to the Company's remaining Powder River Basin properties based upon a true up of previously estimated fair value relative to carrying value. These assets were classified as held for sale as of December 31, 2014 and sold in February 2015.


(2)	Non-cash impairment of proved oil and gas properties for the six months ended June 30, 2014 related to the Company's West Tavaputs properties based upon a true up of previously estimated fair value relative to carrying value. These assets were sold in December 2013.

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 June 30, 2015		As of December 31, 2014
	(in thousands)
Accrued drilling, completion and facility costs	$	54,312	$	68,124
Accrued lease operating, gathering, transportation and processing expenses	10,650		12,526
Accrued general and administrative expenses	8,214		8,482
Accrued interest payable	13,914		14,284
Accrued payables for property sales	97		16,296
Trade payables and other	5,670		6,540
Total accounts payable and accrued liabilities	$	92,857	$	126,252

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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. 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' volumetric share of 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 June 30, 2015 and 2014 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 and in the Unaudited Consolidated Statements of Operations as commodity derivative gain (loss).

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. The Company does not have any uncertain tax positions recorded as of June 30, 2015.

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 six months ended June 30, 2015 and 2014.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands, except per share amounts)
Net income (loss)	$	(44,581	)	$	(26,586	)	$	(56,312	)	$	(39,335	)
Basic weighted-average common shares outstanding in period	48,299			47,997			48,249			47,944
Add dilutive effects of stock options and nonvested equity shares of common stock	—			—			—			—
Diluted weighted-average common shares outstanding in period	48,299			47,997			48,249			47,944
Basic net income (loss) per common share	$	(0.92	)	$	(0.55	)	$	(1.17	)	$	(0.82	)
Diluted net income (loss) per common share	$	(0.92	)	$	(0.55	)	$	(1.17	)	$	(0.82	)

New Accounting Pronouncements. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Simplifying the Presentation of Debt Issuance Costs. The objective of this update is to require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from

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the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for the annual periods beginning after December 15, 2015, and for interim periods within that annual period. The adoption of the pronouncement will not have a significant impact on the Company’s disclosures and 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 standard will be adopted prospectively.

In May 2014, the FASB issued 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. In July 2015, the FASB issued a one year deferral of this standard changing the effective date to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact of adopting this standard.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:



	Six Months Ended June 30,
	2015			2014
	(in thousands)
Cash paid for interest	$	30,839		$	33,173
Cash paid for income taxes	1,052			1
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	56,654			82,782
Accrued liabilities - equity offering costs	624			—
Change in asset retirement obligations, net of disposals	(138		)	3,195
Retirement of treasury stock	(1,015		)	(2,049		)

4. Long-Term Debt

The Company's outstanding debt is summarized below:



		As of June 30, 2015						As of December 31, 2014
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount		Carrying Amount
		(in thousands)
Amended Credit Facility	April 9, 2020	$	—	$	—	$	—	$	—	$	—	$	—
Convertible Notes ⁽¹⁾	March 15, 2028 ⁽²⁾	579		—		579		25,344		—		25,344
7.625% Senior Notes ⁽³⁾	October 1, 2019	400,000		—		400,000		400,000		—		400,000
7.0% Senior Notes ⁽⁴⁾	October 15, 2022	400,000		—		400,000		400,000		—		400,000
Lease Financing Obligation ⁽⁵⁾	August 10, 2020	3,437		—		3,437		3,648		—		3,648
Total Debt		$	804,016	$	—	$	804,016	$	828,992	$	—	$	828,992
Less: Current Portion of Long-Term Debt ⁽⁶⁾		1,012		—		1,012		25,770		—		25,770
Total Long-Term Debt		$	803,004	$	—	$	803,004	$	803,222	$	—	$	803,222


(1)	The aggregate estimated fair value of the Convertible Notes was approximately $0.6 million and $25.1 million as of June 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments. On March 20, 2015, the holders put 98% of the Convertible Notes to the Company, leaving $0.6 million principal amount remaining.


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

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(3)	The aggregate estimated fair value of the 7.625% Senior Notes was approximately $382.9 million and $359.8 million as of June 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.


(4)	The aggregate estimated fair value of the 7.0% Senior Notes was approximately $361.0 million and $366.0 million as of June 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.


(5)	The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.3 million as of June 30, 2015 and $3.5 million as of December 31, 2014. 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.


(6)	The current portion of the long-term debt as of June 30, 2015 and December 31, 2014 includes the current portion of the Lease Financing Obligation and the principal amount of the Convertible Notes.

Amended Credit Facility

On April 9, 2015, the Company entered into a Third Amendment (the "Third Amendment") to the Third Amended and Restated Credit Agreement dated March 16, 2010 (the "Amended Credit Facility"). The Third Amendment amended the definition of "Maturity Date" in the Amended Credit Facility to mean the earliest of (a) April 9, 2020 or (b) the date 181 days prior to the maturity of certain unsecured senior or senior subordinated debt of the Company in existence as of the date of the Third Amendment or that may be incurred by the Company as of a future date, or any permitted refinancing debt in respect thereof. The Amended Credit Facility currently has commitments and a borrowing base of $375.0 million from 13 lenders. Due to the Third Amendment, the Company recognized interest expense of $1.6 million and a loss on extinguishment of debt of $0.8 million on the Unaudited Consolidated Statements of Operations related to deferred financing charges during the three and six months ended June 30, 2015. As of June 30, 2015, 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 was issued under the Amended Credit Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of June 30, 2015 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 unused commitment fee is between 0.375% and 0.5% based on borrowing base utilization. The average annual interest rate incurred on the Amended Credit Facility was 1.9% and 1.8% for the three and six months ended June 30, 2014, respectively.

The borrowing base is required to be re-determined twice per year, on or about April 1 and October 1. 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 calculated using future commodity pricing provided by our lenders, 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 from the time it entered into the facility.

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. On March 20, 2015, $24.8 million of the remaining outstanding principal amount, or approximately 98% of the remaining outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. The Company settled the notes in cash and recognized a gain on extinguishment of $2.6 million in the Unaudited Consolidated Statements of Operations for the six months ended June 30, 2015. After the redemption, $0.6 million aggregate principal amount of the Convertible Notes were outstanding as of June 30, 2015. 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.

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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 of each year. 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 Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are redeemable at the Company's option beginning on October 1, 2015 at an initial 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 generally 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 Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at the Company's option beginning on October 15, 2017 at an initial 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 generally 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

The Company has a lease financing obligation with a balance of $3.4 million as of June 30, 2015 whereby the Company sold and subsequently leased back the 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 pursuant to which the Company may purchase the equipment for $1.8 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.

The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, the outstanding Convertible Notes, the 7.625% Senior Notes, the 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:

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	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)
Amended Credit Facility ⁽¹⁾
Cash interest	$	437	$	1,543	$	870	$	2,621
Non-cash interest ⁽²⁾	$	1,783	$	585	$	2,369	$	1,171
Convertible Notes ⁽³⁾
Cash interest	$	10	$	324	$	286	$	634
Non-cash interest	$	2	$	2	$	5	$	3
7.625% Senior Notes ⁽⁴⁾
Cash interest	$	7,625	$	7,625	$	15,250	$	15,250
Non-cash interest	$	273	$	272	$	546	$	544
7.0% Senior Notes ⁽⁵⁾
Cash interest	$	7,000	$	7,000	$	14,000	$	14,000
Non-cash interest	$	204	$	203	$	408	$	406
Lease Financing Obligation ⁽⁶⁾
Cash interest	$	28	$	255	$	57	$	517
Non-cash interest	$	24	$	4	$	24	$	8


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


(2)	The three and six months ended June 30, 2015 includes $1.6 million related to amending the credit facility during the three months ended June 30, 2015.

(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 $0.6 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 for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 was due to obligations transferring with the sale of natural gas assets in the Piceance Basin during the third quarter of 2014.

5. Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the six months ended June 30, 2015 is as follows (in thousands):



As of December 31, 2014	$	22,852
Liabilities incurred	717
Liabilities settled	(110		)
Disposition of properties	(745		)
Accretion expense	724
Revisions to estimate	—
As of June 30, 2015	$	23,438
Less: Current asset retirement obligations	1,580
Long-term asset retirement obligations	$	21,858

6. Fair Value Measurements

Assets and Liabilities Measured on a Recurring Basis

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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 4, 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 June 30, 2015
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	1,123	$	—	$	—	$	1,123
Cash Equivalents	53		—		—		53
Commodity Derivatives	—		118,859		—		118,859

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	As of December 31, 2014
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	1,069	$	—	$	—	$	1,069
Cash Equivalents	75,066		—		—		75,066
Commodity Derivatives	—		195,176		—		195,176
Liabilities
Commodity Derivatives	$	—	$	200	$	—	$	200

The commodity derivatives 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 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 highly liquid cash equivalents are recorded at carrying value, which approximates fair value, which represent Level 1 inputs. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $743.9 million as of June 30, 2015. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $725.8 million as of December 31, 2014. 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 Amended Credit Facility, Convertible Notes or Lease Financing Obligation. The Amended Credit Facility had a balance of zero as of June 30, 2015 and December 31, 2014. The Convertible Notes fair value of $0.6 million and $25.1 million as of June 30, 2015 and December 31, 2014, 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 $3.3 million and $3.5 million as of June 30, 2015 and December 31, 2014, 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 June 30, 2015 and December 31, 2014, 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. See Note 2 for details related to impairment expense recognized during the three and six months ended June 30, 2015 and 2014.

7. 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.

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In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of 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 June 30, 2015
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 (current)	$	90,836		$	—			$	90,836
Derivative assets (noncurrent)	28,023			—				28,023
Total derivative assets	$	118,859		$	—			$	118,859

	As of December 31, 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 (current)	$	145,426		$	(200	)	⁽¹⁾	$	145,226
Derivative assets (noncurrent)	49,750			—				49,750
Total derivative assets	$	195,176		$	(200	)		$	194,976
	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	$	(200	)	$	200		⁽²⁾	$	—
Total derivative liabilities	$	(200	)	$	200			$	—


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


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

As of June 30, 2015, 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:



	July – December 2015			For the year 2016			For the year 2017
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	1,987,200	$	89.81	2,478,600	$	80.47	683,250	$	75.61
Natural Gas (MMbtu)	3,680,000	$	4.13	1,830,000	$	4.10	—	$	—

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:

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
	(in thousands)
Commodity derivative gain (loss) settlements on derivatives designated as cash flow hedges ⁽¹⁾	$	—		$	382		$	—	$	538
Total commodity derivative gain (loss) ⁽²⁾	(27,657		)	(46,775		)	6,781		(71,930		)


(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 June 30, 2015. 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 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 to the Company under the 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.

8. 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 six months ended June 30, 2015, 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 six months ended June 30, 2015 and 2014.

Income tax benefit for the three and six months ended June 30, 2015 and 2014 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 state income taxes.

9. Equity Incentive Compensation Plans and Other Long-term Incentive Programs

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:

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	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)
Common stock options	$	149	$	497	$	391	$	1,126
Nonvested common stock	1,617		1,548		3,191		3,219
Nonvested common stock units	268		260		529		509
Nonvested performance-based shares	523		146		953		964
Total	$	2,557	$	2,451	$	5,064	$	5,818

Unrecognized compensation cost as of June 30, 2015 was $16.5 million related to grants of nonvested stock options and nonvested shares of common stock that are expected to be recognized over a weighted-average period of 2.3 years.

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



	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
	Number of Shares	Weighted Average Grant Date Fair Value Per Share		Number of Shares	Weighted Average Grant Date Fair Value Per Share
Nonvested common stock	9,530	$	9.30	23,626	$	23.91
Nonvested common stock units	122,729	$	8.71	700	$	26.78
Nonvested performance-based shares	—	$	—	44,540	$	20.92
Total shares granted	132,259			68,866

	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
	Number of Shares	Weighted Average Grant Date Fair Value Per Share		Number of Shares	Weighted Average Grant Date Fair Value Per Share
Nonvested common stock	632,139	$	12.26	489,940	$	22.54
Nonvested common stock units	124,988	$	8.70	1,432	$	26.18
Nonvested performance-based shares	—	$	—	293,115	$	19.81
Total shares granted	757,127			784,487

Performance Cash Program

2015 Program. In February 2015, the Compensation Committee approved a performance cash program (the "2015 Program") granting performance cash units that will settle in cash. The performance-based awards contingently vest in May 2018, 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, 2017, 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% or 50% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of units will be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no units will vest. In any event, the total number of units that could vest will not exceed 200% of the original number of performance cash units granted. At the end of the three year vesting period, any units that have not vested will be forfeited. A total of 405,836 units were granted under this program during the six months ended June 30, 2015. The Company recognized $0.4 million in derivatives and other noncurrent liabilities on the Unaudited Consolidated Balance Sheets as of June 30, 2015 and $0.1 million and $0.4 million in general and administrative expense on the Unaudited Consolidated Statements of Operations for the three and six months ended June 30, 2015, respectively, for the 2015 Program.

10. Equity Distribution Agreement

On June 10, 2015, the Company entered into an Equity Distribution Agreement (the "Agreement") with Goldman, Sachs and Co. (the "Manager"). Pursuant to the terms of the Agreement, the Company may sell, from time to time through or to the

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Manager, shares of its common stock having an aggregate gross sales price of up to $100.0 million. Sales of the shares, if any, will be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange, at market prices, in block transactions, to or through a market maker, through an electronic communications network or as otherwise agreed by the Company and the Manager. As of June 30, 2015, no shares have been sold pursuant to the Agreement.

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 4. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below:



	As of June 30, 2015
	(in thousands)
2015	$	269
2016	537
2017	537
2018	537
2019	1,825
Thereafter	—
Total	$	3,705

Transportation Charges. The Company entered into two firm transportation contracts to provide capacity on natural gas pipeline systems. The remaining term on these contracts is six years. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. Beginning October 1, 2014, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures during 2013 and 2014, 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 June 30, 2015
	(in thousands)
2015	$	8,961
2016	18,692
2017	18,692
2018	18,692
2019	18,692
Thereafter	29,595
Total	$	113,324

Purchase Commitments. The Company has one take-or-pay purchase agreement for supply of carbon dioxide ("CO2"), which has a total financial commitment of $1.5 million. The CO2 is for use in fracture stimulation operations. Under this contract, the Company is obligated to purchase a minimum volume of CO2 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 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 450.0 MMcf for the period of December 1, 2014 to November 30, 2015. If the minimum volume is not delivered, the Company must make a deficiency payment in an amount up to $0.8 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 June 30, 2015, the Company had satisfied approximately 132.4 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.5 million due

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December 1, 2015. The deficiency amounts associated with this contract are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations.

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



	As of June 30, 2015
	(in thousands)
2015	$	2,235
2016	2,875
2017	2,747
2018	2,530
2019	632
Thereafter	—
Total	$	11,019

Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of 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 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 the Securities and Exchange Commission ("SEC") Rule 3-10 of Regulation S-X.

During the six 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. During the six months ended June 30, 2015, Bill Barrett Corporation, as parent, merged another 100% owned subsidiary, Elk Production Uintah, LLC, 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

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	As of June 30, 2015
	Parent Issuer		Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Current assets	$	243,394	$	53		$	—		$	243,447
Property and equipment, net	1,781,495		21,374			—			1,802,869
Intercompany receivable (payable)	21,267		(21,267		)	—			—
Investment in subsidiaries	96		—			(96		)	—
Noncurrent assets	41,385		—			—			41,385
Total assets	$	2,087,637	$	160		$	(96	)	$	2,087,701
Liabilities and Stockholders' Equity:
Current liabilities	$	175,400	$	15		$	—		$	175,415
Long-term debt	803,004		—			—			803,004
Deferred income taxes	108,136		—			—			108,136
Other noncurrent liabilities	25,102		49			—			25,151
Stockholders' equity	975,995		96			(96		)	975,995
Total liabilities and stockholders' equity	$	2,087,637	$	160		$	(96	)	$	2,087,701



	As of December 31, 2014
	Parent Issuer		Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Current assets	$	426,103	$	2		$	—		$	426,105
Property and equipment, net	1,730,074		23,047			—			1,753,121
Intercompany receivable (payable)	22,840		(22,840		)	—			—
Investment in subsidiaries	163		—			(163		)	—
Noncurrent assets	65,258		—			—			65,258
Total assets	$	2,244,438	$	209		$	(163	)	$	2,244,484
Liabilities and Stockholders' Equity:
Current liabilities	$	264,687	$	—		$	—		$	264,687
Long-term debt	803,222		—			—			803,222
Deferred income taxes	122,350		—			—			122,350
Other noncurrent liabilities	24,691		46			—			24,737
Stockholders' equity	1,029,488		163			(163		)	1,029,488
Total liabilities and stockholders' equity	$	2,244,438	$	209		$	(163	)	$	2,244,484

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Condensed Consolidating Statements of Operations



	Three Months Ended June 30, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	62,505		$	113		$	—	$	62,618
Operating expenses	(73,596		)	(157		)	—		(73,753		)
General and administrative	(14,672		)	—			—		(14,672		)
Interest income and other income (expense)	(45,721		)	—			—		(45,721		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(71,484		)	(44		)	—		(71,528		)
(Provision for) Benefit from income taxes	26,947			—			—		26,947
Equity in earnings (loss) of subsidiaries	(44		)	—			44		—
Net income (loss)	$	(44,581	)	$	(44	)	$	44	$	(44,581	)

	Six Months Ended June 30, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	111,401		$	251		$	—	$	111,652
Operating expenses	(148,594		)	(318		)	—		(148,912		)
General and administrative	(28,001		)	—			—		(28,001		)
Interest income and other income (expense)	(24,871		)	—			—		(24,871		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(90,065		)	(67		)	—		(90,132		)
(Provision for) Benefit from income taxes	33,820			—			—		33,820
Equity in earnings (loss) of subsidiaries	(67		)	—			67		—
Net income (loss)	$	(56,312	)	$	(67	)	$	67	$	(56,312	)

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	Three Months Ended June 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	145,004		$	4		$	—	$	145,008
Operating expenses	(104,014		)	(59		)	—		(104,073		)
General and administrative	(14,521		)	—			—		(14,521		)
Interest and other income (expense)	(64,279		)	35			—		(64,244		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(37,810		)	(20		)	—		(37,830		)
(Provision for) Benefit from income taxes	11,244			—			—		11,244
Equity in earnings of subsidiaries	(20		)	—			20		—
Net income (loss)	$	(26,586	)	$	(20	)	$	20	$	(26,586	)

	Six Months Ended June 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	272,705		$	(9	)	$	—	$	272,696
Operating expenses	(197,007		)	(130		)	—		(197,137		)
General and administrative	(29,928		)	—			—		(29,928		)
Interest and other income (expense)	(106,490		)	35			—		(106,455		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(60,720		)	(104		)	—		(60,824		)
(Provision for) Benefit from income taxes	21,489			—			—		21,489
Equity in earnings (loss) of subsidiaries	(104		)	—			104		—
Net income (loss)	$	(39,335	)	$	(104	)	$	104	$	(39,335	)

Condensed Consolidating Statements of Comprehensive Income (Loss)



	Three Months Ended June 30, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	(44,581	)	$	(44	)	$	44	$	(44,581	)
Other Comprehensive Income (Loss), net of tax:
Effect of derivative financial instruments	—			—			—		—
Other comprehensive income (loss)	—			—			—		—
Comprehensive income (loss)	$	(44,581	)	$	(44	)	$	44	$	(44,581	)

	Six Months Ended June 30, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	(56,312	)	$	(67	)	$	67	$	(56,312	)
Other Comprehensive Income (Loss), net of tax:
Effect of derivative financial instruments	—			—			—		—
Other comprehensive income (loss)	—			—			—		—
Comprehensive income (loss)	$	(56,312	)	$	(67	)	$	67	$	(56,312	)

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	Three Months Ended June 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	(26,586	)	$	(20	)	$	20	$	(26,586	)
Other Comprehensive Income (Loss), net of tax:
Effect of derivative financial instruments	(239		)	—			—		(239		)
Other comprehensive income (loss)	(239		)	—			—		(239		)
Comprehensive income (loss)	$	(26,825	)	$	(20	)	$	20	$	(26,825	)

	Six Months Ended June 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	(39,335	)	$	(104	)	$	104	$	(39,335	)
Other Comprehensive Income (Loss), net of tax:
Effect of derivative financial instruments	(336		)	—			—		(336		)
Other comprehensive income (loss)	(336		)	—			—		(336		)
Comprehensive income (loss)	$	(39,671	)	$	(104	)	$	104	$	(39,671	)

Condensed Consolidating Statements of Cash Flows



	Six Months Ended June 30, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	90,952		$	189		$	—		$	91,141
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(195,492		)	1,369			—			(194,123		)
Additions to furniture, fixtures and other	(878		)	—			—			(878		)
Proceeds from sale of properties and other investing activities	66,518			—			—			66,518
Cash paid for short-term investments	(114,883		)	—			—			(114,883		)
Proceeds from sale of short-term investments	50,000			—			—			50,000
Intercompany transfers	1,558			—			(1,558		)	—
Cash flows from financing activities:
Proceeds from debt	—			—			—			—
Principal payments on debt	(24,976		)	—			—			(24,976		)
Intercompany transfers	—			(1,558		)	1,558			—
Other financing activities	(2,821		)	—			—			(2,821		)
Change in cash and cash equivalents	(130,022		)	—			—			(130,022		)
Beginning cash and cash equivalents	165,904			—			—			165,904
Ending cash and cash equivalents	$	35,882		$	—		$	—		$	35,882

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	Six Months Ended June 30, 2014
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	127,382		$	36		$	—		$	127,418
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(260,783		)	(3,562		)	—			(264,345		)
Additions to furniture, fixtures and other	(856		)	—			—			(856		)
Proceeds from sale of properties and other investing activities	7,640			535			—			8,175
Intercompany transfers	(2,991		)	—			2,991			—
Cash flows from financing activities:
Proceeds from debt	135,000			—			—			135,000
Principal payments on debt	(2,285		)	—			—			(2,285		)
Intercompany transfers	—			2,991			(2,991		)	—
Other financing activities	(1,923		)	—			—			(1,923		)
Change in cash and cash equivalents	1,184			—			—			1,184
Beginning cash and cash equivalents	54,595			—			—			54,595
Ending cash and cash equivalents	$	55,779		$	—		$	—		$	55,779

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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, risks and uncertainties relating to:


•	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"), and the risk of a prolonged period of depressed prices;


•	derivative and hedging activities;


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


•	solely operating in the Rocky Mountain region;


•	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 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, including those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2014 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

We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.

We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share.

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We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders' expectations and regulatory requirements.

Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, other indebtedness, and/or debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.

Because of our growth through acquisitions and, more recently, development of our properties and sales of properties in 2012, 2013, 2014 and 2015, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not indicative of future results.

Commodity prices are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget using internally generated management estimates regarding sales price assumptions and our existing hedge position. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month to 18-month basis using a combination of swaps and other financial derivative instruments. We currently have hedged approximately 80% of our expected remaining 2015 production and approximately 40% our expected 2016 production at price levels that provide some economic certainty.

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 June 30, 2015 Compared with Three Months Ended June 30, 2014



	Three Months Ended June 30,					Increase (Decrease)
	2015			2014		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	61,382		$	136,220	$	(74,838	)	(55	)%
Other	1,236			8,788		(7,552		)	(86	)%
Operating Expenses
Lease operating expense	11,405			15,919		(4,514		)	(28	)%
Gathering, transportation and processing expense ⁽¹⁾	933			11,750		(10,817		)	(92	)%
Production tax expense	3,816			9,651		(5,835		)	(60	)%
Exploration expense	92			116		(24		)	(21	)%
Impairment, dry hole costs and abandonment expense	1,090			1,743		(653		)	(37	)%
(Gain) Loss on divestitures	(644		)	—		(644		)	*nm
Depreciation, depletion and amortization	52,674			64,894		(12,220		)	(19	)%
Unused commitments ⁽¹⁾	4,387			—		4,387			*nm
General and administrative expense ⁽²⁾	11,903			11,998		(95		)	(1	)%
Long-term cash and equity incentive compensation ⁽²⁾	2,769			2,523		246			10	%
Total operating expenses	$	88,425		$	118,594	$	(30,169	)	(25	)%
Production Data:
Oil (MBbls)	1,120			1,026		94			9	%
Natural gas (MMcf)	1,800			6,696		(4,896		)	(73	)%
NGLs (MBbls)	208			480		(272		)	(57	)%
Combined volumes (MBoe)	1,628			2,622		(994		)	(38	)%
Daily combined volumes (Boe/d)	17,890			28,813		(10,923		)	(38	)%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	48.68		$	86.64	$	(37.96	)	(44	)%
Natural gas (per Mcf)	2.33			4.74		(2.41		)	(51	)%
NGLs (per Bbl)	12.76			31.64		(18.88		)	(60	)%
Combined (per Boe)	37.70			51.80		(14.10		)	(27	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	78.44		$	79.69	$	(1.25	)	(2	)%
Natural gas (per Mcf)	4.10			4.46		(0.36		)	(8	)%
NGLs (per Bbl)	12.76			31.75		(18.99		)	(60	)%
Combined (per Boe)	60.13			48.39		11.74			24	%
Average Costs (per Boe):
Lease operating expense	$	7.01		$	6.07	$	0.94		15	%
Gathering, transportation and processing expense ⁽¹⁾	0.57			4.48		(3.91		)	(87	)%
Production tax expense	2.34			3.68		(1.34		)	(36	)%
Depreciation, depletion and amortization	32.36			24.75		7.61			31	%
General and administrative expense ⁽³⁾	7.31			4.58		2.73			60	%


*	Not meaningful.

(1)

Subsequent to the Piceance Divestiture on September 30, 2014, gathering, transportation and processing expense excludes demand charges associated with unused transportation contracts not included in the sale of certain gas assets during 2013 and 2014. We will continue to incur monthly demand charges of approximately $1.5 million for the remaining term ending July 31, 2021, and these costs are included in unused commitments in the Unaudited Consolidated Statements of Operations.


(2)	Long-term cash and equity incentive compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $14.7 million and $14.5 million for the three months ended June 30, 2015 and

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2014, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of long-term cash and equity incentive compensation from general and administrative expense allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with cash performance compensation programs and stock-based grants.

(3)

Excludes long-term cash and equity incentive compensation as described in Note 2 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including long-term cash and equity incentive compensation, as presented in the Unaudited Consolidated Statements of Operations, were $9.01 and $5.54 for the three months ended June 30, 2015 and 2014, respectively.

Production Revenues and Volumes. Production revenues decreased to $61.4 million for the three months ended June 30, 2015 from $136.2 million for the three months ended June 30, 2014. The decrease in production revenues was due to a 38% decrease in production volumes and a 27% decrease in average realized prices before hedging. The decrease in production volumes reduced production revenues by approximately $37.5 million, while the decrease in average prices reduced production revenues by approximately $37.3 million.

Total production volumes of 1.6 MMBoe for the three months ended June 30, 2015 decreased from 2.6 MMBoe for the three months ended June 30, 2014. The decrease is primarily related to the sale of our natural gas assets in the Piceance Basin (the "Piceance Divestiture") completed in the third quarter of 2014 and the sale of our oil assets in the Powder River Basin (the "Powder River Oil Divestitures") in the third quarter of 2014 and the first quarter of 2015. These decreases were partially offset by a 76% overall increase in DJ Basin production. Additional information concerning production is in the following table:



	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014				% 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)
DJ Basin	729	186	1,350	1,140	376	99	1,038	648	94	%	88	%	30	%	76	%
Uinta Oil Program	389	22	444	485	482	32	588	612	(19	)%	(31	)%	(24	)%	(21	)%
Other ⁽¹⁾	2	—	6	3	168	349	5,070	1,362	(99	)%	*nm		(100	)%	(100	)%
Total	1,120	208	1,800	1,628	1,026	480	6,696	2,622	9	%	(57	)%	(73	)%	(38	)%


*	Not meaningful.


(1)	Includes oil, NGL and natural gas volumes of 53 MBbls, 337 MBbls and 4,902 MMcf, respectively, from the Piceance Basin and 115 MBbls, 11 MBbls and 144 MMcf, respectively, from the Powder River Basin for the three months ended June 30, 2014.

Hedging Activities. During the three months ended June 30, 2015, approximately 92% of our oil volumes and 96% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $33.3 million and natural gas income of $3.2 million after settlements for all commodity derivatives. The $36.5 million gain on settlements for the three months ended June 30, 2015 was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

During the three months ended June 30, 2014, approximately 80% of our oil volumes, 88% of our natural gas volumes and 19% of our NGL related volumes were subject to financial hedges, which resulted in decreases in oil income of $7.1 million and natural gas income of $1.9 million, partially offset by an increase in NGL income of $0.1 million after settlements for all commodity derivatives. Of the $8.9 million loss on total settlements for the three months ended June 30, 2014, a gain of $0.4 million was included in oil, gas and NGL production revenues and a loss of $9.3 million was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

Other Operating Revenues. Other operating revenues decreased to $1.2 million for the three months ended June 30, 2015 from $8.8 million for the three months ended June 30, 2014. Other operating revenues for the three months ended June 30, 2015 consisted of a $1.0 million Utah severance tax refund related to the West Tavaputs area of the Uinta Basin. The West Tavaputs properties were sold in December 2013. Additional income of $0.2 million related to gathering and compression fees received from third parties.

Other operating revenues for the three months ended June 30, 2014 consisted of a $5.7 million adjustment related to the recovery of processing deductions for NGL revenues, $2.5 million in net gains realized from the sale of properties and $0.6 million of income from gathering and compression fees received from third parties. Based on guidance provided by the Federal

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Office of Natural Resources Revenue, 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 Project").

Lease Operating Expense ("LOE"). LOE increased to $7.01 per Boe for the three months ended June 30, 2015 from $6.07 per Boe for the three months ended June 30, 2014. 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 through the Piceance Divestiture contributed to a higher LOE per Boe for the three months ended June 30, 2015.

Gathering, Transportation and Processing Expense ("GTP"). GTP expense decreased to $0.57 per Boe for the three months ended June 30, 2015 from $4.48 per Boe for the three months ended June 30, 2014. GTP expense on a per Boe basis decreased due to inherently lower GTP expense from our oil producing properties in the Uinta and DJ Basin development areas and due to the sale of natural gas properties with higher GTP expense per Boe in the Piceance Divestiture. Beginning October 1, 2014, costs associated with unused firm natural gas pipeline transportation contracts have been included in unused commitments in the Unaudited Consolidated Statements of Operations. See "Unused Commitments" below for further information.

Production Tax Expense. Total production taxes decreased to $3.8 million for the three months ended June 30, 2015 from $9.7 million for the three months ended June 30, 2014. The overall decrease in production tax expense is related to the Piceance Divestiture and the Powder River Oil Divestitures and a 27% decrease in average realized prices before hedging. 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 6.2% and 7.1% for the three months ended June 30, 2015 and June 30, 2014, 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.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the three months ended June 30, 2015 and 2014 is summarized below:



	Three Months Ended June 30,
	2015				2014
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	272		⁽¹⁾	$	—
Non-cash impairment of unproved oil and gas properties	173			⁽¹⁾	—
Non-cash impairment of inventory	—				340
Dry hole expense	(58		)		(12		)
Abandonment expense/ Lease expirations	703				1,415
Total non-cash impairment, dry hole costs and abandonment expense	$	1,090			$	1,743


(1)	Non-cash impairment of proved and unproved oil and gas properties for the three months ended June 30, 2015 related to our remaining Powder River Basin properties based upon a true up of previously estimated fair value relative to carrying value. These assets were classified as held for sale as of December 31, 2014 and sold in February 2015.

Given the decline in current and future commodity prices, we will continue to review our acreage position and future drilling plans. In addition, we will assess the carrying value of our properties relative to their estimated future net cash flows and estimated fair values. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date. If commodity prices and actual operating results vary from management estimates, we may incur additional non-cash property impairments in future periods, which could have a material adverse effect on our results of operations in the period taken.

Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $52.7 million for the three months ended June 30, 2015 compared with $64.9 million for the three months ended June 30, 2014. The decrease of $12.2 million was a

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result of a 38% decrease in production for the three months ended June 30, 2015 compared with the three months ended June 30, 2014 primarily due to the Piceance Divestiture and Powder River Oil Divestitures, partially offset by an increase in the DD&A rate. The decrease in production accounted for a $24.6 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $12.4 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 June 30, 2015, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $32.36 per Boe compared with $24.75 per Boe for the three months ended June 30, 2014. The increase in the DD&A rate during the three months ended June 30, 2015 compared with the three months ended June 30, 2014 was due to an increase in oil development, which has higher capital costs per Boe compared to natural gas development, and due to the sale of natural gas properties in the Piceance Divestiture which had lower capital costs per Boe compared to oil development. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.

Unused Commitments. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of the previous divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Unaudited Consolidated Statements of Operations. Unused commitments expense for the three months ended June 30, 2015 included $4.4 million related to these contracts.

General and Administrative Expense. General and administrative expense, excluding long-term cash and equity compensation, decreased slightly to $11.9 million for the three months ended June 30, 2015 from $12.0 million for the three months ended June 30, 2014. General and administrative expense, excluding long-term cash and equity compensation, is a non-GAAP measure. See Note 2 to the table on page 30 for a reconciliation and explanation.

Long-term cash and equity incentive compensation for the three months ended June 30, 2015 and 2014 were $2.8 million and $2.5 million, respectively. The components of long-term cash and equity incentive compensation for the three months ended June 30, 2015 and 2014 are shown in the following table:



	Three Months Ended June 30,
	2015		2014
	(in thousands)
Stock options and nonvested shares of common stock	$	2,557	$	2,380
Shares issued for 401(k) plan ⁽¹⁾	—		124
Shares issued for directors' fees	18		19
Performance cash units	194		—
Total	$	2,769	$	2,523


(1)	Starting in the second quarter of 2015, we no longer issue 401(k) plan shares under our 401(k) match program; employees now receive cash only under this program.

Interest Expense. Interest expense decreased to $17.4 million for the three months ended June 30, 2015 from $17.8 million for the three months ended June 30, 2014. Our weighted average interest rate for the three months ended June 30, 2015 was 8.6% compared to 6.6% for the three months ended June 30, 2014. The increase in the average interest rate for the three months ended June 30, 2015 was due to paying down our Amended Credit Facility and our Convertible Notes, both of which have lower interest rates than our remaining bonds. In addition, we expensed deferred financing charges of $1.6 million related to amending the credit facility during the three months ended June 30, 2015. See Note 4 to the accompanying Unaudited Consolidated Financial Statements for additional details related to the amendment of the credit facility.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $27.7 million for the three months ended June 30, 2015 compared with a loss of $46.8 million for the three months ended June 30, 2014. The loss on commodity

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derivatives is related to fluctuations of oil, natural gas and NGL future pricing compared to actual pricing of commodity hedges in place as of June 30, 2015 and 2014.

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



	Three Months Ended June 30,
	2015			2014
	(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges ⁽¹⁾	$	36,523		$	(9,326	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges ⁽¹⁾	(64,180		)	(37,449		)
Total commodity derivative gain (loss)	$	(27,657	)	$	(46,775	)

(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 (Expense) Benefit. Income tax benefit totaled $26.9 million for the three months ended June 30, 2015 compared with income tax benefit of $11.2 million for the three months ended June 30, 2014, resulting in effective tax rates of 37.7% and 29.7%, respectively. The tax benefit increase is due to variations in revenue and expense items as discussed above resulting in larger pretax book loss for the three months ended June 30, 2015. For both the 2015 and 2014 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 June 30, 2015 there was a decrease in permanent items primarily related to the decrease in stock based compensation and the officer compensation limitation.

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Six Months Ended June 30, 2015 Compared with Six Months Ended June 30, 2014



	Six Months Ended June 30,					Increase (Decrease)
	2015			2014		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	109,868		$	263,389	$	(153,521	)	(58	)%
Other	1,784			9,307		(7,523		)	(81	)%
Operating Expenses
Lease operating expense	25,196			32,083		(6,887		)	(21	)%
Gathering, transportation and processing expense ⁽¹⁾	1,875			23,454		(21,579		)	(92	)%
Production tax expense	6,350			17,275		(10,925		)	(63	)%
Exploration expense	125			419		(294		)	(70	)%
Impairment, dry hole costs and abandonment expense	2,345			3,504		(1,159		)	(33	)%
(Gain) Loss on divestitures	(682		)	—		(682		)	*nm
Depreciation, depletion and amortization	104,928			120,402		(15,474		)	(13	)%
Unused commitments ⁽¹⁾	8,775			—		8,775			*nm
General and administrative expense ⁽²⁾	22,182			23,817		(1,635		)	(7	)%
Long-term cash and equity incentive compensation ⁽²⁾	5,819			6,111		(292		)	(5	)%
Total operating expenses	$	176,913		$	227,065	$	(50,152	)	(22	)%
Production Data:
Oil (MBbls)	2,245			1,948		297			15	%
Natural gas (MMcf)	3,558			13,116		(9,558		)	(73	)%
NGLs (MBbls)	371			922		(551		)	(60	)%
Combined volumes (MBoe)	3,209			5,056		(1,847		)	(37	)%
Daily combined volumes (Boe/d)	17,729			27,934		(10,205		)	(37	)%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	42.89		$	84.73	$	(41.84	)	(49	)%
Natural gas (per Mcf)	2.46			5.14		(2.68		)	(52	)%
NGLs (per Bbl)	13.00			32.87		(19.87		)	(60	)%
Combined (per Boe)	34.24			51.98		(17.74		)	(34	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	77.35		$	79.26	$	(1.91	)	(2	)%
Natural gas (per Mcf)	4.01			4.62		(0.61		)	(13	)%
NGLs (per Bbl)	13.00			32.35		(19.35		)	(60	)%
Combined (per Boe)	60.07			48.43		11.64			24	%
Average Costs (per Boe):
Lease operating expense	$	7.85		$	6.35	$	1.50		24	%
Gathering, transportation and processing expense ⁽¹⁾	0.58			4.64		(4.06		)	(88	)%
Production tax expense	1.98			3.42		(1.44		)	(42	)%
Depreciation, depletion and amortization	32.70			23.81		8.89			37	%
General and administrative expense ⁽³⁾	6.91			4.71		2.20			47	%


*	Not meaningful.

(1)

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(2)

Long-term cash and equity incentive compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $28.0 million and $29.9 million for the six months ended June 30, 2015 and 2014, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of long-term cash and equity incentive compensation from general and administrative expense allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with cash performance compensation programs and stock-based grants.

(3)

Excludes long-term cash and equity incentive compensation as described in Note 2 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including long-term cash and equity incentive compensation, as presented in the Unaudited Consolidated Statements of Operations, were $8.73 and $5.92 for the six months ended June 30, 2015 and 2014, respectively.

Production Revenues and Volumes. Production revenues decreased to $109.9 million for the six months ended June 30, 2015 from $263.4 million for the six months ended June 30, 2014. The decrease in production revenues was due to a 37% decrease in production volumes and a 34% decrease in average realized prices before hedging. The decrease in production volumes reduced production revenues by approximately $63.2 million, while the decrease in average realized prices before hedging decreased production revenues by approximately $90.3 million.

Total production volumes of 3.2 MMBoe for the six months ended June 30, 2015 decreased from 5.1 MMBoe for the six months ended June 30, 2014. The decrease is primarily related to the Piceance Divestiture and Powder River Oil Divestitures, partially offset by a 79% overall increase in DJ Basin production. Additional information concerning production is in the following table:



	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014				% 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)
DJ Basin	1,436	323	2,592	2,191	733	191	1,818	1,227	96	%	69	%	43	%	79	%
Uinta Oil Program	789	47	960	996	884	62	1,110	1,131	(11	)%	(24	)%	(14	)%	(12	)%
Other ⁽¹⁾	20	1	6	22	331	669	10,188	2,698	(94	)%	(100	)%	(100	)%	(99	)%
Total	2,245	371	3,558	3,209	1,948	922	13,116	5,056	15	%	(60	)%	(73	)%	(37	)%


(1)	Includes oil, NGL and gas volumes of 114 MBbls, 655 MBbls and 9,924 MMcf, respectively, from the Piceance Basin and 214 MBbls, 13 MBbls and 258 MMcf, respectively, from the Powder River Basin for the six months ended June 30, 2014.

Hedging Activities. During the six months ended June 30, 2015, approximately 91% of our oil volumes and 94% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $77.4 million and natural gas income of $5.5 million after settlements for all commodity derivatives. The $82.9 million gain on settlements for the six months ended June 30, 2015 was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

During the six months ended June 30, 2014, approximately 84% of our oil volumes, 90% of our natural gas volumes and 18% of our NGL related volumes were subject to financial hedges, which resulted in decreases in oil income of $10.6 million, natural gas income of $6.9 million and NGL income of $0.5 million after settlements for all commodity derivatives. Of the $18.0 million loss on settlements for the six months ended June 30, 2014, a $0.5 million gain was included in oil, gas and NGL production revenues and a $18.5 million loss was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

Other Operating Revenues. Other operating revenues decreased to $1.8 million for the six months ended June 30, 2015 from $9.3 million for the six months ended June 30, 2014. Other operating revenues for the six months ended June 30, 2015 consisted of a $1.0 million Utah severance tax refund related to the West Tavaputs area of the Uinta Basin. The West Tavaputs properties were sold in December 2013. Additional income of $0.8 million related to gathering and compression fees received from third parties.

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Other operating revenues for the six months ended June 30, 2014 consisted of a $5.7 million adjustment related to recovering processing deductions from the West Tavaputs Project, $2.5 million in net gains realized from the sale of properties and $1.1 million of income from gathering and compression fees received from third parties.

Lease Operating Expense. LOE increased to $7.85 per Boe for the six months ended June 30, 2015 from $6.35 per Boe for the six months ended June 30, 2014. 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 through the Piceance Divestiture contributed to a higher LOE per Boe for the six months ended June 30, 2015.

Gathering, Transportation and Processing Expense. GTP expense decreased to $0.58 per Boe for the six months ended June 30, 2015 from $4.64 per Boe for the six months ended June 30, 2014. GTP expense on a per Boe basis decreased due to inherently lower GTP expense from our oil producing properties in the Uinta and DJ Basin development areas and due to the sale of natural gas properties with higher GTP expense per Boe in the Piceance Divestiture. Beginning October 1, 2014, costs associated with unused firm natural gas pipeline transportation contracts have been included in unused commitments in the Unaudited Consolidated Statements of Operations. See "Unused Commitments" below for further information.

Production Tax Expense. Total production taxes decreased to $6.4 million for the six months ended June 30, 2015 from $17.3 million for the six months ended June 30, 2014. The overall decrease in production tax expense is related to the Piceance Divestiture and the Powder River Oil Divestitures and a 34% decrease in average realized prices before hedging. 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 5.8% and 6.6% for the six months ended June 30, 2015 and 2014, respectively.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the six months ended June 30, 2015 and 2014 are summarized below:



	Six Months Ended June 30,
	2015				2014
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	272		⁽¹⁾	$	1,038	⁽²⁾
Non-cash impairment of unproved oil and gas properties	231			⁽¹⁾	—
Non-cash impairment of inventory	—				340
Dry hole expense	(43		)		94
Abandonment expense	1,885				2,032
Total non-cash impairment, dry hole costs and abandonment expense	$	2,345			$	3,504


(1)	Non-cash impairment of proved and unproved oil and gas properties for the six months ended June 30, 2015 related to our remaining Powder River Basin properties based upon a true up of previously estimated fair value relative to carrying value. These assets were classified as held for sale as of December 31, 2014 and sold in February 2015.


(2)	Non-cash impairment of proved oil and gas properties for the six months ended June 30, 2014 related to our West Tavaputs properties based upon a true up of previously estimated fair value relative to carrying value. These assets were sold in December 2013.

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Depreciation, Depletion and Amortization. DD&A decreased to $104.9 million for the six months ended June 30, 2015 compared with $120.4 million for the six months ended June 30, 2014. The decrease of $15.5 million was a result of the 37% decrease in production for the six months ended June 30, 2015 compared with the six months ended June 30, 2014 primarily due to the Piceance Divestiture and Powder River Oil Divestitures, partially offset by an increase in the DD&A rate. The decrease in production accounted for a $44.0 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $28.5 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 six months ended June 30, 2015, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $32.70 per Boe compared with $23.81 per Boe for the six months ended June 30, 2014. The increase in the DD&A rate during the six months ended June 30, 2015 compared with the six months ended June 30, 2014 was due to an increase in oil development, which has higher capital costs per Boe compared to natural gas development, and to the sale of natural gas properties in the Piceance Divestiture which had lower capital costs per Boe compared to oil development. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.

Unused Commitments. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of the previous divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Unaudited Consolidated Statements of Operations. Unused commitments expense for the six months ended June 30, 2015 included $8.8 million related to these contracts.

General and Administrative Expense. General and administrative expense, excluding long-term cash and equity incentive compensation, decreased to $22.2 million for the six months ended June 30, 2015 from $23.8 million for the six months ended June 30, 2014. General and administrative expense, excluding long-term cash and equity incentive compensation, is a non-GAAP measure. See Note 2 to the table on page 36 for a reconciliation and explanation.

Long-term cash and equity incentive compensation for the six months ended June 30, 2015 and 2014 was $5.8 million and $6.1 million, respectively. The components of long-term cash and equity incentive compensation for the six months ended June 30, 2015 and 2014 are shown in the following table:



	Six Months Ended June 30,
	2015		2014
	(in thousands)
Stock options and nonvested shares of common stock	$	5,064	$	5,680
Shares issued for 401(k) plan ⁽¹⁾	273		393
Shares issued for directors' fees	37		38
Performance cash units	445		—
Total	$	5,819	$	6,111


(1)	Starting in the second quarter of 2015, we no longer issue 401(k) plan shares under our 401(k) match program; employees now receive cash only under this program.

Interest Expense. Interest expense decreased to $33.8 million for the six months ended June 30, 2015 from $35.3 million for the six months ended June 30, 2014. The decrease for the six months ended June 30, 2015 was primarily due to our use of the proceeds from the Piceance Divestiture to reduce the average debt balance. Our weighted average interest rate for the six months ended June 30, 2015 was 8.3% compared to 6.7% for the six months ended June 30, 2014. The increase in the average interest rate for the six months ended June 30, 2015 was due to paying down our Amended Credit Facility and our Convertible Notes, both of which have lower interest rates than our remaining bonds. In addition, we expensed deferred financing charges of $1.6 million related to amending the credit facility during the six months ended June 30, 2015. See Note 4 to the

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accompanying Unaudited Consolidated Financial Statements for additional details related to the amendment of the credit facility.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) changed to a gain of $6.8 million for the six months ended June 30, 2015 compared with a loss of $71.9 million for the six months ended June 30, 2014. 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 June 30, 2015 and 2014.

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



	Six Months Ended June 30,
	2015			2014
	(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges ⁽¹⁾	$	82,898		$	(18,526	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges ⁽¹⁾	(76,117		)	(53,404		)
Total commodity derivative gain (loss)	$	6,781		$	(71,930	)

(1)

Income Tax (Expense) Benefit. Income tax benefit totaled $33.8 million for the six months ended June 30, 2015 compared with an income tax benefit of $21.5 million for the six months ended June 30, 2014, resulting in effective tax rates of 37.5% and 35.3%, respectively. For both the 2015 and 2014 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, officer's compensation, state taxes and gain on extinguishment of debt, which are not deductible or considered income for income tax purposes. For the six months ended June 30, 2015, the non-deductible permanent items were $1.3 million less than in the six months ended June 30, 2014, primarily due to reduced limitations for stock-based compensation and officer compensation. The increase 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 potential issuances 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 on hand, cash flows from operations and under our Amended Credit Facility for our planned uses of capital for the remainder of 2015. However, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions if we believe conditions to be favorable.

At June 30, 2015, we had cash and cash equivalents of $35.9 million, short-term investments of $65.0 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2014, we had cash and cash equivalents of $165.9 million and no amounts outstanding under our Amended Credit Facility. Our borrowing base was $375.0 million as of June 30, 2015, which is dependent on our proved reserves and hedge position and is calculated using future commodity pricing provided by our lenders. Our remaining borrowing capacity was reduced by $26.0 million to $349.0 million as of June 30, 2015 due to an outstanding irrevocable letter of credit related to a firm transportation agreement. Future borrowing base will be determined at the sole discretion of the lenders.

Cash Flow from Operating Activities

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Net cash provided by operating activities for the six months ended June 30, 2015 and 2014 was $91.1 million and $127.4 million, respectively. The decrease in net cash provided by operating activities was primarily due to a decrease in production revenues offset by an increase in commodity 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 June 30, 2015, we had in place crude oil swaps covering portions of our 2015, 2016 and 2017 production and natural gas swaps covering portions of our 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 June 30, 2015, the estimated fair value of all of our commodity derivative instruments was a net asset of $118.9 million, comprised of current and noncurrent assets.

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)
Commodity derivative settlements on derivatives designated as cash flow hedges ⁽¹⁾	$	—		$	382		$	—		$	538
Realized gains (losses) on derivatives not designated as cash flow hedges ⁽²⁾⁽³⁾	$	36,523		$	(9,326	)	$	82,898		$	(18,526	)
Unrealized gains (losses) on derivatives not designated as cash flow hedges ⁽²⁾⁽³⁾	(64,180		)	(37,449		)	(76,117		)	(53,404		)
Total commodity derivative gain (loss)	$	(27,657	)	$	(46,775	)	$	6,781		$	(71,930	)


(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)

The following table summarizes all of our hedges in place as of June 30, 2015. There were no hedges entered into subsequent to June 30, 2015 through July 24, 2015.

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Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price ⁽¹⁾	Fair Market Value (in thousands)
Swap Contracts:
2015
Oil	1,987,200	Bbls	$	89.81	WTI	$	58,405
Natural gas	3,680,000	MMBtu	$	4.13	NWPL	5,015
2016
Oil	2,478,600	Bbls	$	80.47	WTI	45,301
Natural gas	1,830,000	MMBtu	$	4.10	NWPL	2,080
2017
Oil	683,250	Bbls	$	75.61	WTI	8,058
Total						$	118,859


(1)	WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange ("NYMEX"). NWPL refers to the Northwest Pipeline Corporation price as quoted in Platt's Inside FERC on the first business day of each month.

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 to us under the derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.

Capital Expenditures

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



	Six Months Ended June 30,
Basin/Area	2015		2014
	(in millions)
DJ	$	158.6	$	180.3
Uinta Oil Program	19.1		74.0
Other	1.8		18.8
Total	$	179.5	$	273.1

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	Six Months Ended June 30,
	2015		2014
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	3.4	$	6.5
Drilling, development, exploration and exploitation of oil and natural gas properties	167.7		258.4
Gathering and compression facilities	5.2		6.5
Geologic and geophysical costs	2.3		0.5
Furniture, fixtures and equipment	0.9		1.2
Total	$	179.5	$	273.1

Our current estimated capital expenditure budget in 2015 is between $320.0 to $350.0 million. The budget targets exclusively oil activities and includes facilities costs, but excludes acquisitions. We expect our 2015 capital expenditure plan to result in continued growth in production from our DJ Basin assets, in substantial part due to the extended reach lateral wells we are drilling in the area. We also expect to continue to benefit from significant improvements in per well drilling and completion costs relative to the costs experienced in 2014. 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 further or costs increase relative to levels we consider acceptable, 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. We would generally expect to do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures, including those relating to 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 cash on hand, short-term investments, capacity under the Amended Credit Facility and cash flow from operations to fund our 2015 budgeted capital expenditures. In addition, in June 2015, we entered into an Equity Distribution Agreement with Goldman, Sachs and Co. (the "Equity Distribution Agreement") pursuant to which we may elect to sell from time to time shares of our common stock to the public having an aggregate gross sales price of up to $100.0 million. While we have not sold any shares pursuant to the Equity Distribution Agreement to date, it provides us with another potential source of liquidity. Future cash flows are subject to a number of variables, including our level of oil and natural gas 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

On April 9, 2015, we entered into a Third Amendment (the "Third Amendment") to the Amended Credit Facility dated March 16, 2010. The Third Amendment amended the definition of "Maturity Date" in the credit agreement to mean the earliest of (a) April 9, 2020 or (b) the date 181 days prior to the maturity of certain unsecured senior or senior subordinated debt of ours in existence as of the date of the Third Amendment or that may be incurred by us as of a future date, or any permitted refinancing debt in respect thereof. The Amended Credit Facility currently has commitments and a borrowing base of $375.0 million from 13 lenders. Due to the Third Amendment, we recognized interest expense of $1.6 million and a loss on extinguishment of debt of $0.8 million on the Unaudited Consolidated Statements of Operations related to expensing deferred financing charges during the three and six months ended June 30, 2015. As of June 30, 2015, 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 has been issued under the Amended Credit Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of June 30, 2015 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 unused commitment fee is between 0.375% to 0.5% based on borrowing base utilization. We had no amounts outstanding under the Amended Credit Facility as of June 30, 2015. The average annual interest rate incurred on the Amended Credit Facility was 1.8% for the six months ended June 30, 2014.

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The borrowing base is required to be re-determined twice per year, on or about April 1 and October 1. Future semi-annual borrowing bases will be computed based on our proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt.

The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants from the time we entered into the facility.

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 redeemed by us at par. On March 20, 2015, $24.8 million of the remaining outstanding principal amount, or approximately 98% of the remaining outstanding Convertible Notes, were put to us and redeemed by us at par. We settled the notes in cash and recognized a gain on extinguishment of $2.6 million in the Unaudited Consolidated Statements of Operations for the six months ended June 30, 2015. After the redemption, $0.6 million aggregate principal amount of the Convertible Notes were outstanding as of June 30, 2015. 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, 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 of each year. 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 beginning on October 1, 2015 at our option at an initial 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 generally 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. 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 beginning on October 15, 2017 at an initial redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally 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

We have a Lease Financing Obligation with a balance of $3.4 million as of June 30, 2015 whereby we sold and subsequently leased back the existing compressors and related facilities owned by us. The Lease Financing Obligation expires

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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 pursuant to which we may purchase the equipment for $1.8 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 to the accompanying Unaudited Consolidated Financial Statements for a discussion of aggregate minimum future lease payments.

Our outstanding debt is summarized below:



		As of June 30, 2015						As of December 31, 2014
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount		Carrying Amount
		(in thousands)
Amended Credit Facility	April 9, 2020	$	—	$	—	$	—	$	—	$	—	$	—
Convertible Notes ⁽¹⁾	March 15, 2028 ⁽²⁾	579		—		579		25,344		—		25,344
7.625% Senior Notes ⁽³⁾	October 1, 2019	400,000		—		400,000		400,000		—		400,000
7.0% Senior Notes ⁽⁴⁾	October 15, 2022	400,000		—		400,000		400,000		—		400,000
Lease Financing Obligation ⁽⁵⁾	August 10, 2020	3,437		—		3,437		3,648		—		3,648
Total Debt		$	804,016	$	—	$	804,016	$	828,992	$	—	$	828,992
Less: Current Portion of Long-Term Debt ⁽⁶⁾		1,012		—		1,012		25,770		—		25,770
Total Long-Term Debt		$	803,004	$	—	$	803,004	$	803,222	$	—	$	803,222


(1)	The aggregate estimated fair value of the Convertible Notes was approximately $0.6 million and $25.1 million as of June 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments. On March 20, 2015, the holders put 98% of the Notes to us, leaving $0.6 million principal amount remaining.


(2)	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, 2018 and March 20, 2023.


(3)	The aggregate estimated fair value of the 7.625% Senior Notes was approximately $382.9 million and $359.8 million as of June 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.


(4)	The aggregate estimated fair value of the 7.0% Senior Notes was approximately $361.0 million and $366.0 million as of June 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.


(5)	The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.3 million and $3.5 million as of June 30, 2015 and December 31, 2014, respectively. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.


(6)	The current portion of the long-term debt as of June 30, 2015 and December 31, 2014 includes the current portion of the Lease Financing Obligation and the principal amount of the Convertible Notes.

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 7.0% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Contractual Obligations. A summary of our contractual obligations as of and subsequent to June 30, 2015 is provided in the following table:

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	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	Twelve Months Ended June 30, 2016		Twelve Months Ended June 30, 2017		Twelve Months Ended June 30, 2018		Twelve Months Ended June 30, 2019		Twelve Months Ended June 30, 2020		After June 30, 2020
	(in thousands)
Notes payable ⁽¹⁾	$	553	$	553	$	413	$	—	$	—	$	—	$	1,519
7.625% Senior Notes ⁽²⁾	30,500		30,500		30,500		30,500		407,625		—		529,625
7.0% Senior Notes ⁽³⁾	28,000		28,000		28,000		28,000		28,000		464,167		604,167
Convertible Notes ⁽⁴⁾	608		—		—		—		—		—		608
Lease Financing Obligation ⁽⁵⁾	537		537		537		2,094		—		—		3,705
Purchase commitments ⁽⁶⁾	1,531		—		—		—		—		—		1,531
Office and office equipment leases and other ⁽⁷⁾⁽⁸⁾	3,697		2,806		2,617		1,899		—		—		11,019
Firm transportation and processing agreements ⁽⁹⁾	18,307		18,692		18,692		18,692		18,692		20,249		113,324
Asset retirement obligations ⁽¹⁰⁾	1,580		180		201		411		217		20,849		23,438
Total	$	85,313	$	81,268	$	80,960	$	81,596	$	454,534	$	505,265	$	1,288,936


(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 of the letter of credit is April 30, 2018. There is currently no balance outstanding under the Amended Credit Facility.


(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. On March 20, 2015, approximately 98% of the remaining outstanding Convertible Notes, representing $24.8 million of the then outstanding principal amount, were put to us, leaving $0.6 million principal amount remaining. 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.


(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 June 30, 2015, $1.5 million of the future commitment is due by December 31, 2015.


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

(8)

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 450.0 MMcf for the period of December 1, 2014 to November 30, 2015. If the minimum volume is not delivered, we must make a deficiency payment of up to $0.8 million. As of June 30, 2015, we have satisfied approximately 132.4 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.5 million due December 1, 2015.


(9)	We have entered into contracts that provide firm transportation capacity on pipeline systems. The remaining term on these contracts is six 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.


(10)	Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2014 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of June 30, 2015.

Trends and Uncertainties

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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, 2014 for a discussion of trends and uncertainties that may affect our financial condition or liquidity.

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, 2014 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 $105.37 per Bbl at June 30, 2014 compared to $59.47 per Bbl at June 30, 2015. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the six months ended June 30, 2015, our income before income taxes would have decreased by approximately $0.1 million for each $1.00 per barrel decrease in crude oil prices, a de minimis amount for each $0.10 decrease per MMBtu in natural gas prices and $0.3 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.

As of July 24, 2015, we have financial derivative instruments related to oil and natural gas volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented under "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities."



	July – December 2015			For the year 2016			For the year 2017
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	1,987,200	$	89.81	2,478,600	$	80.47	683,250	$	75.61
Natural Gas (MMbtu)	3,680,000	$	4.13	1,830,000	$	4.10	—	$	—

Interest Rate Risks

At June 30, 2015, 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 six months ended June 30, 2014 was 1.8%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2014 would have resulted in an estimated $0.9 million increase in interest expense.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of June 30, 2015, 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. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of June 30, 2015.

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the second fiscal quarter of 2015 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 does not believe that the resolution of any currently pending proceeding will 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, 2014. 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, 2014 and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

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

Unregistered Sales of Securities

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

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended June 30, 2015:



Period	Total Number of Shares ⁽¹⁾	Weighted Average Price Paid Per Share		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1 – 30, 2015	1,960	$	11.08	—	—
May 1 – 31, 2015	1,599	9.24		—	—
June 1 – 30, 2015	483	8.62		—	—
Total	4,042	$	10.06	—	—


(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.

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Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.



Exhibit Number		Description of Exhibits
10.1		Third Amendment, dated effective as of April 9, 2015, to Third Amended and Restated Credit Agreement, dated as of March 16, 2010, among Bill Barrett Corporation, certain of its subsidiaries party thereto and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on April 9, 2015.]

10.2		Equity Distribution Agreement, dated June 10, 2015, by and between Bill Barrett Corporation and Goldman, Sachs & Co. [Incorporated by reference to Exhibit 1.1 of our Current Report on Form 8-K filed with the Commission on June 10, 2015.]

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

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SIGNATURES

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




		BILL BARRETT CORPORATION

Date:	August 6, 2015	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President
			(Principal Executive Officer)

Date:	August 6, 2015	By:	/s/ Robert W. Howard
			Robert W. Howard
			Chief Financial Officer
			(Principal Financial Officer)

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