10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2017

OR

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

For the transition period from to

Commission file number 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(303) 293-9100

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x  Yes    o  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    o  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

There were 76,283,870 shares of $0.001 par value common stock outstanding on October 17, 2017.

INDEX TO FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements (Unaudited)	3
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	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	47
Item 5.	Other Information	48
Item 6.	Exhibits	48
SIGNATURES		49

2

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2017			December 31, 2016
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	155,885		$	275,841
Accounts receivable, net of allowance for doubtful accounts	42,089			32,837
Derivative assets	5,782			8,398
Assets held for sale, net of depreciation, depletion, amortization and impairment	145,553			—
Prepayments and other current assets	2,209			1,376
Total current assets	351,518			318,452
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	1,292,786			1,539,373
Unproved oil and gas properties, excluded from amortization	70,535			58,830
Furniture, equipment and other	17,217			23,636
	1,380,538			1,621,839
Accumulated depreciation, depletion, amortization and impairment	(404,693		)	(559,690		)
Total property and equipment, net	975,845			1,062,149
Deferred income tax asset	—			1,587
Deferred financing costs and other noncurrent assets	3,143			3,153
Total	$	1,330,506		$	1,385,341
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities	$	85,678		$	49,447
Amounts payable to oil and gas property owners	12,563			6,192
Production taxes payable	22,805			22,992
Derivative liabilities	—			4,346
Deferred income taxes	—			1,587
Current portion of long-term debt	465			454
Liabilities associated with assets held for sale	4,856			—
Total current liabilities	126,367			85,018
Long-term debt, net of debt issuance costs	668,744			711,808
Asset retirement obligations	15,771			10,703
Derivatives and other noncurrent liabilities	4,610			6,269
Stockholders' equity:
Common stock, $0.001 par value; authorized 300,000,000 and 150,000,000 shares at September 30, 2017 and December 31, 2016, respectively; 76,284,992 and 75,721,360 shares issued and outstanding at September 30, 2017 and December 31, 2016, respectively, with 1,391,256 and 1,325,714 shares subject to restrictions, respectively	75			74
Additional paid-in capital	1,118,180			1,113,797
Retained earnings (accumulated deficit)	(603,241		)	(542,328		)
Treasury stock, at cost: zero shares at September 30, 2017 and December 31, 2016	—			—
Total stockholders' equity	515,014			571,543
Total	$	1,330,506		$	1,385,341

See notes to Unaudited Consolidated Financial Statements.

3

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands, except share and per share data)
Operating Revenues:
Oil, gas and NGL production	$	67,175		$	50,133		$	168,541		$	126,279
Other operating revenues	690			348			926			920
Total operating revenues	67,865			50,481			169,467			127,199
Operating Expenses:
Lease operating expense	5,919			4,795			17,287			22,101
Gathering, transportation and processing expense	620			472			1,644			1,871
Production tax expense	5,384			3,832			9,140			7,037
Exploration expense	18			16			48			64
Impairment, dry hole costs and abandonment expense	261			974			8,336			1,766
(Gain) loss on sale of properties	—			1,914			(92		)	1,206
Depreciation, depletion and amortization	41,732			43,083			119,409			125,491
Unused commitments	4,557			4,567			13,687			13,703
General and administrative expense	12,496			9,178			30,788			31,535
Other operating expenses, net	(282		)	—			(1,610		)	—
Total operating expenses	70,705			68,831			198,637			204,774
Operating Income (Loss)	(2,840		)	(18,350		)	(29,170		)	(77,575		)
Other Income and Expense:
Interest and other income	332			72			1,030			166
Interest expense	(13,926		)	(13,991		)	(44,014		)	(45,160		)
Commodity derivative gain (loss)	(12,408		)	6,054			19,654			(7,258		)
Gain (loss) on extinguishment of debt	—			29			(7,904		)	8,726
Total other income and expense	(26,002		)	(7,836		)	(31,234		)	(43,526		)
Income (Loss) before Income Taxes	(28,842		)	(26,186		)	(60,404		)	(121,101		)
(Provision for) Benefit from Income Taxes	—			—			—			—
Net Income (Loss)	$	(28,842	)	$	(26,186	)	$	(60,404	)	$	(121,101	)
Net Income (Loss) Per Common Share, Basic	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)
Net Income (Loss) Per Common Share, Diluted	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)
Weighted Average Common Shares Outstanding, Basic	74,886,107			58,851,598			74,742,699			53,081,809
Weighted Average Common Shares Outstanding, Diluted	74,886,107			58,851,598			74,742,699			53,081,809

See notes to Unaudited Consolidated Financial Statements.

4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Net Income (Loss)	$	(28,842	)	$	(26,186	)	$	(60,404	)	$	(121,101	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive Income (Loss)	$	(28,842	)	$	(26,186	)	$	(60,404	)	$	(121,101	)

See notes to Unaudited Consolidated Financial Statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(60,404	)	$	(121,101	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	119,409			125,491
Impairment, dry hole costs and abandonment expense	8,336			1,766
Commodity derivative (gain) loss	(19,654		)	7,258
Settlements of commodity derivatives	17,062			78,417
Stock compensation and other non-cash charges	5,134			7,208
Amortization of deferred financing costs	1,665			2,075
(Gain) loss on extinguishment of debt	7,904			(8,726		)
(Gain) loss on sale of properties	(92		)	1,206
Change in operating assets and liabilities:
Accounts receivable	(9,252		)	13,552
Prepayments and other assets	(980		)	(968		)
Accounts payable, accrued and other liabilities	20,071			18,903
Amounts payable to oil and gas property owners	6,371			(2,894		)
Production taxes payable	(187		)	(5,980		)
Net cash provided by (used in) operating activities	95,383			116,207
Investing Activities:
Additions to oil and gas properties, including acquisitions	(160,788		)	(93,704		)
Additions of furniture, equipment and other	(268		)	(1,184		)
Proceeds from sale of properties and other investing activities	(712		)	25,571
Net cash provided by (used in) investing activities	(161,768		)	(69,317		)
Financing Activities:
Proceeds from debt	275,000			—
Principal payments on debt	(322,228		)	(329		)
Proceeds from sale of common stock, net of offering costs	(298		)	—
Deferred financing costs and other	(6,045		)	(1,134		)
Net cash provided by (used in) financing activities	(53,571		)	(1,463		)
Increase (Decrease) in Cash and Cash Equivalents	(119,956		)	45,427
Beginning Cash and Cash Equivalents	275,841			128,836
Ending Cash and Cash Equivalents	$	155,885		$	174,263

See notes to Unaudited Consolidated Financial Statements.

6

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Total Stockholders' Equity
Balance at December 31, 2015	$	48	$	921,318		$	(371,950	)	$	—		$	549,416
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	1		—			—			(1,114		)	(1,113		)
Stock-based compensation	—		9,455			—			—			9,455
Retirement of treasury stock	—		(1,114		)	—			1,114			—
Exchange of senior notes for shares of common stock	10		74,390			—			—			74,400
Issuance of common stock, net of offering costs	15		109,748			—			—			109,763
Net income (loss)	—		—			(170,378		)	—			(170,378		)
Balance at December 31, 2016	74		1,113,797			(542,328		)	—			571,543
Cumulative effect of accounting change (1)	—		180			(509		)	—			(329		)
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	1		—			—			(1,246		)	(1,245		)
Stock-based compensation	—		5,510			—			—			5,510
Retirement of treasury stock	—		(1,246		)	—			1,246			—
Issuance of common stock, net of offering costs	—		(61		)	—			—			(61		)
Net income (loss)	—		—			(60,404		)	—			(60,404		)
Balance at September 30, 2017	$	75	$	1,118,180		$	(603,241	)	$	—		$	515,014

See notes to Unaudited Consolidated Financial Statements.

(1) Cumulative effect of accounting change relates to the adoption of Accounting Standards Update 2016-09. See Note 2 of the Consolidated Financial Statements for further detail on the adoption of this accounting standard.

7

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2017

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 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 consolidated 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 2016 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 2016 Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company's consolidated 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 include volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future net 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 payment awards.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of September 30, 2017			As of December 31, 2016
	(in thousands)
Accrued oil, gas and NGL sales	$	33,170		$	26,542
Due from joint interest owners	9,164			4,366
Other	14			1,952
Allowance for doubtful accounts	(259		)	(23		)
Total accounts receivable	$	42,089		$	32,837

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

8

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, recent sales prices of comparable properties 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.

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

	As of September 30, 2017			As of December 31, 2016
	(in thousands)
Proved properties	$	218,746		$	306,075
Wells and related equipment and facilities	1,035,764			1,164,354
Support equipment and facilities	34,317			63,238
Materials and supplies	3,959			5,706
Total proved oil and gas properties (1)	$	1,292,786		$	1,539,373
Unproved properties	33,713			27,790
Wells and facilities in progress	36,822			31,040
Total unproved oil and gas properties, excluded from amortization (1)	$	70,535		$	58,830
Accumulated depreciation, depletion, amortization and impairment (1)	(393,340		)	(543,154		)
Total oil and gas properties, net (1)	$	969,981		$	1,055,049

(1) Excludes oil and gas properties held for sale of $145.1 million, comprised of $410.7 million of proved oil and gas properties and $0.4 million of unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of $266.0 million. Held for sale balances are included in current assets as assets held for sale, net of amortization and impairment, in the Unaudited Consolidated Balance Sheet as of September 30, 2017. See Note 4 for additional information on assets held for sale.

The Company reviews oil and natural gas properties 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 using proved and risked probable and possible reserves based on the Company's development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax 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 oil and gas properties, no impairment is taken. If the carrying amount 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 of its oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, 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.

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In addition, oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique, which involves calculating the present value of future net cash flows as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Impairment of unproved oil and gas properties (1)	$	—	$	—	$	8,010	$	183
Dry hole costs	—		1		—		71
Abandonment expense and lease expirations	261		973		326		1,512
Total impairment, dry hole costs and abandonment expense	$	261	$	974	$	8,336	$	1,766

(1) The Company recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the nine months ended September 30, 2017. The Company has no current plan to develop this acreage.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.

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

	As of September 30, 2017		As of December 31, 2016
	(in thousands)
Accrued drilling, completion and facility costs	$	33,325	$	15,594
Accrued lease operating, gathering, transportation and processing expenses	4,589		4,261
Accrued general and administrative expenses	8,653		6,375
Accrued interest payable	23,500		12,264
Prepayments from partners	11,249		332
Trade payables	2,323		7,900
Other	2,039		2,721
Total accounts payable and accrued liabilities	$	85,678	$	49,447

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. Recent case law in Wyoming has exposed the Company to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contractual obligations to the Company as provided for in the applicable purchase and sale agreements, regulatory agencies and landowners may demand that the Company perform such activities. The Company recognized $0.8 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the nine months ended September 30, 2017.

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.

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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 September 30, 2017 and 2016 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. Deferred tax assets are regularly reviewed, considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, taxable strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine whether it is more likely than not that the deferred tax asset will be realized. If it is determined that the deferred tax asset will not be realized, then a valuation allowance will be recorded against the deferred tax asset. The Company began recording a full valuation allowance against the deferred tax asset during the period ending September 30, 2015 and continues to do so as of September 30, 2017.

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 September 30, 2017.

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 and in-the-money outstanding stock options to purchase the Company's common stock. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and nine months ended September 30, 2017 and 2016.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands, except per share amounts)
Net income (loss)	$	(28,842	)	$	(26,186	)	$	(60,404	)	$	(121,101	)
Basic weighted-average common shares outstanding in period	74,886			58,852			74,743			53,082
Diluted weighted-average common shares outstanding in period	74,886			58,852			74,743			53,082
Basic net income (loss) per common share	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)
Diluted net income (loss) per common share	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)

New Accounting Pronouncements. In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-09, Stock Compensation-Scope of Modification Accounting. The objective of this update is to provide clarity and reduce both diversity in practice and cost and complexity when applying a change to the terms or conditions of a share-based payment award. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

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In January 2017, the FASB issued ASU 2017-01, Business Combinations: Clarifying the definition of a business. The objective of this update is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments. The objective of this update is to address eight specific cash flow issues in order to reduce the existing diversity in practice. ASU 2016-15 is effective for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. The objective of this update is to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted effective January 1, 2017 and did not have a significant impact on the Company's disclosures or financial statements. As of January 1, 2017, the Company did not have excess tax benefits associated with its stock compensation and therefore there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes were already classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. The Company elected to account for forfeitures as they occur as opposed to estimating the number of awards that are expected to vest. Per ASU 2016-09, the election is considered a change in accounting principle, with the cumulative effect of the change reported as an adjustment to the beginning equity balance. The Company reported an increase to accumulated deficit and additional paid in capital ("APIC") of $0.2 million related to equity award compensation and an increase to accumulated deficit and derivative and other noncurrent liabilities of $0.3 million related to liability award compensation. The cumulative effect of accounting change is reported in the Consolidated Statement of Stockholders' Equity.

In February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company has performed an initial assessment by compiling and analyzing contracts and leasing arrangements that may be affected. The Company is still evaluating the impact of adopting this standard.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The objective of this update is to require deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted January 1, 2017 on a prospective basis and did not have a significant impact on the Company's disclosures and financial statements. Prior periods were not retrospectively adjusted.

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. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which provided additional implementation guidance and deferred the effective date of ASU 2014-09. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard will be adopted using the modified retrospective transition method, effective January 1, 2018. The Company has performed an assessment of its current existing revenue contracts and is in the process of implementing additional control procedures. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

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	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Cash paid for interest	$	31,113		$	31,736
Cash paid for income taxes	—			—
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	37,319			8,318
Change in asset retirement obligations, net of disposals	10,453			(4,788		)
Retirement of treasury stock	(1,246		)	(1,098		)
Properties exchanged in non-cash transactions	13,323			—
Fair value of debt exchanged for common stock (1)	—			74,400

(1) See Note 5 for additional information regarding the Debt Exchange.

4. Acquisitions, Exchanges, Divestitures and Assets Held for Sale

During the three months ended September 30, 2017, the Company committed to a plan to sell the Company's remaining assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2017. Assets held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value of the net assets held for sale was in excess of the net carrying value as of September 30, 2017. The net carrying value was presented as assets held for sale, net of depreciation, depletion, amortization and impairment, of $145.6 million and liabilities associated with assets held for sale of $4.9 million on the Unaudited Consolidated Balance Sheet as of September 30, 2017.

On February 28, 2017, the Company acquired acreage in the DJ Basin for $11.6 million, after final closing adjustments. The transaction was considered an asset acquisition and therefore the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. The acquisition included $9.1 million and $11.2 million of proved and unevaluated properties, respectively, and asset retirement obligations of $8.7 million.

During the nine months ended September 30, 2017, the Company completed two acreage exchange transactions to consolidate certain acreage positions in the DJ Basin. Pursuant to the transactions, the Company exchanged leasehold interests in certain proved undeveloped acreage. The Company’s future cash flows are not expected to significantly change as a result of the exchange transactions, therefore, the non-monetary exchanges were measured based on the carrying values and not on the fair values of the assets exchanged.

On July 14, 2016, the Company sold certain non-core assets in the Uinta Basin. The Company received $27.8 million in cash proceeds, after final closing adjustments. In addition to the cash proceeds, the Company recognized non-cash proceeds of $4.8 million related to the relief from the Company's asset retirement obligation. Assets sold included $30.6 million in proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment, and $2.0 million in unproved oil and gas properties. Liabilities sold included $4.8 million of asset retirement obligations. The transaction was accounted for as a cost recovery. Therefore, no gain or loss was recognized.

5. Long-Term Debt

The Company's outstanding debt is summarized below:

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		As of September 30, 2017							As of December 31, 2016
	Maturity Date	Principal		Debt Issuance Costs			Carrying Amount		Principal		Debt Issuance Costs			Carrying Amount
		(in thousands)
Amended Credit Facility	April 9, 2020	$	—	$	—		$	—	$	—	$	—		$	—
Convertible Notes (1)	March 15, 2028	—		—			—		579		—			579
7.625% Senior Notes (2)	October 1, 2019	—		—			—		315,300		(2,169		)	313,131
7.0% Senior Notes (3)	October 15, 2022	400,000		(3,684		)	396,316		400,000		(4,227		)	395,773
8.75% Senior Notes (4)	June 15, 2025	275,000		(4,548		)	270,452		—		—			—
Lease Financing Obligation (5)	August 10, 2020	2,443		(2		)	2,441		2,782		(3		)	2,779
Total Debt		$	677,443	$	(8,234	)	$	669,209	$	718,661	$	(6,399	)	$	712,262
Less: Current Portion of Long-Term Debt (6)		465		—			465		454		—			454
Total Long-Term Debt		$	676,978	$	(8,234	)	$	668,744	$	718,207	$	(6,399	)	$	711,808

(1) The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of December 31, 2016 based on reported market trades of these instruments.

(2) The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately $314.5 million as of December 31, 2016 based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $386.3 million and $384.5 million as of September 30, 2017 and December 31, 2016, respectively, based on reported market trades of these instruments.

(4) The aggregate estimated fair value of the 8.75% Senior Notes was approximately $266.8 million as of September 30, 2017 based on reported market trades of these instruments.

(5) The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.3 million and $2.6 million as of September 30, 2017 and December 31, 2016, respectively. As 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 long-term debt includes the current portion of the Lease Financing Obligation.

Amended Credit Facility

The Company's amended revolving credit facility ("Amended Credit Facility") had commitments from 13 lenders and a borrowing base of $300.0 million as of September 30, 2017. As credit support for future payments 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 September 30, 2017 to $274.0 million. There have not been any borrowings under the Amended Credit Facility to date in 2017 and there were no such borrowings in 2016.

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 borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of the Company's proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. In October 2017, the Company's borrowing base was re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at June 30, 2017. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the Company's lenders, as well as any other outstanding debt. Lower commodity prices could result in a decreased borrowing base.

The Amended Credit Facility contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. If the Company fails to comply with the covenants or other terms of any agreements governing the Company's debt, the Company's lenders and holders of the Company's senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect the Company's financial condition. In September 2015, the Company obtained an amendment to the Amended Credit Facility that replaced the Company's debt-to-EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses) covenant in the facility with a

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secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that the Company will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

5% Convertible Senior Notes Due 2028

On May 30, 2017, the Company redeemed the $0.6 million of outstanding Convertible Notes with the proceeds of its 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes due 2025" below for additional information.

7.625% Senior Notes Due 2019

On May 30, 2017, the Company redeemed the $315.3 million of outstanding 7.625% Senior Notes with cash on hand and proceeds from the issuance of its 8.75% Senior Notes on April 28, 2017. See "8.75% Senior Notes due 2025" below for additional information.

Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, the Company recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the nine months ended September 30, 2017.

The 7.625% Senior Notes were issued at $400.0 million in principal amount on September 27, 2011. On June 3, 2016, the Company completed a debt exchange with a holder of the 7.625% Senior Notes (the "Debt Exchange"). The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the Company’s common stock. Based on the fair value of the shares issued, the Company recognized an $8.7 million gain on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2016. Following the Debt Exchange, the remaining aggregate principal amount was $315.3 million, which, as indicated above, was then redeemed on May 30, 2017.

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 October 15, 2022 at par. The 7.0% Senior Notes mature on October 15, 2022 unless earlier redeemed or purchased by the Company. 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 8.75% Senior Notes. The 7.0% Senior Notes became redeemable at the Company's option on October 15, 2017 at a redemption price of 103.500% of the principal amount. The redemption price will decrease to 102.333%, 101.167% and 100.000% of the principal amount in 2018, 2019 and 2022, respectively. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 8.75% 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 covenants and has complied with all covenants since issuance.

8.75% Senior Notes Due 2025

On April 28, 2017, the Company issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year, commencing on December 15, 2017. The 8.75% 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 7.0% Senior Notes.

The 8.75% Senior Notes will become redeemable at the Company's option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, the Company may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, the Company may redeem the notes at a redemption price equal to 100.000% of the principal amount plus a specified "make-whole" premium.

The 8.75% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 7.0% Senior Notes. The 8.75% 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 covenants and has complied with all covenants since issuance.

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Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

Lease Financing Obligation Due 2020

The Company has a lease financing obligation with a balance of $2.4 million as of September 30, 2017 resulting from the Company's sale and subsequent lease back of certain compressors and related facilities owned by the Company (the "Lease Financing Obligation"). 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 12 for a discussion of aggregate minimum future lease payments.

6. Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the nine months ended September 30, 2017 is as follows (in thousands):

As of December 31, 2016	$	11,238
Liabilities incurred (1)	10,379
Liabilities settled	(814		)
Disposition of properties	(6		)
Accretion expense	765
Revisions to estimate	894
As of September 30, 2017	$	22,456
Less: liabilities associated with assets held for sale	4,856
Less: current asset retirement obligations	1,829
Long-term asset retirement obligations	$	15,771

(1) Includes $8.7 million associated with properties acquired in the DJ Basin during the nine months ended September 30, 2017. See Note 4 for additional information regarding this acquisition.

7. Fair Value Measurements

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 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. 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 2 – Quoted prices are available in active markets for similar assets or liabilities and in non-active markets for identical or similar instruments. Model-derived valuations have inputs that are observable or whose significant value drivers are observable. 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.

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

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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 assets and liabilities that were measured at fair value in the Unaudited Consolidated Balance Sheets.

	As of September 30, 2017
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Cash equivalents (1)	$	110,772	$	—	$	—	$	110,772
Deferred compensation plan (1)	1,719		—		—		1,719
Commodity derivatives (1)	—		8,211		—		8,211
Unproved oil and gas properties (2)	—		—		1,088		1,088
Liabilities
Commodity derivatives (1)	$	—	$	2,466	$	—	$	2,466

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2) This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.

	As of December 31, 2016
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Cash equivalents (1)	$	40,115	$	—	$	—	$	40,115
Deferred compensation plan (1)	1,447		—		—		1,447
Commodity derivatives (1)	—		13,156		—		13,156
Liabilities
Commodity derivatives (1)	$	—	$	10,003	$	—	$	10,003

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Cash equivalents – The highly liquid cash equivalents are recorded at carrying value. Carrying value approximates fair value, which represents a Level 1 input.

Deferred compensation plan – 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 deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Commodity derivatives – 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. The inputs discussed above all represent Level 2 inputs.

The commodity derivatives 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.

Oil and gas properties –Oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. If an impairment is necessary, the fair value is estimated by using

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either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future revenues. The present value, net of estimated operating and development costs, is calculated 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, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. During the nine months ended September 30, 2017, the Company reduced its unproved Cottonwood Gulch assets in the Piceance Basin to a fair value of $1.1 million, resulting in a non-cash impairment charge of $8.0 million. During the year ended December 31, 2016, no properties were measured at fair value.

Properties classified as held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The fair value of the assets held for sale as of September 30, 2017 was in excess of the net carrying value, therefore, no impairment was necessary. See Note 4 for additional information on assets held for sale.

Acquisitions of proved and unproved properties – Assets acquired and liabilities assumed under transactions that meet the criteria of a business combination under ASC Topic 805, Business Combinations are recorded at fair value on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of reserves, production rates, future operating and development costs, future commodity prices including price differentials, future cash flows and a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

Assets acquired and liabilities assumed under transactions that do not meet the criteria of a business combination under ASC Topic 805, Business Combinations are accounted for as asset acquisitions and are recorded based on the fair value of the total consideration transferred on the acquisition date using the lowest observable inputs available. The Company acquired proved and unproved properties in the DJ Basin for total cash consideration of $11.6 million during the nine months ended September 30, 2017. See Note 4 for additional information regarding this asset acquisition.

Long-term Debt – Long-term debt is not presented at fair value on the Unaudited Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The Company issued the 8.75% Senior Notes on April 28, 2017 and redeemed its 7.625% Senior Notes on May 30, 2017. The fair values of the Company's fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $653.1 million as of September 30, 2017. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $699.0 million as of December 31, 2016. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility or Lease Financing Obligation and there was no such market for the Convertible Notes when they were outstanding. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company's borrowing base utilization. The Amended Credit Facility had a balance of zero as of September 30, 2017 and December 31, 2016. The Convertible Notes were redeemed on May 30, 2017 and had a fair value of $0.5 million as of December 31, 2016. The Lease Financing Obligation fair values of $2.3 million and $2.6 million as of September 30, 2017 and December 31, 2016, 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.

8. Derivative Instruments

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

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

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All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair value and included in the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts, of all derivative instruments presented in the Unaudited Consolidated Balance Sheets as of the dates indicated.

	As of September 30, 2017
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	7,608		$	(1,826	)	(1)	$	5,782
Deferred financing costs and other noncurrent assets	603			(482		)	(1)	121
Total derivative assets	$	8,211		$	(2,308	)		$	5,903
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(1,826	)	$	1,826		(1)	$	—
Derivatives and other noncurrent liabilities	(640		)	482			(1)	(158		)
Total derivative liabilities	$	(2,466	)	$	2,308			$	(158	)
	As of December 31, 2016
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	13,156		$	(4,758	)	(1)	$	8,398
Deferred financing costs and other noncurrent assets	—			—				—
Total derivative assets	$	13,156		$	(4,758	)		$	8,398
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(9,104	)	$	4,758		(1)	$	(4,346	)
Derivatives and other noncurrent liabilities	(899		)	—				(899		)
Total derivative liabilities	$	(10,003	)	$	4,758			$	(5,245	)

(1) Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.

As of September 30, 2017, the Company had financial derivative instruments in place related to the sale of a portion of the Company's production for the following volumes for the periods indicated:

	October – December 2017			For the year 2018			For the year 2019
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	747,500	$	57.69	2,506,750	$	52.47	547,500	$	50.38
Natural Gas (MMbtu)	920,000	$	2.96	1,825,000	$	2.68	—	$	—

The Company's derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments 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 six different counterparties as of

19

September 30, 2017. 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 ongoing 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 these counterparties.

It is the Company's policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility or affiliates of lenders in the Amended Credit Facility. The Company's derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement 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, the Company may not be able to set-off amounts owed by it under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.

9. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the three and nine months ended September 30, 2017 and 2016, the Company had no uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and nine months ended September 30, 2017 and 2016.

Income tax benefit for the three and nine months ended September 30, 2017 and 2016 differs from the amounts that would be provided by applying the U.S. statutory income tax rates to pretax income or loss principally due to the effect of deferred tax asset valuation allowances, stock-based compensation, political lobbying expense, political contributions, nondeductible officer compensation and state income taxes. For the three and nine months ended September 30, 2017 and 2016, the effective tax rate remained at zero as a result of recording a full valuation allowance against the deferred tax asset balance. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgement is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration.

10. Stockholders' Equity

Common and Preferred Stock. The Company's authorized capital structure consists of 75,000,000 shares of preferred stock, par value of $0.001 per share, and 300,000,000 shares of common stock, par value of $0.001 per share. At the annual meeting on May 16, 2017, a proposal to increase the number of authorized shares of common stock from 150,000,000 to 300,000,000 was approved. There are no issued and outstanding shares of preferred stock.

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 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 September 30, 2017, and the date of this filing, no shares have been sold pursuant to the Agreement.

20

On June 3, 2016, the Company issued 10,000,000 shares of common stock pursuant to a debt exchange with a holder of the Company's 7.625% Senior Notes. The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the Company’s common stock.

11. 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). Cash-based compensation is measured at fair value at each reporting date and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

The following table presents the long-term cash and equity incentive compensation related to awards for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
	(in thousands)
Common stock options (1)	$	—	$	—	$	—		$	69
Nonvested common stock (1)	1,434		1,458		4,437			5,273
Nonvested common stock units (1)	174		165		516			711
Nonvested performance-based shares (1)	—		275		558			1,510
Nonvested performance cash units (2)(3)	1,073		242		(27		)	1,088
Total	$	2,681	$	2,140	$	5,484		$	8,651

(1) Unrecognized compensation cost as of September 30, 2017 was $6.8 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.7 years.

(2) The nonvested performance-based cash units are accounted for as liability awards with $1.1 million in accounts payable and accrued liabilities as of September 30, 2017 and $2.1 million and $2.9 million in derivatives and other noncurrent liabilities as of September 30, 2017 and December 31, 2016, respectively, in the Unaudited Consolidated Balance Sheets.

(3) Liability awards are fair valued at each reporting date. For the three months ended September 30, 2017, the weighted average fair value share price increased from $3.41 as of June 30, 2017 to $4.29 as of September 30, 2017. For the nine months ended September 30, 2017, the weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $4.29 as of September 30, 2017.

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

21

	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Equity Awards	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	5,267	$	3.31	—	$	—
Nonvested common stock units	3,787	$	4.29	2,922	$	5.56
Total granted	9,054			2,922
	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Cash Awards	Number of Units	Fair Value Per Unit		Number of Units	Fair Value Per Unit
Nonvested performance cash units	5,267	$	4.29	—	$	—
	Nine Months Ended September 30, 2017			Nine Months Ended September 30, 2016
Equity Awards	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	782,511	$	5.99	686,500	$	5.11
Nonvested common stock units	190,711	$	3.53	96,650	$	7.02
Total granted	973,222			783,150
	Nine Months Ended September 30, 2017			Nine Months Ended September 30, 2016
Cash Awards	Number of Units	Fair Value Per Unit		Number of Units	Fair Value Per Unit
Nonvested performance cash units	663,425	$	4.29	646,572	$	5.56

Performance Cash Program

2017 Program. In February 2017, the Compensation Committee approved a performance cash program (the "2017 Program") granting performance cash units that will settle in cash. The performance-based awards contingently vest in February 2020, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three-year period ending December 31, 2019, will be the Company's total shareholder return ("TSR") based on a matrix measurement of (1) the Company's absolute performance and (2) the Company's ranking relative to a defined peer group's individual TSRs ("Relative TSR"). The Company's absolute performance is measured against the December 30, 2016 closing share price of $6.99. If the Company's absolute performance is lower than the $6.99 share price, the payout is zero for this portion. If the Company's absolute performance is greater than the $6.99 share price, the performance cash units will vest 1% for each 1% in growth, up to 100% of the original grant. If the Company's Relative TSR is less than the median, the payout is zero for this portion. If the Company's Relative TSR is above the median, the payout is equal to twice the Company's percentile rank above the median, up to 100% of the original grant. The Company's combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant. A total of 663,425 units were granted under this program during the nine months ended September 30, 2017.

12. Commitments and Contingencies

Lease Financing Obligation. The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below. The Lease Financing Obligation contains an early buyout option pursuant to which the Company may purchase the equipment for $1.8 million on February 10, 2019.

	As of September 30, 2017
	(in thousands)
2017	$	135
2018	537
2019	1,824
Total	$	2,496

22

Transportation Charges. The Company is party to two firm transportation contracts, through July 2021, to provide capacity on natural gas pipeline systems. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 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 September 30, 2017
	(in thousands)
2017	$	4,634
2018	18,691
2019	18,691
2020	18,691
2021	10,902
Thereafter	—
Total	$	71,609

Lease and Other Commitments. The Company leases office space, vehicles and certain office equipment. In addition, the Company has various long-term agreements for telecommunication services. Future minimum annual payments under lease and other agreements are as follows:

	As of September 30, 2017
	(in thousands)
2017	$	951
2018	3,038
2019	1,070
2020	113
2021	6
Thereafter	—
Total	$	5,178

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.

13. Guarantor Subsidiaries

In addition to the Amended Credit Facility, the 7.0% Senior Notes and 8.75% Senior Notes, which have been registered under the Securities Act of 1933, are jointly and severally guaranteed on a full and unconditional basis by the Company's 100% owned subsidiaries ("Guarantor Subsidiaries"). Presented below are the Company's condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) and statements of cash flows, as required by Securities and Exchange Commission ("SEC") Rule 3-10 of Regulation S-X.

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

23

	As of September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	155,885		$	—		$	—		$	155,885
Accounts receivable, net of allowance for doubtful accounts	41,935			154			—			42,089
Other current assets	153,544			—			—			153,544
Property and equipment, net	970,444			5,401			—			975,845
Intercompany receivable	20,304			—			(20,304		)	—
Investment in subsidiaries	(14,811		)	—			14,811			—
Noncurrent assets	3,143			—			—			3,143
Total assets	$	1,330,444		$	5,555		$	(5,493	)	$	1,330,506
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	$	85,678		$	—		$	—		$	85,678
Other current liabilities	40,689			—			—			40,689
Intercompany payable	—			20,304			(20,304		)	—
Long-term debt	668,744			—			—			668,744
Other noncurrent liabilities	20,319			62			—			20,381
Stockholders' equity	515,014			(14,811		)	14,811			515,014
Total liabilities and stockholders' equity	$	1,330,444		$	5,555		$	(5,493	)	$	1,330,506

	As of December 31, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	275,841		$	—		$	—		$	275,841
Accounts receivable, net of allowance for doubtful accounts	32,659			178			—			32,837
Other current assets	9,774			—			—			9,774
Property and equipment, net	1,056,343			5,806			—			1,062,149
Intercompany receivable	20,678			—			(20,678		)	—
Investment in subsidiaries	(14,751		)	—			14,751			—
Noncurrent assets	4,740			—			—			4,740
Total assets	$	1,385,284		$	5,984		$	(5,927	)	$	1,385,341
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	$	49,447		$	—		$	—		$	49,447
Other current liabilities	35,571			—			—			35,571
Intercompany payable	—			20,678			(20,678		)	—
Long-term debt	711,808			—			—			711,808
Other noncurrent liabilities	16,915			57			—			16,972
Stockholders' equity	571,543			(14,751		)	14,751			571,543
Total liabilities and stockholders' equity	$	1,385,284		$	5,984		$	(5,927	)	$	1,385,341

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Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	67,697		$	168		$	—		$	67,865
Operating expenses	(58,053		)	(156		)	—			(58,209		)
General and administrative	(12,496		)	—			—			(12,496		)
Interest expense	(13,926		)	—			—			(13,926		)
Interest income and other income (expense)	(12,076		)	—			—			(12,076		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(28,854		)	12			—			(28,842		)
(Provision for) Benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	12			—			(12		)	—
Net income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	169,041		$	426		$	—		$	169,467
Operating expenses	(167,363		)	(486		)	—			(167,849		)
General and administrative	(30,788		)	—			—			(30,788		)
Interest expense	(44,014		)	—			—			(44,014		)
Interest income and other income (expense)	12,780			—			—			12,780
Income (loss) before income taxes and equity in earnings of subsidiaries	(60,344		)	(60		)	—			(60,404		)
(Provision for) benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	(60		)	—			60			—
Net income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)

25

	Three Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	50,325		$	156		$	—		$	50,481
Operating expenses	(59,498		)	(155		)	—			(59,653		)
General and administrative	(9,178		)	—			—			(9,178		)
Interest expense	(13,991		)	—			—			(13,991		)
Interest and other income (expense)	6,155			—			—			6,155
Income (loss) before income taxes and equity in earnings of subsidiaries	(26,187		)	1			—			(26,186		)
(Provision for) Benefit from income taxes	—			—			—			—
Equity in earnings of subsidiaries	1			—			(1		)	—
Net income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	126,730		$	469		$	—		$	127,199
Operating expenses	(172,759		)	(480		)	—			(173,239		)
General and administrative	(31,535		)	—			—			(31,535		)
Interest expense	(45,160		)	—			—			(45,160		)
Interest and other income (expense)	1,634			—			—			1,634
Income (loss) before income taxes and equity in earnings of subsidiaries	(121,090		)	(11		)	—			(121,101		)
(Provision for) benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	(11		)	—			11			—
Net income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)

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	Three Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	95,009		$	374		$	—		$	95,383
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(160,788		)	—			—			(160,788		)
Additions to furniture, fixtures and other	(268		)	—			—			(268		)
Proceeds from sale of properties and other investing activities	(712		)	—			—			(712		)
Intercompany transfers	374			—			(374		)	—
Cash flows from financing activities:
Proceeds from debt	275,000			—			—			275,000
Principal payments on debt	(322,228		)	—			—			(322,228		)
Proceeds from sale of common stock, net of offering costs	(298		)	—			—			(298		)
Intercompany transfers	—			(374		)	374			—
Other financing activities	(6,045		)	—			—			(6,045		)
Change in cash and cash equivalents	(119,956		)	—			—			(119,956		)
Beginning cash and cash equivalents	275,841			—			—			275,841
Ending cash and cash equivalents	$	155,885		$	—		$	—		$	155,885

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	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	115,695		$	512		$	—		$	116,207
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(93,686		)	(18		)	—			(93,704		)
Additions to furniture, fixtures and other	(1,184		)	—			—			(1,184		)
Proceeds from sale of properties and other investing activities	25,571			—			—			25,571
Intercompany transfers	494			—			(494		)	—
Cash flows from financing activities:
Principal payments on debt	(329		)	—			—			(329		)
Intercompany transfers	—			(494		)	494			—
Other financing activities	(1,134		)	—			—			(1,134		)
Change in cash and cash equivalents	45,427			—			—			45,427
Beginning cash and cash equivalents	128,836			—			—			128,836
Ending cash and cash equivalents	$	174,263		$	—		$	—		$	174,263

28

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 future plans, estimates, beliefs and expected performance of Bill Barrett Corporation (the "Company", "we", "us" or "our"). 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;

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

• reduction of proved undeveloped reserves due to failure to develop within the five-year development window defined by the Securities and Exchange Commission;

• derivative and hedging activities;

• legislative, judicial or regulatory changes including initiatives to impose standard setbacks from occupied structures and other sensitive areas, initiatives to give local governmental authorities the ability to further regulate or to ban oil and gas development activities within their boundaries, and 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;

• possible inability to complete planned dispositions;

• 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 and availability of capital;

• 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;

• changes in estimates of proved reserves;

• the potential for production decline rates from our wells, or drilling and related costs, 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 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, 2016 under the headings "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" 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 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

29

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. In December 2016, we completed an additional public offering of our common stock, selling 15,525,000 shares at a price of $7.40 per share. The sale included the full exercise by the underwriters of their option to purchase 2,025,000 shares of common stock.

On April 28, 2017, we issued $275.0 million in aggregate principal amount of 8.75% senior unsecured notes due 2025, at par. We used the net proceeds from the offering, together with available cash on hand, to fund the redemption and repurchase of all of our outstanding 7.625% Senior Notes due 2019 and all of our outstanding 5% Convertible Senior Notes due 2028.

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, other indebtedness, sales of properties, and/or the issuance of 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.

As a result of acquisitions and dispositions of properties, 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 necessarily indicative of future results.

Commodity prices are inherently volatile and are influenced by many factors outside of our control. As of October 17, 2017, we have hedged 747,500 barrels of oil and 920,000 MMbtu of natural gas, or approximately 43% of our expected remaining 2017 production, 2,552,000 barrels of oil and 1,825,000 MMbtu of natural gas for 2018 and 547,500 barrels of oil for 2019 at price levels that provide some economic certainty to our cash flows. We focus our efforts on increasing oil, natural gas and NGLs reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.

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.

30

Results of Operations

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

Three Months Ended September 30, 2017 Compared with Three Months Ended September 30, 2016

	Three Months Ended September 30,					Increase (Decrease)
	2017			2016		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	67,175		$	50,133	$	17,042		34	%
Other operating revenues	690			348		342			98	%
Total operating revenues	67,865			50,481		17,384			34	%
Operating Expenses
Lease operating expense	5,919			4,795		1,124			23	%
Gathering, transportation and processing expense	620			472		148			31	%
Production tax expense	5,384			3,832		1,552			41	%
Exploration expense	18			16		2			13	%
Impairment, dry hole costs and abandonment expense	261			974		(713		)	(73	)%
(Gain) loss on sale of properties	—			1,914		(1,914		)	*nm
Depreciation, depletion and amortization	41,732			43,083		(1,351		)	(3	)%
Unused commitments	4,557			4,567		(10		)	—	%
General and administrative expense (1)	12,496			9,178		3,318			36	%
Other operating expense, net	(282		)	—		(282		)	*nm
Total operating expenses	$	70,705		$	68,831	$	1,874		3	%
Production Data:
Oil (MBbls)	1,202			1,016		186			18	%
Natural gas (MMcf)	2,274			1,734		540			31	%
NGLs (MBbls)	339			261		78			30	%
Combined volumes (MBoe)	1,920			1,566		354			23	%
Daily combined volumes (Boe/d)	20,870			17,022		3,848			23	%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	46.08		$	41.92	$	4.16		10	%
Natural gas (per Mcf)	2.37			2.29		0.08			3	%
NGLs (per Bbl)	18.93			13.65		5.28			39	%
Combined (per Boe)	34.99			32.02		2.97			9	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	51.86		$	61.30	$	(9.44	)	(15	)%
Natural gas (per Mcf)	2.51			2.71		(0.20		)	(7	)%
NGLs (per Bbl)	18.93			13.65		5.28			39	%
Combined (per Boe)	38.78			45.06		(6.28		)	(14	)%
Average Costs (per Boe):
Lease operating expense	$	3.08		$	3.06	$	0.02		1	%
Gathering, transportation and processing expense	0.32			0.30		0.02			7	%
Production tax expense	2.80			2.45		0.35			14	%
Depreciation, depletion and amortization (2)	22.52			27.51		(4.99		)	(18	)%
General and administrative expense (1)	6.51			5.86		0.65			11	%

* Not meaningful.

31

(1) Included in general and administrative expense is long-term cash and equity incentive compensation of $2.7 million (or $1.40 per Boe) and $2.1 million (or $1.37 per Boe) for the three months ended September 30, 2017 and 2016, respectively.

(2) The DD&A rate per Boe excludes production of 67 MBoe associated with our properties that were classified as held for sale in the Uinta Basin, as these were not depleted the month of September 30, 2017.

Production Revenues and Volumes. Production revenues increased to $67.2 million for the three months ended September 30, 2017 from $50.1 million for the three months ended September 30, 2016. The increase in production revenues was due to a 23% increase in production volumes and a 9% increase in average realized prices before hedging. The increase in production volumes increased production revenues by approximately $12.4 million, while the increase in average realized prices before hedging increased production revenues by approximately $4.7 million.

The 23% increase in total production from the three months ended September 30, 2016 to the three months ended September 30, 2017 was primarily due to a 27% increase in production from the DJ Basin, offset by a 5% decrease in production from the Uinta Oil Program. Additional information concerning production is in the following table:

	Three Months Ended September 30, 2017				Three Months Ended September 30, 2016				% 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	1,005	335	2,178	1,703	827	252	1,554	1,338	22	%	33	%	40	%	27	%
Uinta Oil Program	195	4	96	215	188	9	174	226	4	%	(56	)%	(45	)%	(5	)%
Other	2	—	—	2	1	—	6	2	100	%	*nm		*nm		—	%
Total	1,202	339	2,274	1,920	1,016	261	1,734	1,566	18	%	30	%	31	%	23	%

* Not meaningful.

Lease Operating Expense ("LOE"). LOE remained consistent at $3.08 per Boe for the three months ended September 30, 2017 compared to $3.06 per Boe for the three months ended September 30, 2016.

Production Tax Expense. Total production taxes increased to $5.4 million for the three months ended September 30, 2017 from $3.8 million for the three months ended September 30, 2016. The increase is attributable to the 23% increase in production and the 9% increase in averaged 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 8.0% and 7.6% for the three months ended September 30, 2017 and September 30, 2016, 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 September 30, 2017 and 2016 is summarized below:

	Three Months Ended September 30,
	2017		2016
	(in thousands)
Dry hole expense	$	—	$	1
Abandonment expense and lease expirations	261		973
Total impairment, dry hole costs and abandonment expense	$	261	$	974

We review our oil and natural gas properties 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. We estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future

32

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 oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, 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.

Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

During the three months ended September 30, 2017, we committed to a plan to sell our remaining assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2017. We utilized the income valuation technique to determine that the fair value of the assets held for sale was in excess of the asset carrying value as of September 30, 2017.

Unproved oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.

Given current and projected 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. 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.

Our current recoverability test on our existing oil and gas properties as of September 30, 2017 uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of September 30, 2017 results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.

Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $41.7 million for the three months ended September 30, 2017 compared with $43.1 million for the three months ended September 30, 2016. The decrease of $1.4 million was a result of an 18%decrease in the DD&A rate, offset by a 23% increase in production volumes for the three months ended September 30, 2017 compared with the three months ended September 30, 2016. The decrease in the DD&A rate accounted for an $11.1 million decrease in DD&A expense, while the increase in production accounted for a $9.7 million increase in DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended September 30, 2017, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $22.52 per Boe compared with $27.51 per Boe for the three months ended September 30, 2016.

33

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 the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021. Unused commitments expense for each of the three months ended September 30, 2017 and September 30, 2016 consisted of $4.6 million related to these contracts.

General and Administrative Expense. General and administrative expense increased to $12.5 million for the three months ended September 30, 2017 from $9.2 million for the three months ended September 30, 2016 primarily due to an increase in variable employee compensation related to performance, legal and professional services fees.

Included in general and administrative expense is long-term cash and equity incentive compensation of $2.7 million and $2.1 million for the three months ended September 30, 2017 and 2016, respectively. The components of long-term cash and equity incentive compensation for the three months ended September 30, 2017 and 2016 are shown in the following table:

	Three Months Ended September 30,
	2017		2016
	(in thousands)
Stock options and nonvested common stock	$	1,434	$	1,733
Nonvested common stock units	174		165
Performance cash units (1)	1,073		242
Total	$	2,681	$	2,140

(1) The performance cash units will be settled in cash for the performance metrics that are met.

Commodity Derivative Gain (Loss).Commodity derivative gain (loss) was a loss of $12.4 million for the three months ended September 30, 2017 compared with a gain of $6.1 million for the three months ended September 30, 2016. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of September 30, 2017 and 2016 or during the periods then ended.

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

	Three Months Ended September 30,
	2017			2016
	(in thousands)
Realized gain (loss) on derivatives (1)	$	7,263		$	20,412
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	(1,036		)	(21,706		)
Unrealized gain (loss) on derivatives (1)	(18,635		)	7,348
Total commodity derivative gain (loss)	$	(12,408	)	$	6,054

(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.

During the three months ended September 30, 2017, approximately 55% of our oil volumes and 39% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $6.9 million and natural gas income of $0.3 million after settlements for all commodity derivatives. During the three months ended September 30, 2016, approximately 66% of our oil volumes and 27% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $19.7 million and natural gas income of $0.7 million after settlements for all commodity derivatives.

34

Income Tax (Expense) Benefit. We recorded an additional valuation allowance of $10.9 million and $10.0 million for the three months ended September 30, 2017 and 2016, respectively, against our deferred tax asset balance, which reduced our effective tax rate to zero. In regard to the valuation allowance recorded against our deferred tax asset balance we considered all available evidence in assessing the need for a valuation allowance. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the 2017 and 2016 periods, our effective tax rate differs from the federal statutory rate as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as the effect of state income taxes.

35

Nine Months Ended September 30, 2017 Compared with Nine Months Ended September 30, 2016

	Nine Months Ended September 30,					Increase (Decrease)
	2017			2016		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	168,541		$	126,279	$	42,262		33	%
Other operating revenues	926			920		6			1	%
Total operating revenues	169,467			127,199		42,268			33	%
Operating Expenses
Lease operating expense	17,287			22,101		(4,814		)	(22	)%
Gathering, transportation and processing expense	1,644			1,871		(227		)	(12	)%
Production tax expense	9,140			7,037		2,103			30	%
Exploration expense	48			64		(16		)	(25	)%
Impairment, dry hole costs and abandonment expense	8,336			1,766		6,570			*nm
(Gain) loss on sale of properties	(92		)	1,206		(1,298		)	108	%
Depreciation, depletion and amortization	119,409			125,491		(6,082		)	(5	)%
Unused commitments	13,687			13,703		(16		)	—	%
General and administrative expense (1)	30,788			31,535		(747		)	(2	)%
Other operating expenses, net	(1,610		)	—		(1,610		)	*nm
Total operating expenses	$	198,637		$	204,774	$	(6,137	)	(3	)%
Production Data:
Oil (MBbls)	2,929			2,925		4			—	%
Natural gas (MMcf)	6,084			5,298		786			15	%
NGLs (MBbls)	936			732		204			28	%
Combined volumes (MBoe)	4,879			4,540		339			7	%
Daily combined volumes (Boe/d)	17,872			16,569		1,303			7	%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	46.52		$	36.88	$	9.64		26	%
Natural gas (per Mcf)	2.48			1.81		0.67			37	%
NGLs (per Bbl)	18.40			12.05		6.35			53	%
Combined (per Boe)	34.54			27.82		6.72			24	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	52.18		$	62.74	$	(10.56	)	(17	)%
Natural gas (per Mcf)	2.56			2.34		0.22			9	%
NGLs (per Bbl)	18.40			12.05		6.35			53	%
Combined (per Boe)	38.04			45.09		(7.05		)	(16	)%
Average Costs (per Boe):
Lease operating expense	$	3.54		$	4.87	$	(1.33	)	(27	)%
Gathering, transportation and processing expense	0.34			0.41		(0.07		)	(17	)%
Production tax expense	1.87			1.55		0.32			21	%
Depreciation, depletion and amortization (2)	24.81			27.64		(2.83		)	(10	)%
General and administrative expense (1)	6.31			6.95		(0.64		)	(9	)%

* Not meaningful.

(1) Included in general and administrative expense is long-term cash and equity incentive compensation of $5.5 million (or $1.12 per Boe) and $8.7 million (or $1.91 per Boe) for the nine months ended September 30, 2017 and 2016, respectively.

(2) The DD&A rate per Boe excludes production of 67 MBoe associated with our properties that were classified as held for sale in the Uinta Basin, as these were not depleted the month of September 30, 2017.

36

Production Revenues and Volumes. Production revenues increased to $168.5 million for the nine months ended September 30, 2017 from $126.3 million for the nine months ended September 30, 2016. The increase in production revenues was due to a 24% increase in average realized prices before hedging and a 7%increase in production volumes. The increase in average realized prices before hedging increased production revenues by approximately $30.5 million, while the increase in production volumes increased production revenues by approximately $11.7 million.

The 7%increase in total production from the nine months ended September 30, 2016 to the nine months ended September 30, 2017 was primarily due to a 16% increase in the DJ Basin as a result of new wells placed into production, offset by a 31% decrease in production from the Uinta Oil Program primarily due to the sale of certain non-core Uinta Oil Program assets during July 2016. Additional information concerning production is set forth in the following table:

	Nine Months Ended September 30, 2017				Nine Months Ended September 30, 2016				% 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	2,399	927	5,814	4,295	2,247	693	4,500	3,690	7	%	34	%	29	%	16	%
Uinta Oil Program	526	9	258	578	674	37	762	838	(22	)%	(76	)%	(66	)%	(31	)%
Other	4	—	12	6	4	2	36	12	—	%	*nm		(67	)%	(50	)%
Total	2,929	936	6,084	4,879	2,925	732	5,298	4,540	—	%	28	%	15	%	7	%

* Not meaningful.

Lease Operating Expense. LOE decreased to $3.54 per Boe for the nine months ended September 30, 2017 from $4.87 per Boe for the nine months ended September 30, 2016. The decrease per Boe for the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 is primarily related to operational efficiencies and sales of certain non-core assets in the Uinta Oil Program during July 2016, which had relatively high LOE costs on a per Boe basis.

Production Tax Expense. Total production taxes increased to $9.1 million for the nine months ended September 30, 2017 from $7.0 million for the nine months ended September 30, 2016. The increase is attributable to the 24% increase in average realized prices before hedging and the 7% increase in production. Production tax expense for both periods included an annual true-up of Colorado ad valorem tax based on actual assessments and a true-up of the Colorado severance tax. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Excluding the ad valorem and severance tax adjustments, production taxes as a percentage of oil, natural gas and NGL sales were 7.2% and 7.3% for the nine months ended September 30, 2017 and September 30, 2016, 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 nine months ended September 30, 2017 and 2016 are summarized below:

	Nine Months Ended September 30,
	2017		2016
	(in thousands)
Impairment of unproved oil and gas properties (1)	$	8,010	$	183
Dry hole expense	—		71
Abandonment expense and lease expirations	326		1,512
Total impairment, dry hole costs and abandonment expense	$	8,336	$	1,766

(1) We recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the nine months ended September 30, 2017. We have no current plan to develop this acreage.

37

We review our oil and natural gas properties 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. We estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare 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 oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, 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.

Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

During the three months ended September 30, 2017, we committed to a plan to sell our remaining assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2017. We utilized the income valuation technique to determine that the fair value of the assets held for sale was in excess of the asset carrying value as of September 30, 2017.

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, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.

Given current and projected 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. 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.

Our current recoverability test on our existing oil and gas properties as of September 30, 2017 uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of September 30, 2017 results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.

Depreciation, Depletion and Amortization. DD&A decreased to $119.4 million for the nine months ended September 30, 2017 compared with $125.5 million for the nine months ended September 30, 2016. The decrease of $6.1 million was a result of a 10%decrease in the DD&A rate, offset by a 7%increase in production for the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016. The decrease in the DD&A rate accounted for a $15.5 million decrease in DD&A expense, while the increase in production accounted for a $9.4 million increase in DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the nine months ended September 30, 2017, the relationship of capital expenditures, proved reserves and production from

38

certain producing fields yielded a depletion rate of $24.81 per Boe compared with $27.64 per Boe for the nine months ended September 30, 2016.

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 the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021. Unused commitments expense for each of the nine months ended September 30, 2017 and 2016 consisted of $13.7 million related to these contracts.

General and Administrative Expense. General and administrative expense decreased to $30.8 million for the nine months ended September 30, 2017 from $31.5 million for the nine months ended September 30, 2016 primarily due to a decrease in long-term cash and equity compensation discussed below, offset by an increase in variable employee compensation related to performance, legal and professional services fees.

Included in general and administrative expense is long-term cash and equity incentive compensation of $5.5 million and $8.7 million for the nine months ended September 30, 2017 and 2016, respectively. The components of long-term cash and equity incentive compensation for the nine months ended September 30, 2017 and 2016 are shown in the following table:

	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Stock options and nonvested common stock	$	4,995		$	6,852
Nonvested common stock units	516			711
Performance cash units (1)(2)	(27		)	1,088
Total	$	5,484		$	8,651

(1) The performance cash units will be settled in cash for the performance metrics that are met.

(2) The performance cash units are accounted for as liability awards and fair valued at each reporting date. The weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $4.29 as of September 30, 2017.

Commodity Derivative Gain (Loss).Commodity derivative gain (loss) was a gain of $19.7 million for the nine months ended September 30, 2017 compared with a loss of $7.3 million for the nine months ended September 30, 2016. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of September 30, 2017 and 2016 and during the periods then ended.

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

	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Realized gain (loss) on derivatives (1)	$	17,062		$	78,417
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	(2,114		)	(79,055		)
Unrealized gain (loss) on derivatives (1)	4,706			(6,620		)
Total commodity derivative gain (loss)	$	19,654		$	(7,258	)

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

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During the nine months ended September 30, 2017, approximately 63% of our oil volumes and 43% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $16.6 million and natural gas income of $0.5 million after settlements for all commodity derivatives. During the nine months ended September 30, 2016, approximately 68% of our oil volumes and 25% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $75.6 million and natural gas income of $2.8 million after settlements for all commodity derivatives.

Income Tax (Expense) Benefit. We recorded an additional valuation allowance of $22.9 million and $45.8 million for the nine months ended September 30, 2017 and 2016, respectively, against our deferred tax asset balance, which reduced our effective tax rate to zero. We consider all available evidence in assessing the need for recording a valuation allowance. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforward, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the nine months ended September 30, 2017 and 2016, our effective tax rate before valuation allowance differs from the federal statutory rate because of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as state income tax expense.

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, 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, fund planned capital expenditure activities and ensure adequate 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 2017 and 2018. However, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions, such as additional property dispositions, if we believe conditions to be favorable. During the three months ended September 30, 2017,

we committed to a plan to sell our remaining assets in the Uinta Basin. The proceeds from a sale of the Uinta Basin properties will be used to fund a portion of our 2018 capital expenditures. However, the closing of such a sale, the timing of closing and the proceeds to us are uncertain.

At September 30, 2017, we had cash and cash equivalents of $155.9 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2016, we had cash and cash equivalents of $275.8 million and no amounts outstanding under our Amended Credit Facility. In October 2017, our borrowing base was re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at June 30, 2017. Our effective borrowing capacity is reduced by $26.0 million to $274.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement. The borrowing base is dependent on our proved reserves and hedge position and is calculated using future commodity pricing provided by our lenders, and may be adjusted in the future at the sole discretion of the lenders.

Cash Flow from Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2017 and 2016 was $95.4 million and $116.2 million, respectively. The decrease in net cash provided by operating activities was primarily due to decreases in cash from derivative settlements offset by an increase in production revenues.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. 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. At September 30,

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2017, we had in place crude oil swaps covering portions of our 2017, 2018 and 2019 production and natural gas swaps covering portions of our 2017 and 2018 production.

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

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative's fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.

At September 30, 2017, the estimated fair value of all of our commodity derivative instruments, summarized in the following table, was a net asset of $5.7 million, comprised of current and noncurrent assets.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price (1)	Fair Market Value (in thousands)
Swap Contracts:
2017
Oil	747,500	Bbls	$	57.69	WTI	$	4,251
Natural gas	920,000	MMBtu	$	2.96	NWPL	216
2018
Oil	2,506,750	Bbls	$	52.47	WTI	1,471
Natural gas	1,825,000	MMBtu	$	2.68	NWPL	109
2019
Oil	547,500	Bbls	$	50.38	WTI	(302		)
Total						$	5,745

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

The following table includes all hedges entered into from October 1, 2017 to October 17, 2017:

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price
Swap Contracts:
2018
Oil	45,250	Bbls	$	52.20	WTI

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

It is our policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. 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

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counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations, if any, 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:

	Nine Months Ended September 30,
Basin/Area	2017		2016
	(in millions)
DJ	$	165.4	$	67.0
Uinta Oil Program	8.7		1.1
Other	0.4		1.4
Total	$	174.5	$	69.5

	Nine Months Ended September 30,
	2017		2016
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	20.2	$	2.5
Drilling, development, exploration and exploitation of oil and natural gas properties	150.1		60.8
Gathering and compression facilities	3.9		5.0
Furniture, fixtures and equipment	0.3		1.2
Total	$	174.5	$	69.5

Our current estimated capital expenditure budget in 2017 is $250.0 million to $270.0 million, with all drilling activities targeting oil. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures are generally discretionary and within our control. If oil, natural gas and NGL prices decline below acceptable levels or costs increase above acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. We would generally do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow.

We believe that we have sufficient available liquidity with available cash on hand, available borrowing under the Amended Credit Facility and cash flow from operations to fund our 2017 and 2018 capital expenditures. 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 cash flow from operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

Financing Activities

Amended Credit Facility. The Amended Credit Facility had commitments from 13 lenders and a borrowing base of $300.0 million as of September 30, 2017. 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 under the Amended Credit Facility as of September 30, 2017 to $274.0 million. There have not been any borrowings under the Amended Credit Facility to date in 2017 and there were no such borrowings in 2016.

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.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. In October 2017, our borrowing base was

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re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at June 30, 2017. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by our lenders, as well as any other outstanding debt. Lower commodity prices will generally result in a lower borrowing base.

The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2017 budget at current commodity prices. However, if commodity prices significantly decline, our EBITDAX, which is a critical underpinning of our required financial covenants, will be significantly reduced. If this were to occur, it may become necessary for us to negotiate an amendment to one or more of these financial covenants. In September 2015, we obtained an amendment to the Amended Credit Facility that replaced our debt-to-EBITDAX covenant in the facility with a secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that we will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

If we fail to comply with the covenants or other terms of any agreements governing our debt, including the Amended Credit Facility, our lenders and holders of our senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect our financial condition.

5% Convertible Senior Notes Due 2028. On May 30, 2017, we redeemed our $0.6 million of outstanding Convertible Notes with the proceeds of our 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes Due 2025" below for additional information.

7.625% Senior Notes Due 2019.On May 30, 2017, we redeemed our $315.3 million of outstanding 7.625% Senior Notes with cash on hand and proceeds from the issuance of our 8.75% Senior Notes on April 28, 2017. See "8.75% Senior Notes Due 2025" below for additional information.

Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, we recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the nine months ended September 30, 2017.

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 October 15, 2022 at par. The 7.0% Senior Notes mature on October 15, 2022, unless earlier redeemed or purchased by us. 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 8.75% Senior Notes. The 7.0% Senior Notes became redeemable at our option on October 15, 2017 at a redemption price of 103.500%. The redemption price will decrease to 102.333%, 101.167% and 100.000% of the principal amount in 2018, 2019 and 2020, respectively. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee the Amended Credit Facility and the 8.75% 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 covenants and have complied with all covenants since issuance.

8.75% Senior Notes Due 2025. On April 28, 2017, we issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year, commencing on December 15, 2017. The 8.75% 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 7.0% Senior Notes.

The 8.75% Senior Notes will become redeemable at our option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, we may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, we may redeem the notes at a redemption price equal to 100% of the principal amount plus a specified "make-whole" premium.

The 8.75% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility and the 7.0% Senior Notes. The 8.75% 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 covenants and have complied with all covenants since issuance.

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Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits us from repurchasing any of the notes from time to time at any price in open market purchases or negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

Lease Financing Obligation Due 2020.We have a Lease Financing Obligation with a balance of $2.4 million as of September 30, 2017 resulting from our sale and subsequent lease back of certain compressors and related facilities owned by us. The Lease Financing Obligation expires on August 10, 2020, and we have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option 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 12 to the accompanying Unaudited Consolidated Financial Statements for a discussion of aggregate minimum future lease payments.

Our outstanding debt is summarized below:

		As of September 30, 2017							As of December 31, 2016
	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	—		—			—		579		—			579
7.625% Senior Notes (2)	October 1, 2019	—		—			—		315,300		(2,169		)	313,131
7.0% Senior Notes (3)	October 15, 2022	400,000		(3,684		)	396,316		400,000		(4,227		)	395,773
8.75% Senior Notes (4)	June 15, 2025	275,000		(4,548		)	270,452		—		—			—
Lease Financing Obligation (5)	August 10, 2020	2,443		(2		)	2,441		2,782		(3		)	2,779
Total Debt		$	677,443	$	(8,234	)	$	669,209	$	718,661	$	(6,399	)	$	712,262
Less: Current Portion of Long-Term Debt (6)		465		—			465		454		—			454
Total Long-Term Debt		$	676,978	$	(8,234	)	$	668,744	$	718,207	$	(6,399	)	$	711,808

(1) The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of December 31, 2016 based on reported market trades of these instruments.

(2) The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately $314.5 million as of December 31, 2016 based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $386.3 million and $384.5 million as of September 30, 2017 and December 31, 2016, respectively, based on reported market trades of these instruments.

(4) The aggregate estimated fair value of the 8.75% Senior Notes was approximately $266.8 million as of September 30, 2017 based on reported market trades of these instruments.

(5) The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.3 million and $2.6 million as of September 30, 2017 and December 31, 2016, 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 long-term debt includes the current portion of the Lease Financing Obligation.

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 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, 7.0% Senior Notes or 8.75% 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 September 30, 2017 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 September 30, 2018		Twelve Months Ended September 30, 2019		Twelve Months Ended September 30, 2020		Twelve Months Ended September 30, 2021		Twelve Months Ended September 30, 2022		After September 30, 2022
	(in thousands)
Notes payable (1)	$	322	$	—	$	—	$	—	$	—	$	—	$	322
7.0% Senior Notes (2)	28,000		28,000		28,000		28,000		28,000		414,000		554,000
8.75% Senior Notes (3)	27,334		24,063		24,063		24,063		24,063		347,188		470,774
Lease Financing Obligation (4)	537		1,959		—		—		—		—		2,496
Office and office equipment leases and other (5)	3,157		1,739		255		27		—		—		5,178
Firm transportation and processing agreements (6)	18,652		18,691		18,691		15,575		—		—		71,609
Asset retirement obligations (7)	1,829		1,304		1,279		1,602		1,532		14,910		22,456
Derivative liability (8)	138		20		—		—		—		—		158
Total	$	79,969	$	75,776	$	72,288	$	69,267	$	53,595	$	776,098	$	1,126,993

(1) Notes payable includes interest on 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 due April 9, 2020.

(2) On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make semi-annual interest payments through maturity on October 15, 2022 equal to $14.0 million.

(3) On April 28, 2017, we issued $275.0 million aggregate principal amount of 8.75% Senior Notes. We are obligated to make semi-annual interest payments through maturity on June 15, 2025 equal to $12.0 million. See Note 5 to the accompanying financial statements for additional information.

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

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

(6) We have entered into contracts that provide firm transportation capacity on pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount of gas we deliver to the processing facility or pipeline.

(7) 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, 2016 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(8) Derivative liability represents the net fair value for oil, gas and NGL commodity derivatives presented as liabilities in our Unaudited Consolidated Balance Sheets as of September 30, 2017. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016 and in "Commodity Hedging Activities" above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of September 30, 2017.

Trends and Uncertainties

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016 for a discussion of trends and uncertainties that may affect our financial condition or liquidity. Also see "Risk Factors" in Part II of this report.

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, 2016 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.

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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. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the nine months ended September 30, 2017, our income before income taxes would have decreased by approximately $0.9 million for each $1.00 per barrel decrease in crude oil prices, approximately $0.3 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.9 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. We do not enter into any market risk sensitive instruments for trading purposes.

As of October 17, 2017, 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."

	October – December 2017			For the year 2018			For the year 2019
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	747,500	$	57.69	2,552,000	$	52.47	547,500	$	50.38
Natural Gas (MMbtu)	920,000	$	2.96	1,825,000	$	2.68	—	$	—

Commodity Price Risk - Carrying Value of Proved Oil and Gas Properties

Our current recoverability test on our existing oil and gas properties as of September 30, 2017 uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of September 30, 2017 results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of September 30, 2017, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Principal 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 Principal Financial Officer concluded that our disclosure controls and procedures are effective as of September 30, 2017.

46

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the third fiscal quarter of 2017 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, 2016. 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, 2016 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 September 30, 2017:

Period	Total Number of Shares (1)	Weighted Average Price Paid Per Share		Total Number of  Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number  (or Approximate  Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 – 31, 2017	1,557	$	3.24	—	—
August 1 – 31, 2017	2,418	3.06		—	—
September 1 – 30, 2017	1,074	3.57		—	—
Total	5,049	$	3.22	—	—

(1) Represents shares delivered by employees to satisfy tax withholding obligations resulting from the vesting of restricted shares of common stock issued pursuant to our employee incentive plans.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

47

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit Number	Description of Exhibits
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer.
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Principal 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

48

SIGNATURES

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

		BILL BARRETT CORPORATION
Date:	October 31, 2017	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President
			(Principal Executive Officer)
Date:	October 31, 2017	By:	/s/ David R. Macosko
			David R. Macosko
			Senior Vice President-Accounting
			(Principal Accounting Officer)

49

EX-31.1

Exhibit 31.1

CERTIFICATION

I, R. Scot Woodall, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Bill Barrett Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2017

/s/ R. Scot Woodall

R. Scot Woodall

Chief Executive Officer, President and Director

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, William M. Crawford, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Bill Barrett Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2017

/s/ William M. Crawford

William M. Crawford

Senior Vice President-Treasury and Finance

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

BILL BARRETT CORPORATION

SARBANES-OXLEY ACT SECTION 906 CERTIFICATION

In connection with this quarterly report on Form 10-Q of Bill Barrett Corporation for the fiscal quarter ended September 30, 2017, I, R. Scot Woodall, Chief Executive Officer and President of Bill Barrett Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. This Form 10-Q for the fiscal quarter ended September 30, 2017 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in this Form 10-Q for the fiscal quarter ended September 30, 2017 fairly presents, in all material respects, the financial condition and results of operations of Bill Barrett Corporation for the periods presented therein.

Date: October 31, 2017

/s/ R. Scot Woodall

R. Scot Woodall

Chief Executive Officer and President

(Principal Executive Officer)

EX-32.2

Exhibit 32.2

BILL BARRETT CORPORATION

SARBANES-OXLEY ACT SECTION 906 CERTIFICATION

In connection with this quarterly report on Form 10-Q of Bill Barrett Corporation for the fiscal quarter ended September 30, 2017, I, William M. Crawford, Senior Vice President - Treasury and Finance of Bill Barrett Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. This Form 10-Q for the fiscal quarter ended September 30, 2017 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in this Form 10-Q for the fiscal quarter ended September 30, 2017 fairly presents, in all material respects, the financial condition and results of operations of Bill Barrett Corporation for the periods presented therein.

Date: October 31, 2017

/s/ William M. Crawford

William M. Crawford

Senior Vice President-Treasury and Finance

(Principal Financial Officer)

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 17, 2017
Document Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Trading Symbol	BBG
Entity Registrant Name	BILL BARRETT CORPORATION
Entity Central Index Key	0001172139
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		76,283,870

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 155,885	$ 275,841
Accounts receivable, net of allowance for doubtful accounts	42,089	32,837
Derivative assets	5,782	8,398
Assets held for sale, net of depreciation, depletion, amortization and impairment	145,553	0
Prepayments and other current assets	2,209	1,376
Total current assets	351,518	318,452
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	1,292,786	1,539,373
Unproved oil and gas properties, excluded from amortization	70,535	58,830
Furniture, equipment and other	17,217	23,636
Property, plant and equipment, gross	1,380,538	1,621,839
Accumulated depreciation, depletion, amortization and impairment	(404,693)	(559,690)
Total property and equipment, net	975,845	1,062,149
Deferred income tax asset	0	1,587
Deferred financing costs and other noncurrent assets	3,143	3,153
Total	1,330,506	1,385,341
Current liabilities:
Accounts payable and accrued liabilities	85,678	49,447
Amounts payable to oil and gas property owners	12,563	6,192
Production taxes payable	22,805	22,992
Derivative liabilities	0	4,346
Deferred income taxes	0	1,587
Current portion of long-term debt	465	454
Liabilities associated with assets held for sale	4,856	0
Total current liabilities	126,367	85,018
Long-term debt, net of debt issuance costs	668,744	711,808
Asset retirement obligations	15,771	10,703
Derivatives and other noncurrent liabilities	4,610	6,269
Stockholders' equity:
Common stock, $0.001 par value; authorized 300,000,000 and 150,000,000 shares at September 30, 2017 and December 31, 2016, respectively; 76,284,992 and 75,721,360 shares issued and outstanding at September 30, 2017 and December 31, 2016, respectively, with 1,391,256 and 1,325,714 shares subject to restrictions, respectively	75	74
Additional paid-in capital	1,118,180	1,113,797
Retained earnings (accumulated deficit)	(603,241)	(542,328)
Treasury stock, at cost: zero shares at September 30, 2017 and December 31, 2016	0	0
Total stockholders' equity	515,014	571,543
Total liabilities and stockholders' equity	$ 1,330,506	$ 1,385,341

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common Stock, Par or Stated Value Per Share (in dollars per share)	$ 0.001	$ 0.001
Common Stock, Shares Authorized	300,000,000	150,000,000
Common Stock, Shares, Issued (in shares)	76,284,992	75,721,360
Common stock, shares outstanding (in shares)	76,284,992	75,721,360
Common stock, shares subject to restrictions (in shares)	1,391,256	1,325,714
Treasury stock, shares (in shares)	0	0

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating Revenues:
Oil, gas and NGL production	$ 67,175	$ 50,133	$ 168,541	$ 126,279
Other operating revenues	690	348	926	920
Total operating revenues	67,865	50,481	169,467	127,199
Operating Expenses:
Lease operating expense	5,919	4,795	17,287	22,101
Gathering, transportation and processing expense	620	472	1,644	1,871
Production tax expense	5,384	3,832	9,140	7,037
Exploration expense	18	16	48	64
Impairment, dry hole costs and abandonment expense	261	974	8,336	1,766
(Gain) loss on sale of properties	0	1,914	(92)	1,206
Depreciation, depletion and amortization	41,732	43,083	119,409	125,491
Unused commitments	4,557	4,567	13,687	13,703
General and administrative expense	12,496	9,178	30,788	31,535
Other operating expenses, net	(282)	0	(1,610)	0
Total operating expenses	70,705	68,831	198,637	204,774
Operating Income (Loss)	(2,840)	(18,350)	(29,170)	(77,575)
Other Income and Expense:
Interest and other income	332	72	1,030	166
Interest expense	(13,926)	(13,991)	(44,014)	(45,160)
Commodity derivative gain (loss)	(12,408)	6,054	19,654	(7,258)
Gain (loss) on extinguishment of debt	0	29	(7,904)	8,726
Total other income and expense	(26,002)	(7,836)	(31,234)	(43,526)
Income (Loss) before Income Taxes	(28,842)	(26,186)	(60,404)	(121,101)
(Provision for) Benefit from Income Taxes	0	0	0	0
Net Income (Loss)	$ (28,842)	$ (26,186)	$ (60,404)	$ (121,101)
Net Income (Loss) Per Common Share, Basic (in dollars per share)	$ (0.39)	$ (0.44)	$ (0.81)	$ (2.28)
Net Income (Loss) Per Common Share, Diluted (in dollars per share)	$ (0.39)	$ (0.44)	$ (0.81)	$ (2.28)
Weighted Average Common Shares Outstanding, Basic	74,886,107	58,851,598	74,742,699	53,081,809
Weighted Average Common Shares Outstanding, Diluted	74,886,107	58,851,598	74,742,699	53,081,809

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ (28,842)	$ (26,186)	$ (60,404)	$ (121,101)	$ (170,378)
Other Comprehensive Income (Loss), net of tax:
Other comprehensive income (loss)	0	0	0	0
Comprehensive Income (Loss)	$ (28,842)	$ (26,186)	$ (60,404)	$ (121,101)

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating Activities:
Net Income (Loss)	$ (60,404)	$ (121,101)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	119,409	125,491
Impairment, dry hole costs and abandonment expense	8,336	1,766
Commodity derivative (gain) loss	(19,654)	7,258
Settlements of commodity derivatives	17,062	78,417
Stock compensation and other non-cash charges	5,134	7,208
Amortization of deferred financing costs	1,665	2,075
(Gain) loss on extinguishment of debt	7,904	(8,726)
(Gain) loss on sale of properties	(92)	1,206
Change in operating assets and liabilities:
Accounts receivable	(9,252)	13,552
Prepayments and other assets	(980)	(968)
Accounts payable, accrued and other liabilities	20,071	18,903
Amounts payable to oil and gas property owners	6,371	(2,894)
Production taxes payable	(187)	(5,980)
Net cash provided by (used in) operating activities	95,383	116,207
Investing Activities:
Additions to oil and gas properties, including acquisitions	(160,788)	(93,704)
Additions of furniture, equipment and other	(268)	(1,184)
Proceeds from sale of properties and other investing activities	(712)	25,571
Net cash provided by (used in) investing activities	(161,768)	(69,317)
Financing Activities:
Proceeds from debt	275,000	0
Principal payments on debt	(322,228)	(329)
Proceeds from sale of common stock, net of offering costs	(298)	0
Deferred financing costs and other	(6,045)	(1,134)
Net cash provided by (used in) financing activities	(53,571)	(1,463)
Increase (Decrease) in Cash and Cash Equivalents	(119,956)	45,427
Beginning Cash and Cash Equivalents	275,841	128,836
Ending Cash and Cash Equivalents	$ 155,885	$ 174,263

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED) - USD ($)	Total	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Treasury Stock
Balance at Dec. 31, 2015	$ 549,416,000	$ 48,000	$ 921,318,000	$ (371,950,000)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	(1,113,000)	1,000			(1,114,000)
Stock-based compensation	9,455,000		9,455,000
Retirement of treasury stock	0		(1,114,000)		1,114,000
Exchange of senior notes for shares of common stock	74,400,000	10,000	74,390,000
Issuance of common stock, net of offering costs	109,763,000	15,000	109,748,000
Net income (loss)	(170,378,000)			(170,378,000)
Balance at Dec. 31, 2016	571,543,000	74,000	1,113,797,000	(542,328,000)	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	(1,245,000)	1,000			(1,246,000)
Stock-based compensation	5,510,000		5,510,000
Retirement of treasury stock	0		(1,246,000)		1,246,000
Issuance of common stock, net of offering costs	(61,000)	0	(61,000)
Net income (loss)	(60,404,000)			(60,404,000)
Balance at Sep. 30, 2017	515,014,000	$ 75,000	1,118,180,000	(603,241,000)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect of accounting change (1)	$ (329,000)		$ 180,000.0	$ (509,000)

XML

Organization

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

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 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.

XML

Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 consolidated 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 2016 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 2016 Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company's consolidated 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 include volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future net 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 payment awards.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of September 30, 2017			As of December 31, 2016
	(in thousands)
Accrued oil, gas and NGL sales	$	33,170		$	26,542
Due from joint interest owners	9,164			4,366
Other	14			1,952
Allowance for doubtful accounts	(259		)	(23		)
Total accounts receivable	$	42,089		$	32,837

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, recent sales prices of comparable properties 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.

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

	As of September 30, 2017			As of December 31, 2016
	(in thousands)
Proved properties	$	218,746		$	306,075
Wells and related equipment and facilities	1,035,764			1,164,354
Support equipment and facilities	34,317			63,238
Materials and supplies	3,959			5,706
Total proved oil and gas properties (1)	$	1,292,786		$	1,539,373
Unproved properties	33,713			27,790
Wells and facilities in progress	36,822			31,040
Total unproved oil and gas properties, excluded from amortization (1)	$	70,535		$	58,830
Accumulated depreciation, depletion, amortization and impairment (1)	(393,340		)	(543,154		)
Total oil and gas properties, net (1)	$	969,981		$	1,055,049

(1) Excludes oil and gas properties held for sale of $145.1 million, comprised of $410.7 million of proved oil and gas properties and $0.4 million of unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of $266.0 million. Held for sale balances are included in current assets as assets held for sale, net of amortization and impairment, in the Unaudited Consolidated Balance Sheet as of September 30, 2017. See Note 4 for additional information on assets held for sale.

The Company reviews oil and natural gas properties 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 using proved and risked probable and possible reserves based on the Company's development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax 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 oil and gas properties, no impairment is taken. If the carrying amount 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 of its oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, 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.

In addition, oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique, which involves calculating the present value of future net cash flows as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Impairment of unproved oil and gas properties (1)	$	—	$	—	$	8,010	$	183
Dry hole costs	—		1		—		71
Abandonment expense and lease expirations	261		973		326		1,512
Total impairment, dry hole costs and abandonment expense	$	261	$	974	$	8,336	$	1,766

(1) The Company recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the nine months ended September 30, 2017. The Company has no current plan to develop this acreage.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.

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

	As of September 30, 2017		As of December 31, 2016
	(in thousands)
Accrued drilling, completion and facility costs	$	33,325	$	15,594
Accrued lease operating, gathering, transportation and processing expenses	4,589		4,261
Accrued general and administrative expenses	8,653		6,375
Accrued interest payable	23,500		12,264
Prepayments from partners	11,249		332
Trade payables	2,323		7,900
Other	2,039		2,721
Total accounts payable and accrued liabilities	$	85,678	$	49,447

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. Recent case law in Wyoming has exposed the Company to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contractual obligations to the Company as provided for in the applicable purchase and sale agreements, regulatory agencies and landowners may demand that the Company perform such activities. The Company recognized $0.8 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the nine months ended September 30, 2017.

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 September 30, 2017 and 2016 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. Deferred tax assets are regularly reviewed, considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, taxable strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine whether it is more likely than not that the deferred tax asset will be realized. If it is determined that the deferred tax asset will not be realized, then a valuation allowance will be recorded against the deferred tax asset. The Company began recording a full valuation allowance against the deferred tax asset during the period ending September 30, 2015 and continues to do so as of September 30, 2017.

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 September 30, 2017.

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 and in-the-money outstanding stock options to purchase the Company's common stock. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and nine months ended September 30, 2017 and 2016.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands, except per share amounts)
Net income (loss)	$	(28,842	)	$	(26,186	)	$	(60,404	)	$	(121,101	)
Basic weighted-average common shares outstanding in period	74,886			58,852			74,743			53,082
Diluted weighted-average common shares outstanding in period	74,886			58,852			74,743			53,082
Basic net income (loss) per common share	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)
Diluted net income (loss) per common share	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)

New Accounting Pronouncements. In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-09, Stock Compensation-Scope of Modification Accounting. The objective of this update is to provide clarity and reduce both diversity in practice and cost and complexity when applying a change to the terms or conditions of a share-based payment award. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In January 2017, the FASB issued ASU 2017-01, Business Combinations: Clarifying the definition of a business. The objective of this update is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments. The objective of this update is to address eight specific cash flow issues in order to reduce the existing diversity in practice. ASU 2016-15 is effective for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. The objective of this update is to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted effective January 1, 2017 and did not have a significant impact on the Company's disclosures or financial statements. As of January 1, 2017, the Company did not have excess tax benefits associated with its stock compensation and therefore there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes were already classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. The Company elected to account for forfeitures as they occur as opposed to estimating the number of awards that are expected to vest. Per ASU 2016-09, the election is considered a change in accounting principle, with the cumulative effect of the change reported as an adjustment to the beginning equity balance. The Company reported an increase to accumulated deficit and additional paid in capital ("APIC") of $0.2 million related to equity award compensation and an increase to accumulated deficit and derivative and other noncurrent liabilities of $0.3 million related to liability award compensation. The cumulative effect of accounting change is reported in the Consolidated Statement of Stockholders' Equity.

In February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company has performed an initial assessment by compiling and analyzing contracts and leasing arrangements that may be affected. The Company is still evaluating the impact of adopting this standard.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The objective of this update is to require deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted January 1, 2017 on a prospective basis and did not have a significant impact on the Company's disclosures and financial statements. Prior periods were not retrospectively adjusted.

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. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which provided additional implementation guidance and deferred the effective date of ASU 2014-09. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard will be adopted using the modified retrospective transition method, effective January 1, 2018. The Company has performed an assessment of its current existing revenue contracts and is in the process of implementing additional control procedures. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

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Supplemental Disclosures of Cash Flow Information

9 Months Ended

Sep. 30, 2017

Supplemental Cash Flow Elements [Abstract]

Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Cash paid for interest	$	31,113		$	31,736
Cash paid for income taxes	—			—
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	37,319			8,318
Change in asset retirement obligations, net of disposals	10,453			(4,788		)
Retirement of treasury stock	(1,246		)	(1,098		)
Properties exchanged in non-cash transactions	13,323			—
Fair value of debt exchanged for common stock (1)	—			74,400

(1) See Note 5 for additional information regarding the Debt Exchange.

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Acquisitions, Exchanges, Divestitures and Assets Held for Sale

9 Months Ended

Sep. 30, 2017

Mergers, Acquisitions and Dispositions Disclosures [Abstract]

Acquisitions, Exchanges and Divestitures

Acquisitions, Exchanges, Divestitures and Assets Held for Sale

During the three months ended September 30, 2017, the Company committed to a plan to sell the Company's remaining assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2017. Assets held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value of the net assets held for sale was in excess of the net carrying value as of September 30, 2017. The net carrying value was presented as assets held for sale, net of depreciation, depletion, amortization and impairment, of $145.6 million and liabilities associated with assets held for sale of $4.9 million on the Unaudited Consolidated Balance Sheet as of September 30, 2017.

On February 28, 2017, the Company acquired acreage in the DJ Basin for $11.6 million, after final closing adjustments. The transaction was considered an asset acquisition and therefore the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. The acquisition included $9.1 million and $11.2 million of proved and unevaluated properties, respectively, and asset retirement obligations of $8.7 million.

During the nine months ended September 30, 2017, the Company completed two acreage exchange transactions to consolidate certain acreage positions in the DJ Basin. Pursuant to the transactions, the Company exchanged leasehold interests in certain proved undeveloped acreage. The Company’s future cash flows are not expected to significantly change as a result of the exchange transactions, therefore, the non-monetary exchanges were measured based on the carrying values and not on the fair values of the assets exchanged.

On July 14, 2016, the Company sold certain non-core assets in the Uinta Basin. The Company received $27.8 million in cash proceeds, after final closing adjustments. In addition to the cash proceeds, the Company recognized non-cash proceeds of $4.8 million related to the relief from the Company's asset retirement obligation. Assets sold included $30.6 million in proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment, and $2.0 million in unproved oil and gas properties. Liabilities sold included $4.8 million of asset retirement obligations. The transaction was accounted for as a cost recovery. Therefore, no gain or loss was recognized.

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Long-Term Debt

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

The Company's outstanding debt is summarized below:

		As of September 30, 2017							As of December 31, 2016
	Maturity Date	Principal		Debt Issuance Costs			Carrying Amount		Principal		Debt Issuance Costs			Carrying Amount
		(in thousands)
Amended Credit Facility	April 9, 2020	$	—	$	—		$	—	$	—	$	—		$	—
Convertible Notes (1)	March 15, 2028	—		—			—		579		—			579
7.625% Senior Notes (2)	October 1, 2019	—		—			—		315,300		(2,169		)	313,131
7.0% Senior Notes (3)	October 15, 2022	400,000		(3,684		)	396,316		400,000		(4,227		)	395,773
8.75% Senior Notes (4)	June 15, 2025	275,000		(4,548		)	270,452		—		—			—
Lease Financing Obligation (5)	August 10, 2020	2,443		(2		)	2,441		2,782		(3		)	2,779
Total Debt		$	677,443	$	(8,234	)	$	669,209	$	718,661	$	(6,399	)	$	712,262
Less: Current Portion of Long-Term Debt (6)		465		—			465		454		—			454
Total Long-Term Debt		$	676,978	$	(8,234	)	$	668,744	$	718,207	$	(6,399	)	$	711,808

(1) The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of December 31, 2016 based on reported market trades of these instruments.

(2) The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately $314.5 million as of December 31, 2016 based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $386.3 million and $384.5 million as of September 30, 2017 and December 31, 2016, respectively, based on reported market trades of these instruments.

(4) The aggregate estimated fair value of the 8.75% Senior Notes was approximately $266.8 million as of September 30, 2017 based on reported market trades of these instruments.

(5) The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.3 million and $2.6 million as of September 30, 2017 and December 31, 2016, respectively. As 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 long-term debt includes the current portion of the Lease Financing Obligation.

Amended Credit Facility

The Company's amended revolving credit facility ("Amended Credit Facility") had commitments from 13 lenders and a borrowing base of $300.0 million as of September 30, 2017. As credit support for future payments 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 September 30, 2017 to $274.0 million. There have not been any borrowings under the Amended Credit Facility to date in 2017 and there were no such borrowings in 2016.

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 borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of the Company's proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. In October 2017, the Company's borrowing base was re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at June 30, 2017. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the Company's lenders, as well as any other outstanding debt. Lower commodity prices could result in a decreased borrowing base.

The Amended Credit Facility contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. If the Company fails to comply with the covenants or other terms of any agreements governing the Company's debt, the Company's lenders and holders of the Company's senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect the Company's financial condition. In September 2015, the Company obtained an amendment to the Amended Credit Facility that replaced the Company's debt-to-EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses) covenant in the facility with a secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that the Company will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

5% Convertible Senior Notes Due 2028

On May 30, 2017, the Company redeemed the $0.6 million of outstanding Convertible Notes with the proceeds of its 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes due 2025" below for additional information.

7.625% Senior Notes Due 2019

On May 30, 2017, the Company redeemed the $315.3 million of outstanding 7.625% Senior Notes with cash on hand and proceeds from the issuance of its 8.75% Senior Notes on April 28, 2017. See "8.75% Senior Notes due 2025" below for additional information.

Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, the Company recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the nine months ended September 30, 2017.

The 7.625% Senior Notes were issued at $400.0 million in principal amount on September 27, 2011. On June 3, 2016, the Company completed a debt exchange with a holder of the 7.625% Senior Notes (the "Debt Exchange"). The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the Company’s common stock. Based on the fair value of the shares issued, the Company recognized an $8.7 million gain on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2016. Following the Debt Exchange, the remaining aggregate principal amount was $315.3 million, which, as indicated above, was then redeemed on May 30, 2017.

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 October 15, 2022 at par. The 7.0% Senior Notes mature on October 15, 2022 unless earlier redeemed or purchased by the Company. 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 8.75% Senior Notes. The 7.0% Senior Notes became redeemable at the Company's option on October 15, 2017 at a redemption price of 103.500% of the principal amount. The redemption price will decrease to 102.333%, 101.167% and 100.000% of the principal amount in 2018, 2019 and 2022, respectively. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 8.75% 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 covenants and has complied with all covenants since issuance.

8.75% Senior Notes Due 2025

On April 28, 2017, the Company issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year, commencing on December 15, 2017. The 8.75% 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 7.0% Senior Notes.

The 8.75% Senior Notes will become redeemable at the Company's option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, the Company may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, the Company may redeem the notes at a redemption price equal to 100.000% of the principal amount plus a specified "make-whole" premium.

The 8.75% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 7.0% Senior Notes. The 8.75% 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 covenants and has complied with all covenants since issuance.

Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

Lease Financing Obligation Due 2020

The Company has a lease financing obligation with a balance of $2.4 million as of September 30, 2017 resulting from the Company's sale and subsequent lease back of certain compressors and related facilities owned by the Company (the "Lease Financing Obligation"). 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 12 for a discussion of aggregate minimum future lease payments.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the nine months ended September 30, 2017 is as follows (in thousands):

As of December 31, 2016	$	11,238
Liabilities incurred (1)	10,379
Liabilities settled	(814		)
Disposition of properties	(6		)
Accretion expense	765
Revisions to estimate	894
As of September 30, 2017	$	22,456
Less: liabilities associated with assets held for sale	4,856
Less: current asset retirement obligations	1,829
Long-term asset retirement obligations	$	15,771

(1) Includes $8.7 million associated with properties acquired in the DJ Basin during the nine months ended September 30, 2017. See Note 4 for additional information regarding this acquisition.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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 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. 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 2 – Quoted prices are available in active markets for similar assets or liabilities and in non-active markets for identical or similar instruments. Model-derived valuations have inputs that are observable or whose significant value drivers are observable. 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.

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 assets and liabilities that were measured at fair value in the Unaudited Consolidated Balance Sheets.

	As of September 30, 2017
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Cash equivalents (1)	$	110,772	$	—	$	—	$	110,772
Deferred compensation plan (1)	1,719		—		—		1,719
Commodity derivatives (1)	—		8,211		—		8,211
Unproved oil and gas properties (2)	—		—		1,088		1,088
Liabilities
Commodity derivatives (1)	$	—	$	2,466	$	—	$	2,466

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2) This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.

	As of December 31, 2016
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Cash equivalents (1)	$	40,115	$	—	$	—	$	40,115
Deferred compensation plan (1)	1,447		—		—		1,447
Commodity derivatives (1)	—		13,156		—		13,156
Liabilities
Commodity derivatives (1)	$	—	$	10,003	$	—	$	10,003

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Cash equivalents – The highly liquid cash equivalents are recorded at carrying value. Carrying value approximates fair value, which represents a Level 1 input.

Deferred compensation plan – 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 deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Commodity derivatives – 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. The inputs discussed above all represent Level 2 inputs.

The commodity derivatives 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.

Oil and gas properties –Oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. If an impairment is necessary, the fair value is estimated by using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future revenues. The present value, net of estimated operating and development costs, is calculated 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, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. During the nine months ended September 30, 2017, the Company reduced its unproved Cottonwood Gulch assets in the Piceance Basin to a fair value of $1.1 million, resulting in a non-cash impairment charge of $8.0 million. During the year ended December 31, 2016, no properties were measured at fair value.

Properties classified as held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The fair value of the assets held for sale as of September 30, 2017 was in excess of the net carrying value, therefore, no impairment was necessary. See Note 4 for additional information on assets held for sale.

Acquisitions of proved and unproved properties – Assets acquired and liabilities assumed under transactions that meet the criteria of a business combination under ASC Topic 805, Business Combinations are recorded at fair value on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of reserves, production rates, future operating and development costs, future commodity prices including price differentials, future cash flows and a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

Assets acquired and liabilities assumed under transactions that do not meet the criteria of a business combination under ASC Topic 805, Business Combinations are accounted for as asset acquisitions and are recorded based on the fair value of the total consideration transferred on the acquisition date using the lowest observable inputs available. The Company acquired proved and unproved properties in the DJ Basin for total cash consideration of $11.6 million during the nine months ended September 30, 2017. See Note 4 for additional information regarding this asset acquisition.

Long-term Debt – Long-term debt is not presented at fair value on the Unaudited Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The Company issued the 8.75% Senior Notes on April 28, 2017 and redeemed its 7.625% Senior Notes on May 30, 2017. The fair values of the Company's fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $653.1 million as of September 30, 2017. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $699.0 million as of December 31, 2016. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility or Lease Financing Obligation and there was no such market for the Convertible Notes when they were outstanding. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company's borrowing base utilization. The Amended Credit Facility had a balance of zero as of September 30, 2017 and December 31, 2016. The Convertible Notes were redeemed on May 30, 2017 and had a fair value of $0.5 million as of December 31, 2016. The Lease Financing Obligation fair values of $2.3 million and $2.6 million as of September 30, 2017 and December 31, 2016, 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.

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Derivative Instruments

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

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

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

All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair value and included in the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts, of all derivative instruments presented in the Unaudited Consolidated Balance Sheets as of the dates indicated.

	As of September 30, 2017
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	7,608		$	(1,826	)	(1)	$	5,782
Deferred financing costs and other noncurrent assets	603			(482		)	(1)	121
Total derivative assets	$	8,211		$	(2,308	)		$	5,903
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(1,826	)	$	1,826		(1)	$	—
Derivatives and other noncurrent liabilities	(640		)	482			(1)	(158		)
Total derivative liabilities	$	(2,466	)	$	2,308			$	(158	)
	As of December 31, 2016
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	13,156		$	(4,758	)	(1)	$	8,398
Deferred financing costs and other noncurrent assets	—			—				—
Total derivative assets	$	13,156		$	(4,758	)		$	8,398
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(9,104	)	$	4,758		(1)	$	(4,346	)
Derivatives and other noncurrent liabilities	(899		)	—				(899		)
Total derivative liabilities	$	(10,003	)	$	4,758			$	(5,245	)

(1) Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.

As of September 30, 2017, the Company had financial derivative instruments in place related to the sale of a portion of the Company's production for the following volumes for the periods indicated:

	October – December 2017			For the year 2018			For the year 2019
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	747,500	$	57.69	2,506,750	$	52.47	547,500	$	50.38
Natural Gas (MMbtu)	920,000	$	2.96	1,825,000	$	2.68	—	$	—

The Company's derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments 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 six different counterparties as of September 30, 2017. 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 ongoing 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 these counterparties.

It is the Company's policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility or affiliates of lenders in the Amended Credit Facility. The Company's derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement 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, the Company may not be able to set-off amounts owed by it 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.

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Income Taxes

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the three and nine months ended September 30, 2017 and 2016, the Company had no uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and nine months ended September 30, 2017 and 2016.

Income tax benefit for the three and nine months ended September 30, 2017 and 2016 differs from the amounts that would be provided by applying the U.S. statutory income tax rates to pretax income or loss principally due to the effect of deferred tax asset valuation allowances, stock-based compensation, political lobbying expense, political contributions, nondeductible officer compensation and state income taxes. For the three and nine months ended September 30, 2017 and 2016, the effective tax rate remained at zero as a result of recording a full valuation allowance against the deferred tax asset balance. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgement is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration.

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Stockholders' Equity

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

Stockholders' Equity

Stockholders' Equity

Common and Preferred Stock. The Company's authorized capital structure consists of 75,000,000 shares of preferred stock, par value of $0.001 per share, and 300,000,000 shares of common stock, par value of $0.001 per share. At the annual meeting on May 16, 2017, a proposal to increase the number of authorized shares of common stock from 150,000,000 to 300,000,000 was approved. There are no issued and outstanding shares of preferred stock.

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 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 September 30, 2017, and the date of this filing, no shares have been sold pursuant to the Agreement.

On June 3, 2016, the Company issued 10,000,000 shares of common stock pursuant to a debt exchange with a holder of the Company's 7.625% Senior Notes. The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the Company’s common stock.

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs

9 Months Ended

Sep. 30, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Incentive Compensation Plans and Other Long-term Incentive Programs

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). Cash-based compensation is measured at fair value at each reporting date and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

The following table presents the long-term cash and equity incentive compensation related to awards for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
	(in thousands)
Common stock options (1)	$	—	$	—	$	—		$	69
Nonvested common stock (1)	1,434		1,458		4,437			5,273
Nonvested common stock units (1)	174		165		516			711
Nonvested performance-based shares (1)	—		275		558			1,510
Nonvested performance cash units (2)(3)	1,073		242		(27		)	1,088
Total	$	2,681	$	2,140	$	5,484		$	8,651

(1) Unrecognized compensation cost as of September 30, 2017 was $6.8 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.7 years.

(2) The nonvested performance-based cash units are accounted for as liability awards with $1.1 million in accounts payable and accrued liabilities as of September 30, 2017 and $2.1 million and $2.9 million in derivatives and other noncurrent liabilities as of September 30, 2017 and December 31, 2016, respectively, in the Unaudited Consolidated Balance Sheets.

(3) Liability awards are fair valued at each reporting date. For the three months ended September 30, 2017, the weighted average fair value share price increased from $3.41 as of June 30, 2017 to $4.29 as of September 30, 2017. For the nine months ended September 30, 2017, the weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $4.29 as of September 30, 2017.

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

	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Equity Awards	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	5,267	$	3.31	—	$	—
Nonvested common stock units	3,787	$	4.29	2,922	$	5.56
Total granted	9,054			2,922
	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Cash Awards	Number of Units	Fair Value Per Unit		Number of Units	Fair Value Per Unit
Nonvested performance cash units	5,267	$	4.29	—	$	—
	Nine Months Ended September 30, 2017			Nine Months Ended September 30, 2016
Equity Awards	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	782,511	$	5.99	686,500	$	5.11
Nonvested common stock units	190,711	$	3.53	96,650	$	7.02
Total granted	973,222			783,150
	Nine Months Ended September 30, 2017			Nine Months Ended September 30, 2016
Cash Awards	Number of Units	Fair Value Per Unit		Number of Units	Fair Value Per Unit
Nonvested performance cash units	663,425	$	4.29	646,572	$	5.56

Performance Cash Program

2017 Program. In February 2017, the Compensation Committee approved a performance cash program (the "2017 Program") granting performance cash units that will settle in cash. The performance-based awards contingently vest in February 2020, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three-year period ending December 31, 2019, will be the Company's total shareholder return ("TSR") based on a matrix measurement of (1) the Company's absolute performance and (2) the Company's ranking relative to a defined peer group's individual TSRs ("Relative TSR"). The Company's absolute performance is measured against the December 30, 2016 closing share price of $6.99. If the Company's absolute performance is lower than the $6.99 share price, the payout is zero for this portion. If the Company's absolute performance is greater than the $6.99 share price, the performance cash units will vest 1% for each 1% in growth, up to 100% of the original grant. If the Company's Relative TSR is less than the median, the payout is zero for this portion. If the Company's Relative TSR is above the median, the payout is equal to twice the Company's percentile rank above the median, up to 100% of the original grant. The Company's combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant. A total of 663,425 units were granted under this program during the nine months ended September 30, 2017.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Lease Financing Obligation. The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below. The Lease Financing Obligation contains an early buyout option pursuant to which the Company may purchase the equipment for $1.8 million on February 10, 2019.

	As of September 30, 2017
	(in thousands)
2017	$	135
2018	537
2019	1,824
Total	$	2,496

Transportation Charges. The Company is party to two firm transportation contracts, through July 2021, to provide capacity on natural gas pipeline systems. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 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 September 30, 2017
	(in thousands)
2017	$	4,634
2018	18,691
2019	18,691
2020	18,691
2021	10,902
Thereafter	—
Total	$	71,609

Lease and Other Commitments. The Company leases office space, vehicles and certain office equipment. In addition, the Company has various long-term agreements for telecommunication services. Future minimum annual payments under lease and other agreements are as follows:

	As of September 30, 2017
	(in thousands)
2017	$	951
2018	3,038
2019	1,070
2020	113
2021	6
Thereafter	—
Total	$	5,178

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.

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Guarantor Subsidiaries

9 Months Ended

Sep. 30, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Guarantor Subsidiaries

Guarantor Subsidiaries

In addition to the Amended Credit Facility, the 7.0% Senior Notes and 8.75% Senior Notes, which have been registered under the Securities Act of 1933, are jointly and severally guaranteed on a full and unconditional basis by the Company's 100% owned subsidiaries ("Guarantor Subsidiaries"). Presented below are the Company's condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) and statements of cash flows, as required by Securities and Exchange Commission ("SEC") Rule 3-10 of Regulation S-X.

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

Condensed Consolidating Balance Sheets

	As of September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	155,885		$	—		$	—		$	155,885
Accounts receivable, net of allowance for doubtful accounts	41,935			154			—			42,089
Other current assets	153,544			—			—			153,544
Property and equipment, net	970,444			5,401			—			975,845
Intercompany receivable	20,304			—			(20,304		)	—
Investment in subsidiaries	(14,811		)	—			14,811			—
Noncurrent assets	3,143			—			—			3,143
Total assets	$	1,330,444		$	5,555		$	(5,493	)	$	1,330,506
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	$	85,678		$	—		$	—		$	85,678
Other current liabilities	40,689			—			—			40,689
Intercompany payable	—			20,304			(20,304		)	—
Long-term debt	668,744			—			—			668,744
Other noncurrent liabilities	20,319			62			—			20,381
Stockholders' equity	515,014			(14,811		)	14,811			515,014
Total liabilities and stockholders' equity	$	1,330,444		$	5,555		$	(5,493	)	$	1,330,506

	As of December 31, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	275,841		$	—		$	—		$	275,841
Accounts receivable, net of allowance for doubtful accounts	32,659			178			—			32,837
Other current assets	9,774			—			—			9,774
Property and equipment, net	1,056,343			5,806			—			1,062,149
Intercompany receivable	20,678			—			(20,678		)	—
Investment in subsidiaries	(14,751		)	—			14,751			—
Noncurrent assets	4,740			—			—			4,740
Total assets	$	1,385,284		$	5,984		$	(5,927	)	$	1,385,341
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	$	49,447		$	—		$	—		$	49,447
Other current liabilities	35,571			—			—			35,571
Intercompany payable	—			20,678			(20,678		)	—
Long-term debt	711,808			—			—			711,808
Other noncurrent liabilities	16,915			57			—			16,972
Stockholders' equity	571,543			(14,751		)	14,751			571,543
Total liabilities and stockholders' equity	$	1,385,284		$	5,984		$	(5,927	)	$	1,385,341

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	67,697		$	168		$	—		$	67,865
Operating expenses	(58,053		)	(156		)	—			(58,209		)
General and administrative	(12,496		)	—			—			(12,496		)
Interest expense	(13,926		)	—			—			(13,926		)
Interest income and other income (expense)	(12,076		)	—			—			(12,076		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(28,854		)	12			—			(28,842		)
(Provision for) Benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	12			—			(12		)	—
Net income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	169,041		$	426		$	—		$	169,467
Operating expenses	(167,363		)	(486		)	—			(167,849		)
General and administrative	(30,788		)	—			—			(30,788		)
Interest expense	(44,014		)	—			—			(44,014		)
Interest income and other income (expense)	12,780			—			—			12,780
Income (loss) before income taxes and equity in earnings of subsidiaries	(60,344		)	(60		)	—			(60,404		)
(Provision for) benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	(60		)	—			60			—
Net income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)

	Three Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	50,325		$	156		$	—		$	50,481
Operating expenses	(59,498		)	(155		)	—			(59,653		)
General and administrative	(9,178		)	—			—			(9,178		)
Interest expense	(13,991		)	—			—			(13,991		)
Interest and other income (expense)	6,155			—			—			6,155
Income (loss) before income taxes and equity in earnings of subsidiaries	(26,187		)	1			—			(26,186		)
(Provision for) Benefit from income taxes	—			—			—			—
Equity in earnings of subsidiaries	1			—			(1		)	—
Net income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	126,730		$	469		$	—		$	127,199
Operating expenses	(172,759		)	(480		)	—			(173,239		)
General and administrative	(31,535		)	—			—			(31,535		)
Interest expense	(45,160		)	—			—			(45,160		)
Interest and other income (expense)	1,634			—			—			1,634
Income (loss) before income taxes and equity in earnings of subsidiaries	(121,090		)	(11		)	—			(121,101		)
(Provision for) benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	(11		)	—			11			—
Net income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)

	Three Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	95,009		$	374		$	—		$	95,383
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(160,788		)	—			—			(160,788		)
Additions to furniture, fixtures and other	(268		)	—			—			(268		)
Proceeds from sale of properties and other investing activities	(712		)	—			—			(712		)
Intercompany transfers	374			—			(374		)	—
Cash flows from financing activities:
Proceeds from debt	275,000			—			—			275,000
Principal payments on debt	(322,228		)	—			—			(322,228		)
Proceeds from sale of common stock, net of offering costs	(298		)	—			—			(298		)
Intercompany transfers	—			(374		)	374			—
Other financing activities	(6,045		)	—			—			(6,045		)
Change in cash and cash equivalents	(119,956		)	—			—			(119,956		)
Beginning cash and cash equivalents	275,841			—			—			275,841
Ending cash and cash equivalents	$	155,885		$	—		$	—		$	155,885

	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	115,695		$	512		$	—		$	116,207
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(93,686		)	(18		)	—			(93,704		)
Additions to furniture, fixtures and other	(1,184		)	—			—			(1,184		)
Proceeds from sale of properties and other investing activities	25,571			—			—			25,571
Intercompany transfers	494			—			(494		)	—
Cash flows from financing activities:
Principal payments on debt	(329		)	—			—			(329		)
Intercompany transfers	—			(494		)	494			—
Other financing activities	(1,134		)	—			—			(1,134		)
Change in cash and cash equivalents	45,427			—			—			45,427
Beginning cash and cash equivalents	128,836			—			—			128,836
Ending cash and cash equivalents	$	174,263		$	—		$	—		$	174,263

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Basis of Presentation

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 consolidated 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 2016 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 2016 Annual Report on Form 10-K.

Use of Estimates

Use of Estimates. In the course of preparing the Company's consolidated 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 include volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future net 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 payment awards.

Oil and Gas Properties

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, recent sales prices of comparable properties 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.

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

	As of September 30, 2017			As of December 31, 2016
	(in thousands)
Proved properties	$	218,746		$	306,075
Wells and related equipment and facilities	1,035,764			1,164,354
Support equipment and facilities	34,317			63,238
Materials and supplies	3,959			5,706
Total proved oil and gas properties (1)	$	1,292,786		$	1,539,373
Unproved properties	33,713			27,790
Wells and facilities in progress	36,822			31,040
Total unproved oil and gas properties, excluded from amortization (1)	$	70,535		$	58,830
Accumulated depreciation, depletion, amortization and impairment (1)	(393,340		)	(543,154		)
Total oil and gas properties, net (1)	$	969,981		$	1,055,049

(1) Excludes oil and gas properties held for sale of $145.1 million, comprised of $410.7 million of proved oil and gas properties and $0.4 million of unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of $266.0 million. Held for sale balances are included in current assets as assets held for sale, net of amortization and impairment, in the Unaudited Consolidated Balance Sheet as of September 30, 2017. See Note 4 for additional information on assets held for sale.

The Company reviews oil and natural gas properties 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 using proved and risked probable and possible reserves based on the Company's development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax 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 oil and gas properties, no impairment is taken. If the carrying amount 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 of its oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, 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.

In addition, oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique, which involves calculating the present value of future net cash flows as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Impairment of unproved oil and gas properties (1)	$	—	$	—	$	8,010	$	183
Dry hole costs	—		1		—		71
Abandonment expense and lease expirations	261		973		326		1,512
Total impairment, dry hole costs and abandonment expense	$	261	$	974	$	8,336	$	1,766

(1) The Company recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the nine months ended September 30, 2017. The Company has no current plan to develop this acreage.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. 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. Accounts payable and accrued liabilities are comprised of the following:

	As of September 30, 2017		As of December 31, 2016
	(in thousands)
Accrued drilling, completion and facility costs	$	33,325	$	15,594
Accrued lease operating, gathering, transportation and processing expenses	4,589		4,261
Accrued general and administrative expenses	8,653		6,375
Accrued interest payable	23,500		12,264
Prepayments from partners	11,249		332
Trade payables	2,323		7,900
Other	2,039		2,721
Total accounts payable and accrued liabilities	$	85,678	$	49,447

Environmental Liabilities

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. Recent case law in Wyoming has exposed the Company to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contractual obligations to the Company as provided for in the applicable purchase and sale agreements, regulatory agencies and landowners may demand that the Company perform such activities. The Company recognized $0.8 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the nine months ended September 30, 2017.

Revenue Recognition

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 September 30, 2017 and 2016 were not material.

Derivative Instruments and Hedging Activities

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. 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. Deferred tax assets are regularly reviewed, considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, taxable strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine whether it is more likely than not that the deferred tax asset will be realized. If it is determined that the deferred tax asset will not be realized, then a valuation allowance will be recorded against the deferred tax asset. The Company began recording a full valuation allowance against the deferred tax asset during the period ending September 30, 2015 and continues to do so as of September 30, 2017.

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 September 30, 2017.

Earnings/Loss Per Share

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 and in-the-money outstanding stock options to purchase the Company's common stock. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and nine months ended September 30, 2017 and 2016.

New Accounting Pronouncements

New Accounting Pronouncements. In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-09, Stock Compensation-Scope of Modification Accounting. The objective of this update is to provide clarity and reduce both diversity in practice and cost and complexity when applying a change to the terms or conditions of a share-based payment award. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In January 2017, the FASB issued ASU 2017-01, Business Combinations: Clarifying the definition of a business. The objective of this update is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments. The objective of this update is to address eight specific cash flow issues in order to reduce the existing diversity in practice. ASU 2016-15 is effective for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. The objective of this update is to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted effective January 1, 2017 and did not have a significant impact on the Company's disclosures or financial statements. As of January 1, 2017, the Company did not have excess tax benefits associated with its stock compensation and therefore there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes were already classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. The Company elected to account for forfeitures as they occur as opposed to estimating the number of awards that are expected to vest. Per ASU 2016-09, the election is considered a change in accounting principle, with the cumulative effect of the change reported as an adjustment to the beginning equity balance. The Company reported an increase to accumulated deficit and additional paid in capital ("APIC") of $0.2 million related to equity award compensation and an increase to accumulated deficit and derivative and other noncurrent liabilities of $0.3 million related to liability award compensation. The cumulative effect of accounting change is reported in the Consolidated Statement of Stockholders' Equity.

In February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company has performed an initial assessment by compiling and analyzing contracts and leasing arrangements that may be affected. The Company is still evaluating the impact of adopting this standard.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The objective of this update is to require deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted January 1, 2017 on a prospective basis and did not have a significant impact on the Company's disclosures and financial statements. Prior periods were not retrospectively adjusted.

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. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which provided additional implementation guidance and deferred the effective date of ASU 2014-09. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard will be adopted using the modified retrospective transition method, effective January 1, 2018. The Company has performed an assessment of its current existing revenue contracts and is in the process of implementing additional control procedures. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Summary of Accounts Receivable

Accounts receivable is comprised of the following:

	As of September 30, 2017			As of December 31, 2016
	(in thousands)
Accrued oil, gas and NGL sales	$	33,170		$	26,542
Due from joint interest owners	9,164			4,366
Other	14			1,952
Allowance for doubtful accounts	(259		)	(23		)
Total accounts receivable	$	42,089		$	32,837

Net Capitalized Costs and Associated Accumulated DD&A and Non Cash Impairments

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

	As of September 30, 2017			As of December 31, 2016
	(in thousands)
Proved properties	$	218,746		$	306,075
Wells and related equipment and facilities	1,035,764			1,164,354
Support equipment and facilities	34,317			63,238
Materials and supplies	3,959			5,706
Total proved oil and gas properties (1)	$	1,292,786		$	1,539,373
Unproved properties	33,713			27,790
Wells and facilities in progress	36,822			31,040
Total unproved oil and gas properties, excluded from amortization (1)	$	70,535		$	58,830
Accumulated depreciation, depletion, amortization and impairment (1)	(393,340		)	(543,154		)
Total oil and gas properties, net (1)	$	969,981		$	1,055,049

(1) Excludes oil and gas properties held for sale of $145.1 million, comprised of $410.7 million of proved oil and gas properties and $0.4 million of unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of $266.0 million. Held for sale balances are included in current assets as assets held for sale, net of amortization and impairment, in the Unaudited Consolidated Balance Sheet as of September 30, 2017. See Note 4 for additional information on assets held for sale.

Non-Cash Impairment Charges, Included within Impairment, Dry Hole Costs and Abandonment Expense in Consolidated Statements of Operations

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Impairment of unproved oil and gas properties (1)	$	—	$	—	$	8,010	$	183
Dry hole costs	—		1		—		71
Abandonment expense and lease expirations	261		973		326		1,512
Total impairment, dry hole costs and abandonment expense	$	261	$	974	$	8,336	$	1,766

(1) The Company recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the nine months ended September 30, 2017. The Company has no current plan to develop this acreage.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities are comprised of the following:

	As of September 30, 2017		As of December 31, 2016
	(in thousands)
Accrued drilling, completion and facility costs	$	33,325	$	15,594
Accrued lease operating, gathering, transportation and processing expenses	4,589		4,261
Accrued general and administrative expenses	8,653		6,375
Accrued interest payable	23,500		12,264
Prepayments from partners	11,249		332
Trade payables	2,323		7,900
Other	2,039		2,721
Total accounts payable and accrued liabilities	$	85,678	$	49,447

Calculation of Basic and Diluted Earnings (Loss) Per Share

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands, except per share amounts)
Net income (loss)	$	(28,842	)	$	(26,186	)	$	(60,404	)	$	(121,101	)
Basic weighted-average common shares outstanding in period	74,886			58,852			74,743			53,082
Diluted weighted-average common shares outstanding in period	74,886			58,852			74,743			53,082
Basic net income (loss) per common share	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)
Diluted net income (loss) per common share	$	(0.39	)	$	(0.44	)	$	(0.81	)	$	(2.28	)

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Supplemental Disclosures of Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2017

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

Supplemental cash flow information is as follows:

	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Cash paid for interest	$	31,113		$	31,736
Cash paid for income taxes	—			—
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	37,319			8,318
Change in asset retirement obligations, net of disposals	10,453			(4,788		)
Retirement of treasury stock	(1,246		)	(1,098		)
Properties exchanged in non-cash transactions	13,323			—
Fair value of debt exchanged for common stock (1)	—			74,400

(1) See Note 5 for additional information regarding the Debt Exchange.

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Outstanding Debt

The Company's outstanding debt is summarized below:

		As of September 30, 2017							As of December 31, 2016
	Maturity Date	Principal		Debt Issuance Costs			Carrying Amount		Principal		Debt Issuance Costs			Carrying Amount
		(in thousands)
Amended Credit Facility	April 9, 2020	$	—	$	—		$	—	$	—	$	—		$	—
Convertible Notes (1)	March 15, 2028	—		—			—		579		—			579
7.625% Senior Notes (2)	October 1, 2019	—		—			—		315,300		(2,169		)	313,131
7.0% Senior Notes (3)	October 15, 2022	400,000		(3,684		)	396,316		400,000		(4,227		)	395,773
8.75% Senior Notes (4)	June 15, 2025	275,000		(4,548		)	270,452		—		—			—
Lease Financing Obligation (5)	August 10, 2020	2,443		(2		)	2,441		2,782		(3		)	2,779
Total Debt		$	677,443	$	(8,234	)	$	669,209	$	718,661	$	(6,399	)	$	712,262
Less: Current Portion of Long-Term Debt (6)		465		—			465		454		—			454
Total Long-Term Debt		$	676,978	$	(8,234	)	$	668,744	$	718,207	$	(6,399	)	$	711,808

(1) The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of December 31, 2016 based on reported market trades of these instruments.

(2) The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately $314.5 million as of December 31, 2016 based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $386.3 million and $384.5 million as of September 30, 2017 and December 31, 2016, respectively, based on reported market trades of these instruments.

(4) The aggregate estimated fair value of the 8.75% Senior Notes was approximately $266.8 million as of September 30, 2017 based on reported market trades of these instruments.

(5) The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.3 million and $2.6 million as of September 30, 2017 and December 31, 2016, respectively. As 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 long-term debt includes the current portion of the Lease Financing Obligation.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the nine months ended September 30, 2017 is as follows (in thousands):

As of December 31, 2016	$	11,238
Liabilities incurred (1)	10,379
Liabilities settled	(814		)
Disposition of properties	(6		)
Accretion expense	765
Revisions to estimate	894
As of September 30, 2017	$	22,456
Less: liabilities associated with assets held for sale	4,856
Less: current asset retirement obligations	1,829
Long-term asset retirement obligations	$	15,771

(1) Includes $8.7 million associated with properties acquired in the DJ Basin during the nine months ended September 30, 2017. See Note 4 for additional information regarding this acquisition.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value, Balance Sheet Grouping

The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were measured at fair value in the Unaudited Consolidated Balance Sheets.

	As of September 30, 2017
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Cash equivalents (1)	$	110,772	$	—	$	—	$	110,772
Deferred compensation plan (1)	1,719		—		—		1,719
Commodity derivatives (1)	—		8,211		—		8,211
Unproved oil and gas properties (2)	—		—		1,088		1,088
Liabilities
Commodity derivatives (1)	$	—	$	2,466	$	—	$	2,466

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2) This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.

	As of December 31, 2016
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Cash equivalents (1)	$	40,115	$	—	$	—	$	40,115
Deferred compensation plan (1)	1,447		—		—		1,447
Commodity derivatives (1)	—		13,156		—		13,156
Liabilities
Commodity derivatives (1)	$	—	$	10,003	$	—	$	10,003

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value Amounts of Derivative Instruments

The following table summarizes the location, as well as the gross and net fair value amounts, of all derivative instruments presented in the Unaudited Consolidated Balance Sheets as of the dates indicated.

	As of September 30, 2017
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	7,608		$	(1,826	)	(1)	$	5,782
Deferred financing costs and other noncurrent assets	603			(482		)	(1)	121
Total derivative assets	$	8,211		$	(2,308	)		$	5,903
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(1,826	)	$	1,826		(1)	$	—
Derivatives and other noncurrent liabilities	(640		)	482			(1)	(158		)
Total derivative liabilities	$	(2,466	)	$	2,308			$	(158	)
	As of December 31, 2016
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets	$	13,156		$	(4,758	)	(1)	$	8,398
Deferred financing costs and other noncurrent assets	—			—				—
Total derivative assets	$	13,156		$	(4,758	)		$	8,398
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Derivative liabilities	$	(9,104	)	$	4,758		(1)	$	(4,346	)
Derivatives and other noncurrent liabilities	(899		)	—				(899		)
Total derivative liabilities	$	(10,003	)	$	4,758			$	(5,245	)

(1) Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.

Financial Instruments for Hedging Volumes

As of September 30, 2017, the Company had financial derivative instruments in place related to the sale of a portion of the Company's production for the following volumes for the periods indicated:

	October – December 2017			For the year 2018			For the year 2019
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	747,500	$	57.69	2,506,750	$	52.47	547,500	$	50.38
Natural Gas (MMbtu)	920,000	$	2.96	1,825,000	$	2.68	—	$	—

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs (Tables)

9 Months Ended

Sep. 30, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Non-Cash Stock-Based Compensation Cost Related to Equity Awards

The following table presents the long-term cash and equity incentive compensation related to awards for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
	(in thousands)
Common stock options (1)	$	—	$	—	$	—		$	69
Nonvested common stock (1)	1,434		1,458		4,437			5,273
Nonvested common stock units (1)	174		165		516			711
Nonvested performance-based shares (1)	—		275		558			1,510
Nonvested performance cash units (2)(3)	1,073		242		(27		)	1,088
Total	$	2,681	$	2,140	$	5,484		$	8,651

(1) Unrecognized compensation cost as of September 30, 2017 was $6.8 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.7 years.

(2) The nonvested performance-based cash units are accounted for as liability awards with $1.1 million in accounts payable and accrued liabilities as of September 30, 2017 and $2.1 million and $2.9 million in derivatives and other noncurrent liabilities as of September 30, 2017 and December 31, 2016, respectively, in the Unaudited Consolidated Balance Sheets.

(3) Liability awards are fair valued at each reporting date. For the three months ended September 30, 2017, the weighted average fair value share price increased from $3.41 as of June 30, 2017 to $4.29 as of September 30, 2017. For the nine months ended September 30, 2017, the weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $4.29 as of September 30, 2017.

Stock Options and Nonvested Equity Shares, Equity Awards Granted

The following table presents the equity and cash awards granted pursuant to the Company's various stock compensation plans:

	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Equity Awards	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	5,267	$	3.31	—	$	—
Nonvested common stock units	3,787	$	4.29	2,922	$	5.56
Total granted	9,054			2,922
	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Cash Awards	Number of Units	Fair Value Per Unit		Number of Units	Fair Value Per Unit
Nonvested performance cash units	5,267	$	4.29	—	$	—
	Nine Months Ended September 30, 2017			Nine Months Ended September 30, 2016
Equity Awards	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	782,511	$	5.99	686,500	$	5.11
Nonvested common stock units	190,711	$	3.53	96,650	$	7.02
Total granted	973,222			783,150
	Nine Months Ended September 30, 2017			Nine Months Ended September 30, 2016
Cash Awards	Number of Units	Fair Value Per Unit		Number of Units	Fair Value Per Unit
Nonvested performance cash units	663,425	$	4.29	646,572	$	5.56

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of Aggregate Undiscounted Minimum Future Lease Payments

The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below. The Lease Financing Obligation contains an early buyout option pursuant to which the Company may purchase the equipment for $1.8 million on February 10, 2019.

	As of September 30, 2017
	(in thousands)
2017	$	135
2018	537
2019	1,824
Total	$	2,496

Gross Future Minimum Transportation Demand and Firm Processing Charges

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

	As of September 30, 2017
	(in thousands)
2017	$	4,634
2018	18,691
2019	18,691
2020	18,691
2021	10,902
Thereafter	—
Total	$	71,609

Future Minimum Annual Payments Under Drilling, Lease and Other Agreements

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

	As of September 30, 2017
	(in thousands)
2017	$	951
2018	3,038
2019	1,070
2020	113
2021	6
Thereafter	—
Total	$	5,178

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Guarantor Subsidiaries (Tables)

9 Months Ended

Sep. 30, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule of Condensed Consolidating Balance Sheets

Condensed Consolidating Balance Sheets

	As of September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	155,885		$	—		$	—		$	155,885
Accounts receivable, net of allowance for doubtful accounts	41,935			154			—			42,089
Other current assets	153,544			—			—			153,544
Property and equipment, net	970,444			5,401			—			975,845
Intercompany receivable	20,304			—			(20,304		)	—
Investment in subsidiaries	(14,811		)	—			14,811			—
Noncurrent assets	3,143			—			—			3,143
Total assets	$	1,330,444		$	5,555		$	(5,493	)	$	1,330,506
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	$	85,678		$	—		$	—		$	85,678
Other current liabilities	40,689			—			—			40,689
Intercompany payable	—			20,304			(20,304		)	—
Long-term debt	668,744			—			—			668,744
Other noncurrent liabilities	20,319			62			—			20,381
Stockholders' equity	515,014			(14,811		)	14,811			515,014
Total liabilities and stockholders' equity	$	1,330,444		$	5,555		$	(5,493	)	$	1,330,506

	As of December 31, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	275,841		$	—		$	—		$	275,841
Accounts receivable, net of allowance for doubtful accounts	32,659			178			—			32,837
Other current assets	9,774			—			—			9,774
Property and equipment, net	1,056,343			5,806			—			1,062,149
Intercompany receivable	20,678			—			(20,678		)	—
Investment in subsidiaries	(14,751		)	—			14,751			—
Noncurrent assets	4,740			—			—			4,740
Total assets	$	1,385,284		$	5,984		$	(5,927	)	$	1,385,341
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	$	49,447		$	—		$	—		$	49,447
Other current liabilities	35,571			—			—			35,571
Intercompany payable	—			20,678			(20,678		)	—
Long-term debt	711,808			—			—			711,808
Other noncurrent liabilities	16,915			57			—			16,972
Stockholders' equity	571,543			(14,751		)	14,751			571,543
Total liabilities and stockholders' equity	$	1,385,284		$	5,984		$	(5,927	)	$	1,385,341

Schedule of Condensed Consolidating Statements of Operations

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	67,697		$	168		$	—		$	67,865
Operating expenses	(58,053		)	(156		)	—			(58,209		)
General and administrative	(12,496		)	—			—			(12,496		)
Interest expense	(13,926		)	—			—			(13,926		)
Interest income and other income (expense)	(12,076		)	—			—			(12,076		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(28,854		)	12			—			(28,842		)
(Provision for) Benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	12			—			(12		)	—
Net income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	169,041		$	426		$	—		$	169,467
Operating expenses	(167,363		)	(486		)	—			(167,849		)
General and administrative	(30,788		)	—			—			(30,788		)
Interest expense	(44,014		)	—			—			(44,014		)
Interest income and other income (expense)	12,780			—			—			12,780
Income (loss) before income taxes and equity in earnings of subsidiaries	(60,344		)	(60		)	—			(60,404		)
(Provision for) benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	(60		)	—			60			—
Net income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)

	Three Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	50,325		$	156		$	—		$	50,481
Operating expenses	(59,498		)	(155		)	—			(59,653		)
General and administrative	(9,178		)	—			—			(9,178		)
Interest expense	(13,991		)	—			—			(13,991		)
Interest and other income (expense)	6,155			—			—			6,155
Income (loss) before income taxes and equity in earnings of subsidiaries	(26,187		)	1			—			(26,186		)
(Provision for) Benefit from income taxes	—			—			—			—
Equity in earnings of subsidiaries	1			—			(1		)	—
Net income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating revenues	$	126,730		$	469		$	—		$	127,199
Operating expenses	(172,759		)	(480		)	—			(173,239		)
General and administrative	(31,535		)	—			—			(31,535		)
Interest expense	(45,160		)	—			—			(45,160		)
Interest and other income (expense)	1,634			—			—			1,634
Income (loss) before income taxes and equity in earnings of subsidiaries	(121,090		)	(11		)	—			(121,101		)
(Provision for) benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	(11		)	—			11			—
Net income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)

Schedule of Condensed Consolidating Statements of Comprehensive Income (Loss)

Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(28,842	)	$	12		$	(12	)	$	(28,842	)
	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(60,404	)	$	(60	)	$	60		$	(60,404	)

	Three Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(26,186	)	$	1		$	(1	)	$	(26,186	)
	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)
Other comprehensive income (loss)	—			—			—			—
Comprehensive income (loss)	$	(121,101	)	$	(11	)	$	11		$	(121,101	)

Schedule of Condensed Consolidating Statements of Cash Flows

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2017
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	95,009		$	374		$	—		$	95,383
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(160,788		)	—			—			(160,788		)
Additions to furniture, fixtures and other	(268		)	—			—			(268		)
Proceeds from sale of properties and other investing activities	(712		)	—			—			(712		)
Intercompany transfers	374			—			(374		)	—
Cash flows from financing activities:
Proceeds from debt	275,000			—			—			275,000
Principal payments on debt	(322,228		)	—			—			(322,228		)
Proceeds from sale of common stock, net of offering costs	(298		)	—			—			(298		)
Intercompany transfers	—			(374		)	374			—
Other financing activities	(6,045		)	—			—			(6,045		)
Change in cash and cash equivalents	(119,956		)	—			—			(119,956		)
Beginning cash and cash equivalents	275,841			—			—			275,841
Ending cash and cash equivalents	$	155,885		$	—		$	—		$	155,885

	Nine Months Ended September 30, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	115,695		$	512		$	—		$	116,207
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(93,686		)	(18		)	—			(93,704		)
Additions to furniture, fixtures and other	(1,184		)	—			—			(1,184		)
Proceeds from sale of properties and other investing activities	25,571			—			—			25,571
Intercompany transfers	494			—			(494		)	—
Cash flows from financing activities:
Principal payments on debt	(329		)	—			—			(329		)
Intercompany transfers	—			(494		)	494			—
Other financing activities	(1,134		)	—			—			(1,134		)
Change in cash and cash equivalents	45,427			—			—			45,427
Beginning cash and cash equivalents	128,836			—			—			128,836
Ending cash and cash equivalents	$	174,263		$	—		$	—		$	174,263

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Summary of Significant Accounting Policies - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2017 USD ($)
Property, Plant and Equipment [Line Items]
Oil and Gas Properties Held for Sale, Net of DD&A and Impairment	$ 145,100,000
Cumulative effect of accounting change	329,000
Environmental Remediation Expense	800,000
Oil And Gas Properties Held For Sale, Proved	410,700,000
Oil And Gas Properties Held For Sale, Unproved	400,000
Accumulated Depreciation, Depletion, Amortization And Impairment Associated With Assets Held For Sale	266,000,000
Additional Paid-In Capital
Property, Plant and Equipment [Line Items]
Cumulative effect of accounting change	$ (180,000.0)

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Summary of Significant Accounting Policies - Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (259)	$ (23)
Accounts receivable	42,089	32,837
Accrued Oil, Gas, and NGL Sales
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable gross	33,170	26,542
Due from Joint Interest Owners
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable gross	9,164	4,366
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable gross	$ 14	$ 1,952

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Summary of Significant Accounting Policies - Net Capitalized Costs and Associated Accumulated Depreciation, Depletion & Amortization and Non Cash Impairments (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Proved properties	$ 218,746	$ 306,075
Wells and related equipment and facilities	1,035,764	1,164,354
Support equipment and facilities	34,317	63,238
Materials and supplies	3,959	5,706
Total proved oil and gas properties (1)	1,292,786	1,539,373
Unproved properties	33,713	27,790
Wells and facilities in progress	36,822	31,040
Total unproved oil and gas properties, excluded from amortization (1)	70,535	58,830
Accumulated depreciation, depletion, amortization and impairment (1)	(393,340)	(543,154)
Total oil and gas properties, net (1)	$ 969,981	$ 1,055,049

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Summary of Significant Accounting Policies - Non-Cash Impairment Charges, Included within Impairment, Dry Hole Costs and Abandonment Expense in Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Summary Of Significant Accounting Policies [Line Items]
Dry hole costs	$ 0	$ 1	$ 0	$ 71
Abandonment expense and lease expirations	261	973	326	1,512
Impairment, dry hole costs and abandonment expense	261	974	8,336	1,766
Unproved Oil And Gas Properties
Summary Of Significant Accounting Policies [Line Items]
Non-cash impairment of oil and gas properties	$ 0	$ 0	$ 8,010	$ 183

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Summary of Significant Accounting Policies - Accounts Payable and Accrued Liabilities (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Accrued drilling, completion and facility costs	$ 33,325	$ 15,594
Accrued lease operating, gathering, transportation and processing expenses	4,589	4,261
Accrued general and administrative expenses	8,653	6,375
Accrued interest payable	23,500	12,264
Prepayments from partners	11,249	332
Trade payables	2,323	7,900
Other	2,039	2,721
Total accounts payable and accrued liabilities	$ 85,678	$ 49,447

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Summary of Significant Accounting Policies - Calculation of Basic and Diluted Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Accounting Policies [Abstract]
Net Income (Loss)	$ (28,842)	$ (26,186)	$ (60,404)	$ (121,101)	$ (170,378)
Basic weighted-average common shares outstanding in period (in shares)	74,886,107	58,851,598	74,742,699	53,081,809
Diluted weighted-average common shares outstanding in period (in shares)	74,886,107	58,851,598	74,742,699	53,081,809
Net Income (Loss) Per Common Share, Basic (in dollars per share)	$ (0.39)	$ (0.44)	$ (0.81)	$ (2.28)
Net Income (Loss) Per Common Share, Diluted (in dollars per share)	$ (0.39)	$ (0.44)	$ (0.81)	$ (2.28)

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Supplemental Disclosures of Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 31,113	$ 31,736
Cash paid for income taxes	0	0
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	37,319	8,318
Change in asset retirement obligations, net of disposals	10,453	(4,788)
Retirement of treasury stock	(1,246)	(1,098)
Properties exchanged in non-cash transactions	13,323	0
Fair value of debt exchanged for common stock (1)	$ 0	$ 74,400

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Acquisitions, Exchanges, Divestitures and Assets Held for Sale (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2017 USD ($) transaction	Dec. 31, 2016 USD ($)
Property, Plant and Equipment [Line Items]
Liabilities associated with assets held for sale	$ 4,856,000	$ 0
Asset Retirement Obligations Acquisition of Properties	$ 8,700,000
Number of acreage transactions to consolidate acreage positions | transaction	2
Proceeds from Divestiture of Businesses		27,800,000
Liabilities associated with assets sold		4,800,000
Proved Oil And Gas Properties Sold, Net Of DD&A And Impairment		30,600,000
Unproved Oil And Gas Properties Sold		2,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		$ 0
Proved Oil And Gas Properties
Property, Plant and Equipment [Line Items]
Acquisition Costs, Period Cost	$ 9,100,000
Unproved Oil And Gas Properties
Property, Plant and Equipment [Line Items]
Acquisition Costs, Period Cost	$ 11,200,000

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Long-Term Debt - Outstanding Debt (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2017	Apr. 28, 2017	Dec. 31, 2016	Mar. 12, 2012	Sep. 27, 2011
Debt Instrument [Line Items]
Principal amount of debt instrument	$ 676,978,000		$ 718,207,000
Unamortized Debt Issuance Expense	(8,234,000)		(6,399,000)
Carrying Amount	668,744,000		711,808,000
Debt, fair value	653,100,000		699,000,000
Amended Credit Facility
Debt Instrument [Line Items]
Principal amount of debt instrument	0		0
Unamortized Debt Issuance Expense	0		0
Carrying Amount	0		0
Debt, fair value	0
Convertible Notes
Debt Instrument [Line Items]
Principal amount of debt instrument	0		579,000
Unamortized Debt Issuance Expense	0		0
Carrying Amount	0		579,000
Debt, fair value			500,000
Debt, fair value			500,000
7.625% Senior Notes
Debt Instrument [Line Items]
Principal amount of debt instrument	0		315,300,000		$ 400,000,000.0
Unamortized Debt Issuance Expense	0		(2,169,000)
Carrying Amount	$ 0		313,131,000
Debt, stated interest rate	7.625%
Debt, fair value			314,500,000
7.0% Senior Notes
Debt Instrument [Line Items]
Maturity Date	Oct. 15, 2022
Principal amount of debt instrument	$ 400,000,000		400,000,000	$ 400,000,000.0
Unamortized Debt Issuance Expense	(3,684,000)		(4,227,000)
Carrying Amount	$ 396,316,000		395,773,000
Debt, stated interest rate	7.00%
Debt, fair value	$ 386,300,000		384,500,000
8.75% Senior Notes
Debt Instrument [Line Items]
Maturity Date	Jun. 15, 2025
Principal amount of debt instrument	$ 275,000,000	$ 275,000,000.0	0
Unamortized Debt Issuance Expense	(4,548,000)		0
Carrying Amount	$ 270,452,000		0
Debt, stated interest rate	8.75%
Debt, fair value	$ 266,800,000
Lease Financing Obligation
Debt Instrument [Line Items]
Maturity Date	Aug. 10, 2020
Principal amount of debt instrument	$ 2,443,000		2,782,000
Unamortized Debt Issuance Expense	(2,000)		(3,000)
Carrying Amount	2,441,000		2,779,000
Debt, fair value	2,300,000		2,600,000
Long-term Debt
Debt Instrument [Line Items]
Principal amount of debt instrument	677,443,000		718,661,000
Unamortized Debt Issuance Expense	(8,234,000)		(6,399,000)
Carrying Amount	669,209,000		712,262,000
Current Portion of Long-Term Debt
Debt Instrument [Line Items]
Principal amount of debt instrument	465,000		454,000
Unamortized Debt Issuance Expense	0		0
Carrying Amount	$ 465,000		$ 454,000

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Long-Term Debt - Additional Information (Detail)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) Lenders	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($) shares	Apr. 28, 2017 USD ($)	Mar. 12, 2012 USD ($)	Sep. 27, 2011 USD ($)
Debt Instrument [Line Items]
Principal amount	$ 676,978,000		$ 676,978,000		$ 718,207,000
Gain (loss) on extinguishment of debt	0	$ 29,000	(7,904,000)	$ 8,726,000
Debt, fair value	653,100,000		653,100,000		699,000,000
Purchase of equipment	$ 1,800,000		$ 1,800,000
Minimum
Debt Instrument [Line Items]
Revolving credit facility interest rate percent above LIBOR alternate interest rate			0.50%
Commitment fee percentage	0.375%		0.375%
Revolving Credit Facility Interest Rate Percent Above Libor			1.50%
Maximum
Debt Instrument [Line Items]
Revolving credit facility interest rate percent above LIBOR alternate interest rate			1.50%
Commitment fee percentage	0.50%		0.50%
Revolving Credit Facility Interest Rate Percent Above Libor			2.50%
Amended Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 300,000,000		$ 300,000,000
Number of Lenders, Credit Facility | Lenders			13
Letters of credit issued amount	26,000,000		$ 26,000,000
Line of credit facility, remaining borrowing capacity	274,000,000		274,000,000
Principal amount	0		0		0
Debt, fair value	0		0
5% Convertible Senior Notes
Debt Instrument [Line Items]
Face Amount of Outstanding Convertible Notes Repaid	600,000		600,000
Convertible Notes
Debt Instrument [Line Items]
Debt, fair value					500,000
Principal amount	0		0		579,000
Debt, fair value					500,000
7.625% Senior Notes
Debt Instrument [Line Items]
Principal amount	$ 0		0		315,300,000			$ 400,000,000.0
Gain (loss) on extinguishment of debt			$ (7,900,000)		8,700,000
Debt, stated interest rate	7.625%		7.625%
Face Amount Of Outstanding 7.625% Senior Notes Repaid	$ 315,300,000		$ 315,300,000
Debt, fair value					314,500,000
Face Amount of Outstanding 7.625% Senior Notes Exchanged for Common Stock					$ 84,700,000
Shares issued for debt exchange (in shares) | shares					10,000,000
7.0% Senior Notes
Debt Instrument [Line Items]
Debt instrument, maturity date			Oct. 15, 2022
Principal amount	$ 400,000,000		$ 400,000,000		$ 400,000,000		$ 400,000,000.0
Debt, stated interest rate	7.00%		7.00%
Debt, fair value	$ 386,300,000		$ 386,300,000		384,500,000
8.75% Senior Notes
Debt Instrument [Line Items]
Debt instrument, maturity date			Jun. 15, 2025
Principal amount	$ 275,000,000		$ 275,000,000		0	$ 275,000,000.0
Debt, stated interest rate	8.75%		8.75%
Debt, fair value	$ 266,800,000		$ 266,800,000
Lease Financing Obligation
Debt Instrument [Line Items]
Debt instrument, maturity date			Aug. 10, 2020
Principal amount	2,443,000		$ 2,443,000		2,782,000
Debt, fair value	$ 2,300,000		$ 2,300,000		$ 2,600,000
Weighted average implicit rate based on interest expense	3.30%		3.30%
2017 [Member] | 7.0% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			103.50%
2018 [Member] | 7.0% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			102.333%
2019 [Member] | 7.0% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			101.167%
2020 [Member] | 8.75% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			106.563%
2021 [Member] | 8.75% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			104.375%
2022 [Member] | 7.0% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			100.00%
2022 [Member] | 8.75% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			102.188%
2023 [Member] | 8.75% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			100.00%
Prior to June 15, 2020 [Member] | 8.75% Senior Notes
Debt Instrument [Line Items]
Par value of senior notes			100.00%
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			35.00%
Redemption Price As Percentage Of Principal Redeemed If Equity Offering Proceeds Used			108.75%

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Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2017 USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Acquisition of Properties	$ 8,700
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
As of December 31, 2016	11,238
Liabilities incurred (1)	10,379
Liabilities settled	(814)
Disposition of properties	(6)
Accretion expense	765
Revisions to estimate	894
As of September 30, 2017	22,456
Less: liabilities associated with assets held for sale	4,856
Less: current asset retirement obligations	1,829
Long-term asset retirement obligations	$ 15,771

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Fair Value Measurements - Fair Value, Balance Sheet Grouping (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	$ 70,535	$ 58,830
Assets
Cash equivalents	155,885	275,841	$ 174,263	$ 128,836
Commodity derivatives	5,903	8,398
Liabilities
Commodity derivatives	158	5,245
Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	1,088
Assets
Cash equivalents	110,772	40,115
Deferred compensation plan	1,719	1,447
Commodity derivatives	8,211	13,156
Liabilities
Commodity derivatives	2,466	10,003
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	0
Assets
Cash equivalents	110,772	40,115
Deferred compensation plan	1,719	1,447
Commodity derivatives	0	0
Liabilities
Commodity derivatives	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	0
Assets
Cash equivalents	0	0
Deferred compensation plan	0	0
Commodity derivatives	8,211	13,156
Liabilities
Commodity derivatives	2,466	10,003
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	1,088
Assets
Cash equivalents	0	0
Deferred compensation plan	0	0
Commodity derivatives	0	0
Liabilities
Commodity derivatives	$ 0	$ 0

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Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Fair Value Measurements [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	$ 70,535,000		$ 70,535,000		$ 58,830,000
Property, Plant, and Equipment, Fair Value Disclosure					0
Debt, fair value	653,100,000		653,100,000		699,000,000
Gain (Loss) on Extinguishment of Debt	$ 0	$ 29,000	$ (7,904,000)	$ 8,726,000
7.625% Senior Notes
Fair Value Measurements [Line Items]
Debt, stated interest rate	7.625%		7.625%
Debt, fair value					314,500,000
Gain (Loss) on Extinguishment of Debt			$ (7,900,000)		8,700,000
7.0% Senior Notes
Fair Value Measurements [Line Items]
Debt, stated interest rate	7.00%		7.00%
Debt, fair value	$ 386,300,000		$ 386,300,000		384,500,000
Amended Credit Facility
Fair Value Measurements [Line Items]
Debt, fair value	0		0
Convertible Notes
Fair Value Measurements [Line Items]
Debt, fair value					500,000
Lease Financing Obligation
Fair Value Measurements [Line Items]
Debt, fair value	2,300,000		2,300,000		$ 2,600,000
Level 3
Fair Value Measurements [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	1,088,000		1,088,000
Acquisition Costs, Period Cost			11,600,000
Unproved Oil And Gas Properties
Fair Value Measurements [Line Items]
Acquisition Costs, Period Cost			11,200,000
Impairment of Oil and Gas Properties	$ 0	$ 0	$ 8,010,000	$ 183,000

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Derivative Instruments - Fair Value Amounts of Derivative Instruments (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets	$ 8,211	$ 13,156
Gross Amounts Offset in the Balance Sheet	(2,308)	(4,758)
Net Amounts of Assets Presented in the Balance Sheet	5,903	8,398
Gross Amounts of Recognized Liabilities	(2,466)	(10,003)
Gross Amounts Offset in the Balance Sheet	2,308	4,758
Net Amounts of Liabilities Presented in the Balance Sheet	(158)	(5,245)
Derivative assets
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets	7,608	13,156
Gross Amounts Offset in the Balance Sheet	(1,826)	(4,758)
Net Amounts of Assets Presented in the Balance Sheet	5,782	8,398
Deferred financing costs and other noncurrent assets
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets	603	0
Gross Amounts Offset in the Balance Sheet	(482)	0
Net Amounts of Assets Presented in the Balance Sheet	121	0
Derivative liabilities
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(1,826)	(9,104)
Gross Amounts Offset in the Balance Sheet	1,826	4,758
Net Amounts of Liabilities Presented in the Balance Sheet	0	(4,346)
Derivatives and other noncurrent liabilities
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(640)	(899)
Gross Amounts Offset in the Balance Sheet	482	0
Net Amounts of Liabilities Presented in the Balance Sheet	$ (158)	$ (899)

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Derivative Instruments - Financial Instruments for Hedging Volume (Detail)	Sep. 30, 2017 USD ($) MMBTU bbl
October – December 2017
Derivative Instruments, Gain (Loss) [Line Items]
Oil (Bbls) | bbl	747,500
Weighted Average Price, Hedge Backed Oil Volumes	$ 57.69
Natural Gas (MMbtu) | MMBTU	920,000
Weighted Average Price, Hedge Backed Gas Volumes	$ 2.96
For the year 2018
Derivative Instruments, Gain (Loss) [Line Items]
Oil (Bbls) | bbl	2,506,750
Weighted Average Price, Hedge Backed Oil Volumes	$ 52.47
Natural Gas (MMbtu) | MMBTU	1,825,000
Weighted Average Price, Hedge Backed Gas Volumes	$ 2.68
For the year 2019
Derivative Instruments, Gain (Loss) [Line Items]
Oil (Bbls) | bbl	547,500
Weighted Average Price, Hedge Backed Oil Volumes	$ 50.38
Natural Gas (MMbtu) | MMBTU	0
Weighted Average Price, Hedge Backed Gas Volumes	$ 0.00

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Derivative Instruments - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2017 Counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties for hedges at period end	6

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Income Taxes (Details)	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Effective income tax rate (percent)	0.00%

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Stockholders' Equity (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016	Mar. 31, 2017
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	75,000,000
Maximum Aggregate Offering Price	$ 100,000,000.0
Number of shares sold, equity distribution agreement (in shares)	0
Common Stock, Par or Stated Value Per Share (in dollars per share)	$ 0.001	$ 0.001
Preferred Stock, Par or Stated Value Per Share	$ 0.001
Common Stock, Shares Authorized	300,000,000	150,000,000	150,000,000
Preferred Stock, Shares Outstanding	0
7.625% Senior Notes
Class of Stock [Line Items]
Shares issued for debt exchange (in shares)		10,000,000
Debt, stated interest rate	7.625%
Face Amount of Outstanding 7.625% Senior Notes Exchanged for Common Stock		$ 84,700,000

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs - Non-Cash Stock-Based Compensation Cost Related to Equity Awards (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	$ 2,681	$ 2,140	$ 5,484	$ 8,651
Common Stock Options
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	0	0	0	69
Nonvested Equity Common Stock
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	1,434	1,458	4,437	5,273
Nonvested Equity Common Stock Units
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	174	165	516	711
Nonvested Performance-Based Equity
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	0	275	558	1,510
Nonvested Performance Cash Units
Stock Based Compensation [Line Items]
Cash Unit Based Compensation Awards	$ 1,073	$ 242	$ (27)	$ 1,088

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs - Additional Information (Detail) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) shares $ / shares $ / unit	Sep. 30, 2016 shares	Sep. 30, 2017 USD ($) shares $ / shares $ / unit	Sep. 30, 2016 shares	Jun. 30, 2017 $ / unit	Dec. 31, 2016 USD ($) $ / unit
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Cash program vesting period			3 years
Closing Share Price, December 30, 2016 (in dollars per share) | $ / shares	$ 6.99		$ 6.99
One Percent Vest For Each One Percent Growth			1.00%
Payout If Share Price Less Than $6.99			0
Payout If Relative TSR Is Less Than Median			0
Weighted Average Fair Value Price Per Unit, Liability Awards (in dollars per share) | $ / unit	4.29		4.29		3.41	8.89
Unrecognized compensation cost	$ 6.8		$ 6.8
Weighted-average period (years)			1 year 8 months 12 days
Nonvested Performance Cash Units
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred Compensation Cash-based Arrangements, Liability, Current	1.1		$ 1.1
Deferred Compensation Cash-based Arrangements, Liability, Classified, Noncurrent	$ 2.1		$ 2.1			$ 2.9
Number Of Performance Cash Units Granted (in shares) | shares	5,267	0	663,425	646,572
Absolute Performance
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Award vesting rights, percentage			100.00%
Relative TSR
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Award vesting rights, percentage			100.00%
Absolute Performance and Relative TSR | Maximum
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Award vesting rights, percentage			200.00%

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs - Stock Options and Nonvested Equity Shares, Equity Awards Granted (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2017 $ / shares $ / unit shares	Sep. 30, 2016 $ / shares $ / unit shares	Sep. 30, 2017 $ / shares $ / unit shares	Sep. 30, 2016 $ / shares $ / unit shares
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Nonvested equity shares, Number of Shares (in shares)	5,267	0	782,511	686,500
Nonvested equity common stock units, Number of Shares (in shares)	3,787	2,922	190,711	96,650
Total shares granted (in shares)	9,054	2,922	973,222	783,150
Nonvested equity shares, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares	$ 3.31	$ 0.00	$ 5.99	$ 5.11
Nonvested equity common stock units, Weighted Average Grant Date Fair Value (in dollars per share) | $ / shares	$ 4.29	$ 5.56	$ 3.53	$ 7.02
Performance Cash Unit, Fair Value Per Unit (in dollars per share) | $ / unit	4.29	0.00	4.29	5.56

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Commitments and Contingencies - Schedule of Aggregate Undiscounted Minimum Future Lease Payments (Detail) - Lease Financing Obligation $ in Thousands	Sep. 30, 2017 USD ($)
Future Minimum Lease Payments Under Capital Leases And Operating Leases For Continuing Operations [Line Items]
2017	$ 135
2018	537
2019	1,824
Total	$ 2,496

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Commitments and Contingencies - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($) Agreement
Contingencies And Commitments [Line Items]
Sale Leaseback Transaction Early Buyout Option To Purchase Equipment | $	$ 1.8
Number of Firm Transportation Contracts | Agreement	2

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Commitments and Contingencies - Gross Future Minimum Transportation Demand and Firm Processing Charges (Detail) $ in Thousands	Sep. 30, 2017 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2017	$ 4,634
2018	18,691
2019	18,691
2020	18,691
2021	10,902
Thereafter	0
Total	$ 71,609

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Commitments and Contingencies - Future Minimum Annual Payments under Drilling, Lease and Other Agreements (Detail) - Office & Equipment Leases $ in Thousands	Sep. 30, 2017 USD ($)
Operating Leased Assets [Line Items]
2017	$ 951
2018	3,038
2019	1,070
2020	113
2021	6
Thereafter	0
Total	$ 5,178

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Guarantor Subsidiaries - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2017
Condensed Financial Statements, Captions [Line Items]
Percentage of guarantor subsidiaries	100.00%
7.625% Senior Notes
Condensed Financial Statements, Captions [Line Items]
Debt, stated interest rate	7.625%
7.0% Senior Notes
Condensed Financial Statements, Captions [Line Items]
Debt, stated interest rate	7.00%
8.75% Senior Notes
Condensed Financial Statements, Captions [Line Items]
Debt, stated interest rate	8.75%

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Guarantor Subsidiaries - Schedule of Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Assets:
Cash and cash equivalents	$ 155,885	$ 275,841	$ 174,263	$ 128,836
Accounts receivable, net of allowance for doubtful accounts	42,089	32,837
Other current assets	153,544	9,774
Property and equipment, net	975,845	1,062,149
Intercompany receivable (payable)	0	0
Investment in subsidiaries	0	0
Noncurrent assets	3,143	4,740
Total	1,330,506	1,385,341
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	85,678	49,447
Current liabilities	40,689	35,571
Intercompany payable	0	0
Long-term debt, net of debt issuance costs	668,744	711,808
Other noncurrent liabilities	20,381	16,972
Stockholders' equity	515,014	571,543		549,416
Total liabilities and stockholders' equity	1,330,506	1,385,341
Reportable Legal Entities | Parent Issuer
Assets:
Cash and cash equivalents	155,885	275,841	174,263	128,836
Accounts receivable, net of allowance for doubtful accounts	41,935	32,659
Other current assets	153,544	9,774
Property and equipment, net	970,444	1,056,343
Intercompany receivable (payable)	20,304	20,678
Investment in subsidiaries	(14,811)	(14,751)
Noncurrent assets	3,143	4,740
Total	1,330,444	1,385,284
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	85,678	49,447
Current liabilities	40,689	35,571
Intercompany payable	0	0
Long-term debt, net of debt issuance costs	668,744	711,808
Other noncurrent liabilities	20,319	16,915
Stockholders' equity	515,014	571,543
Total liabilities and stockholders' equity	1,330,444	1,385,284
Reportable Legal Entities | Guarantor Subsidiaries
Assets:
Cash and cash equivalents	0	0	0	0
Accounts receivable, net of allowance for doubtful accounts	154	178
Other current assets	0	0
Property and equipment, net	5,401	5,806
Intercompany receivable (payable)	0	0
Investment in subsidiaries	0	0
Noncurrent assets	0	0
Total	5,555	5,984
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	0	0
Current liabilities	0	0
Intercompany payable	20,304	20,678
Long-term debt, net of debt issuance costs	0	0
Other noncurrent liabilities	62	57
Stockholders' equity	(14,811)	(14,751)
Total liabilities and stockholders' equity	5,555	5,984
Intercompany Eliminations
Assets:
Cash and cash equivalents	0	0	$ 0	$ 0
Accounts receivable, net of allowance for doubtful accounts	0	0
Other current assets	0	0
Property and equipment, net	0	0
Intercompany receivable (payable)	(20,304)	(20,678)
Investment in subsidiaries	14,811	14,751
Noncurrent assets	0	0
Total	(5,493)	(5,927)
Liabilities and Stockholders' Equity:
Accounts payable and accrued liabilities	0	0
Current liabilities	0	0
Intercompany payable	(20,304)	(20,678)
Long-term debt, net of debt issuance costs	0	0
Other noncurrent liabilities	0	0
Stockholders' equity	14,811	14,751
Total liabilities and stockholders' equity	$ (5,493)	$ (5,927)

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Guarantor Subsidiaries - Schedule of Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Operating revenues	$ 67,865	$ 50,481	$ 169,467	$ 127,199
Operating expenses	(58,209)	(59,653)	(167,849)	(173,239)
General and administrative	(12,496)	(9,178)	(30,788)	(31,535)
Interest Expense	(13,926)	(13,991)	(44,014)	(45,160)
Interest income and other income (expense)	(12,076)	6,155	12,780	1,634
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	(28,842)	(26,186)	(60,404)	(121,101)
(Provision for) Benefit from Income Taxes	0	0	0	0
Equity in earnings (loss) of subsidiaries	0	0	0	0
Net Income (Loss)	(28,842)	(26,186)	(60,404)	(121,101)	$ (170,378)
Reportable Legal Entities | Parent Issuer
Condensed Financial Statements, Captions [Line Items]
Operating revenues	67,697	50,325	169,041	126,730
Operating expenses	(58,053)	(59,498)	(167,363)	(172,759)
General and administrative	(12,496)	(9,178)	(30,788)	(31,535)
Interest Expense	(13,926)	(13,991)	(44,014)	(45,160)
Interest income and other income (expense)	(12,076)	6,155	12,780	1,634
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	(28,854)	(26,187)	(60,344)	(121,090)
(Provision for) Benefit from Income Taxes	0	0	0	0
Equity in earnings (loss) of subsidiaries	12	1	(60)	(11)
Net Income (Loss)	(28,842)	(26,186)	(60,404)	(121,101)
Reportable Legal Entities | Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Operating revenues	168	156	426	469
Operating expenses	(156)	(155)	(486)	(480)
General and administrative	0	0	0	0
Interest Expense	0	0	0	0
Interest income and other income (expense)	0	0	0	0
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	12	1	(60)	(11)
(Provision for) Benefit from Income Taxes	0	0	0	0
Equity in earnings (loss) of subsidiaries	0	0	0	0
Net Income (Loss)	12	1	(60)	(11)
Intercompany Eliminations
Condensed Financial Statements, Captions [Line Items]
Operating revenues	0	0	0	0
Operating expenses	0	0	0	0
General and administrative	0	0	0	0
Interest Expense	0	0	0	0
Interest income and other income (expense)	0	0	0	0
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	0	0	0	0
(Provision for) Benefit from Income Taxes	0	0	0	0
Equity in earnings (loss) of subsidiaries	(12)	(1)	60	11
Net Income (Loss)	$ (12)	$ (1)	$ 60	$ 11

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Guarantor Subsidiaries - Schedule of Condensed Consolidating Statements of Comprehensive Income (Loss) (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ (28,842)	$ (26,186)	$ (60,404)	$ (121,101)	$ (170,378)
Other comprehensive income (loss)	0	0	0	0
Comprehensive Income (Loss)	(28,842)	(26,186)	(60,404)	(121,101)
Reportable Legal Entities | Parent Issuer
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(28,842)	(26,186)	(60,404)	(121,101)
Other comprehensive income (loss)	0	0	0	0
Comprehensive Income (Loss)	(28,842)	(26,186)	(60,404)	(121,101)
Reportable Legal Entities | Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	12	1	(60)	(11)
Other comprehensive income (loss)	0	0	0	0
Comprehensive Income (Loss)	12	1	(60)	(11)
Intercompany Eliminations
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(12)	(1)	60	11
Other comprehensive income (loss)	0	0	0	0
Comprehensive Income (Loss)	$ (12)	$ (1)	$ 60	$ 11

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Guarantor Subsidiaries - Schedule of Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	$ 95,383	$ 116,207
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(160,788)	(93,704)
Additions to furniture, fixtures and other	(268)	(1,184)
Proceeds from sale of properties and other investing activities	(712)	25,571
Intercompany transfers	0	0
Cash flows from financing activities:
Proceeds from debt	275,000
Principal payments on debt	(322,228)	(329)
Proceeds from sale of common stock, net of offering costs	(298)	0
Intercompany transfers	0	0
Other financing activities	(6,045)	(1,134)
Increase (Decrease) in Cash and Cash Equivalents	(119,956)	45,427
Beginning Cash and Cash Equivalents	275,841	128,836
Ending Cash and Cash Equivalents	155,885	174,263
Reportable Legal Entities | Parent Issuer
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	95,009	115,695
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(160,788)	(93,686)
Additions to furniture, fixtures and other	(268)	(1,184)
Proceeds from sale of properties and other investing activities	(712)	25,571
Intercompany transfers	374	494
Cash flows from financing activities:
Proceeds from debt	275,000
Principal payments on debt	(322,228)	(329)
Proceeds from sale of common stock, net of offering costs	(298)
Intercompany transfers	0	0
Other financing activities	(6,045)	(1,134)
Increase (Decrease) in Cash and Cash Equivalents	(119,956)	45,427
Beginning Cash and Cash Equivalents	275,841	128,836
Ending Cash and Cash Equivalents	155,885	174,263
Reportable Legal Entities | Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	374	512
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	0	(18)
Additions to furniture, fixtures and other	0	0
Proceeds from sale of properties and other investing activities	0	0
Intercompany transfers	0	0
Cash flows from financing activities:
Proceeds from debt	0
Principal payments on debt	0	0
Proceeds from sale of common stock, net of offering costs	0
Intercompany transfers	(374)	(494)
Other financing activities	0	0
Increase (Decrease) in Cash and Cash Equivalents	0	0
Beginning Cash and Cash Equivalents	0	0
Ending Cash and Cash Equivalents	0	0
Consolidation, Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	0	0
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	0	0
Additions to furniture, fixtures and other	0	0
Proceeds from sale of properties and other investing activities	0	0
Intercompany transfers	(374)	(494)
Cash flows from financing activities:
Proceeds from debt	0
Principal payments on debt	0	0
Proceeds from sale of common stock, net of offering costs	0
Intercompany transfers	374	494
Other financing activities	0	0
Increase (Decrease) in Cash and Cash Equivalents	0	0
Beginning Cash and Cash Equivalents	0	0
Ending Cash and Cash Equivalents	$ 0	$ 0