BBG Bill Barrett Corp. (delisted)

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.)

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

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PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2016				December 31, 2015
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	174,263			$	128,836
Accounts receivable, net of allowance for doubtful accounts	29,909				43,461
Derivative assets	30,740				99,809
Prepayments and other current assets	1,948				2,211
Total current assets	236,860				274,317
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	1,531,367				2,000,210
Unproved oil and gas properties, excluded from amortization	40,735				79,198
Furniture, equipment and other	27,094				26,021
	1,599,196				2,105,429
Accumulated depreciation, depletion, amortization and impairment	(518,130		)		(934,745		)
Total property and equipment, net	1,081,066				1,170,684
Deferred income taxes	10,075				38,219
Derivative assets	3,338				19,662
Deferred financing costs and other noncurrent assets	4,214				3,638
Total	$	1,335,553			$	1,506,520
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities	$	56,604			$	64,337
Amounts payable to oil and gas property owners	12,763				15,657
Production taxes payable	19,890				26,578
Deferred income taxes	10,075				38,219
Current portion of long-term debt	450				440
Total current liabilities	99,782				145,231
Long-term debt, net of debt issuance costs	711,544				794,652
Asset retirement obligations	10,632				14,066
Derivatives and other noncurrent liabilities	4,416				3,155
Stockholders' equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 60,200,546 and 49,864,512 shares issued and outstanding at September 30, 2016 and December 31, 2015, respectively, with 1,337,881 and 1,471,508 shares subject to restrictions, respectively	59				48
Additional paid-in capital	1,002,171				921,318
Retained earnings (Accumulated deficit)	(493,051		)		(371,950		)
Treasury stock, at cost: zero shares at September 30, 2016 and December 31, 2015, respectively	—				—
Total stockholders' equity	509,179				549,416
Total	$	1,335,553			$	1,506,520

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

	Three Months Ended September 30,								Nine Months Ended September 30,
	2016				2015				2016				2015
	(in thousands, except share and per share data)
Operating and Other Revenues:
Oil, gas and NGL production	$	50,133			$	48,799			$	126,279			$	158,667
Other	348				880				920				2,664
Total operating and other revenues	50,481				49,679				127,199				161,331
Operating Expenses:
Lease operating expense	4,795				9,638				22,101				34,834
Gathering, transportation and processing expense	472				684				1,871				2,559
Production tax expense	3,832				3,670				7,037				10,020
Exploration expense	16				20				64				145
Impairment, dry hole costs and abandonment expense	974				572,651				1,766				574,996
(Gain) Loss on divestitures	1,914				(77		)		1,206				(759		)
Depreciation, depletion and amortization	43,083				54,738				125,491				159,666
Unused commitments	4,567				4,388				13,703				13,163
General and administrative expense	9,178				11,025				31,535				39,026
Total operating expenses	68,831				656,737				204,774				833,650
Operating Income (Loss)	(18,350		)		(607,058		)		(77,575		)		(672,319		)
Other Income and Expense:
Interest and other income	72				100				166				519
Interest expense	(13,991		)		(15,754		)		(45,160		)		(49,574		)
Commodity derivative gain (loss)	6,054				69,133				(7,258		)		75,914
Gain (Loss) on extinguishment of debt	29				—				8,726				1,749
Total other income and expense	(7,836		)		53,479				(43,526		)		28,608
Income (Loss) before Income Taxes	(26,186		)		(553,579		)		(121,101		)		(643,711		)
(Provision for) Benefit from Income Taxes	—				143,265				—				177,085
Net Income (Loss)	$	(26,186	)		$	(410,314	)		$	(121,101	)		$	(466,626	)
Net Income (Loss) Per Common Share, Basic	$	(0.44	)		$	(8.49	)		$	(2.28	)		$	(9.67	)
Net Income (Loss) Per Common Share, Diluted	$	(0.44	)		$	(8.49	)		$	(2.28	)		$	(9.67	)
Weighted Average Common Shares Outstanding, Basic	58,851,598				48,339,639				53,081,809				48,279,763
Weighted Average Common Shares Outstanding, Diluted	58,851,598				48,339,639				53,081,809				48,279,763

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

 

	Three Months Ended September 30,								Nine Months Ended September 30,
	2016				2015				2016				2015
	(in thousands)
Net Income (Loss)	$	(26,186	)		$	(410,314	)		$	(121,101	)		$	(466,626	)
Other comprehensive income (loss)	—				—				—				—
Comprehensive Income (Loss)	$	(26,186	)		$	(410,314	)		$	(121,101	)		$	(466,626	)

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

	Nine Months Ended September 30,
	2016				2015
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(121,101	)		$	(466,626	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	125,491				159,666
Deferred income tax benefit	—				(176,797		)
Impairment, dry hole costs and abandonment expense	1,766				574,996
Total commodity derivative (gain) loss	7,258				(75,914		)
Gain (Loss) on settlements of commodity derivatives	78,417				128,834
Stock compensation and other non-cash charges	7,208				7,281
Amortization of deferred financing costs	2,075				3,983
(Gain) Loss on extinguishment of debt	(8,726		)		(1,749		)
(Gain) Loss on sale of properties	1,206				(759		)
Change in operating assets and liabilities:
Accounts receivable	13,552				20,394
Prepayments and other assets	(968		)		(261		)
Accounts payable, accrued and other liabilities	18,903				4,347
Amounts payable to oil and gas property owners	(2,894		)		(850		)
Production taxes payable	(5,980		)		(10,644		)
Net cash provided by (used in) operating activities	116,207				165,901
Investing Activities:
Additions to oil and gas properties, including acquisitions	(93,704		)		(256,059		)
Additions of furniture, equipment and other	(1,184		)		(1,036		)
Proceeds from sale of properties and other investing activities	25,571				66,617
Cash paid for short-term investments	—				(114,883		)
Proceeds from the sale of short-term investments	—				95,000
Net cash provided by (used in) investing activities	(69,317		)		(210,361		)
Financing Activities:
Principal payments on debt	(329		)		(25,083		)
Deferred financing costs and other	(1,134		)		(3,525		)
Net cash provided by (used in) financing activities	(1,463		)		(28,608		)
Increase (Decrease) in Cash and Cash Equivalents	45,427				(73,068		)
Beginning Cash and Cash Equivalents	128,836				165,904
Ending Cash and Cash Equivalents	$	174,263			$	92,836

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

 

	Common Stock				Additional Paid-In Capital				Retained Earnings (Accumulated Deficit)				Treasury Stock				Total Stockholders' Equity
Balance at December 31, 2014	$	48			$	913,619			$	115,821			$	—			$	1,029,488
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	—				—				—				(1,173		)		(1,173		)
Stock-based compensation	—				10,468				—				—				10,468
Retirement of treasury stock	—				(1,173		)		—				1,173				—
Settlement of convertible notes	—				(1,596		)		—				—				(1,596		)
Net income (loss)	—				—				(487,771		)		—				(487,771		)
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				—				—				(1,098		)		(1,097		)
Stock-based compensation	—				7,561				—				—				7,561
Retirement of treasury stock	—				(1,098		)		—				1,098				—
Exchange of senior notes for shares of common stock	10				74,390				—				—				74,400
Net income (loss)	—				—				(121,101		)		—				(121,101		)
Balance at September 30, 2016	$	59			$	1,002,171			$	(493,051	)		$	—			$	509,179

See notes to Unaudited Consolidated Financial Statements.

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BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2016

1. Organization

Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the "Company"), is an independent oil and gas company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids ("NGLs"). Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.

2 . Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company's interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company's Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company's 2015 Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company's financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future cash flows used in determining possible impairments of proved oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining asset retirement obligations, the timing of dry hole costs, impairments of unproved oil and gas properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of September 30, 2016				As of December 31, 2015
	(in thousands)
Accrued oil, gas and NGL sales	$	23,707			$	33,594
Due from joint interest owners	4,809				8,373
Other	1,416				1,508
Allowance for doubtful accounts	(23		)		(14		)
Total accounts receivable	$	29,909			$	43,461

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

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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 value, on a first-in, first-out basis.

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

	As of September 30, 2016				As of December 31, 2015
	(in thousands)
Proved properties	$	300,882			$	320,538
Wells and related equipment and facilities	1,163,497				1,592,716
Support equipment and facilities	60,818				77,785
Materials and supplies	6,170				9,171
Total proved oil and gas properties	$	1,531,367			$	2,000,210
Unproved properties	32,426				33,336
Wells and facilities in progress	8,309				45,862
Total unproved oil and gas properties, excluded from amortization	$	40,735			$	79,198
Accumulated depreciation, depletion, amortization and impairment	(499,177		)		(918,510		)
Total oil and gas properties, net	$	1,072,925			$	1,160,898

The Company reviews proved oil and gas properties on a field-by-field basis for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future net cash flows of its oil and gas properties based on the Company's best estimate of development plans, future production, commodity pricing, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the proved oil and gas properties, no impairment is taken. If the carrying value of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The Company does not believe that the undiscounted future net cash flows analysis of its proved property represents the applicable market value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, 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, the Company utilizes the income valuation technique which involves calculating the present value of future revenues, 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.

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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,
	2016				2015				2016				2015
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	—			$	556,291		(1)	$	—			$	556,563		(1)
Non-cash impairment of unproved oil and gas properties	—				15,572			(1)	183				15,803			(1)
Dry hole costs	1				14				71				(29		)
Abandonment expense and lease expirations	973				774				1,512				2,659
Total non-cash impairment, dry hole costs and abandonment expense	$	974			$	572,651			$	1,766			$	574,996

(1)	Due to the decline in oil prices, the Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved and unproved oil and gas properties for the three and nine months ended September 30, 2015.

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, 2016				As of December 31, 2015
	(in thousands)
Accrued drilling, completion and facility costs	$	7,447			$	32,895
Accrued lease operating, gathering, transportation and processing expenses	5,264				4,930
Accrued general and administrative expenses	5,784				10,962
Accrued interest payable	25,267				13,918
Accrued payables for property sales	11,008				167
Trade payables	510				620
Other	1,324				845
Total accounts payable and accrued liabilities	$	56,604			$	64,337

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, 2016 and 2015 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).

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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 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, 2016 .

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company's common stock and shares into which the Convertible Notes are convertible. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and nine months ended September 30, 2016 and 2015 .

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,
	2016				2015				2016				2015
	(in thousands, except per share amounts)
Net income (loss)	$	(26,186	)		$	(410,314	)		$	(121,101	)		$	(466,626	)
Basic weighted-average common shares outstanding in period	58,852				48,340				53,082				48,280
Diluted weighted-average common shares outstanding in period	58,852				48,340				53,082				48,280
Basic net income (loss) per common share	$	(0.44	)		$	(8.49	)		$	(2.28	)		$	(9.67	)
Diluted net income (loss) per common share	$	(0.44	)		$	(8.49	)		$	(2.28	)		$	(9.67	)

New Accounting Pronouncements. In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 is currently evaluating the impact of adopting this standard.

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 is effective for the annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company is currently evaluating the impact of adopting this standard.

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 is currently 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

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position. ASU 2015-17 is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard will be adopted retrospectively and will not have a significant impact on the Company's disclosures and financial statements.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . The objective of this update is to require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, should be applied retrospectively and represent a change in accounting principle. The Company adopted ASU 2015-03 and ASU 2015-15 as of March 31, 2016, and as a result, $8.7 million of debt issuance costs related to the Company’s senior notes and convertible senior notes was reclassified from deferred financing costs and other noncurrent assets to long-term debt in the Company’s consolidated balance sheet as of December 31, 2015. The Company elected to continue presenting the debt issuance costs associated with its credit facility within deferred financing costs and other noncurrent assets in the consolidated balance sheets.

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

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. ASU 2015-14 deferred the effective reporting periods of ASU 2014-09, and it is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact of adopting this standard.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Nine Months Ended September 30,
	2016				2015
	(in thousands)
Cash paid for interest	$	31,736			$	31,323
Cash paid for income taxes	—				1,052
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	8,318				57,699
Change in asset retirement obligations, net of disposals	(4,788		)		(241		)
Retirement of treasury stock	(1,098		)		(1,100		)
Fair value of debt exchanged for common stock (1)	74,400				—

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

4 . Divestitures

On July 14, 2016, the Company sold certain non-core assets in the Uinta Basin, which included approximately 40,000 net mineral acres. The Company received $28.9 million in cash proceeds, after initial closing adjustments. In addition to the cash proceeds, the Company recognized non-cash proceeds of $4.8 million related to the relief of the Company's asset retirement obligation. Assets sold included $31.7 million in proved oil and gas properties, net of accumulated depreciation, depletion,

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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. These assets were previously classified as held for sale in the Unaudited Consolidated Balance Sheet as of March 31, 2016 and June 30, 2016.

5 . Long-Term Debt

The Company's outstanding debt is summarized below:

 

		As of September 30, 2016												As of December 31, 2015
	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)(2)	March 15, 2028	579				—				579				579				—				579
7.625% Senior Notes (3)	October 1, 2019	315,300				(2,366		)		312,934				400,000				(3,752		)		396,248
7.0% Senior Notes (4)	October 15, 2022	400,000				(4,408		)		395,592				400,000				(4,953		)		395,047
Lease Financing Obligation (5)	August 10, 2020	2,893				(4		)		2,889				3,222				(4		)		3,218
Total Debt		$	718,772			$	(6,778	)		$	711,994			$	803,801			$	(8,709	)		$	795,092
Less: Current Portion of Long-Term Debt (6)		450				—				450				440				—				440
Total Long-Term Debt		$	718,322			$	(6,778	)		$	711,544			$	803,361			$	(8,709	)		$	794,652

 

(1)	The aggregate estimated fair value of the Convertible Notes was approximately $0.6 million and $0.5 million as of September 30, 2016 and December 31, 2015 , respectively, based on reported market trades of these instruments.

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

(3)	The aggregate estimated fair value of the 7.625% Senior Notes was approximately $274.3 million and $270.2 million as of September 30, 2016 and December 31, 2015 , respectively, based on reported market trades of these instruments.

(4)	The aggregate estimated fair value of the 7.0% Senior Notes was approximately $310.0 million and $272.0 million as of September 30, 2016 and December 31, 2015 , respectively, based on reported market trades of these instruments.

(5)	The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.8 million and $3.1 million as of September 30, 2016 and December 31, 2015 , respectively. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.

(6)	The current portion of the long-term debt as of September 30, 2016 and December 31, 2015 includes the current portion of the Lease Financing Obligation.

Amended Credit Facility

The Amended Credit Facility had commitments from 13 lenders and a borrowing base of $335.0 million as of September 30, 2016 . As of September 30, 2016 , the Company had no amounts outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of September 30, 2016 to $309.0 million .

Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the unused commitment fee is between 0.375% and 0.5% based on borrowing base utilization. There have not been any borrowings under the Amended Credit Facility in 2016.

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 such 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. On October 28, 2016, the borrowing base was reduced from $335.0 million to $300.0 million based on proved reserves and the commodity hedge position in place at July 31, 2016. Our re-determined borrowing capacity of $300.0 million is reduced by $26.0 million to $274.0 million due to the letter of credit related to an outstanding irrevocable letter of credit related to a firm transportation agreement. Future borrowing

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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 impact the amount lenders will provide for a 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 convertible notes and 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 March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. On March 20, 2015, $24.8 million of the remaining outstanding principal amount, or approximately 98% of the remaining outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. After the redemption, $0.6 million aggregate principal amount of the Convertible Notes were outstanding as of September 30, 2016 . The Convertible Notes mature on March 15, 2028 , unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company's existing and future senior unsecured indebtedness, are senior in right of payment to all of the Company's future subordinated indebtedness, and are effectively subordinated to all of the Company's secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company's subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.

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

7.625% Senior Notes Due 2019

On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. 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 million 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 nine months ended September 30, 2016 . After the Debt Exchange, $315.3 million aggregate principal amount of the 7.625% Senior Notes was outstanding as of September 30, 2016 .

The 7.625% Senior Notes mature on October 1, 2019 . Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are currently redeemable at the Company's option at a specified redemption price. The 7.625% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.

7.0% Senior Notes Due 2022

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On March 12, 2012, the Company issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes mature on October 15, 2022 . Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at the Company's option beginning on October 15, 2017 at an initial redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.

Lease Financing Obligation Due 2020

The Company has a lease financing obligation with a balance of $2.9 million as of September 30, 2016 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 13 for a discussion of aggregate minimum future lease payments.

The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, the outstanding Convertible Notes, the 7.625% Senior Notes, the 7.0% Senior Notes and the Lease Financing Obligation along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2016				2015				2016				2015
	(in thousands)
Amended Credit Facility (1)
Cash interest	$	370			$	443			$	1,245			$	1,313
Non-cash interest (2)	$	195			$	165			$	851			$	2,534
Convertible Notes (3)
Cash interest	$	7			$	22			$	22			$	308
Non-cash interest	$	—			$	1			$	—			$	6
7.625% Senior Notes (4)
Cash interest	$	6,010			$	7,625			$	20,740			$	22,875
Non-cash interest	$	197			$	267			$	680			$	813
7.0% Senior Notes (5)
Cash interest	$	7,000			$	7,000			$	21,000			$	21,000
Non-cash interest	$	182			$	199			$	544			$	607
Lease Financing Obligation (6)
Cash interest	$	24			$	27			$	75			$	84
Non-cash interest	$	1			$	—			$	1			$	24

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

(2)	The nine months ended September 30, 2015 included $1.6 million related to amending the credit facility.

(3)

The stated interest rate for the Convertible Notes is 5%  per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represented the fair value of the equity conversion feature at the time of issue. The stated interest rate of 5% on the Convertible Notes will be the effective interest rate of the $0.6 million remaining principal balance, as the related debt discount was fully amortized as of March 31, 2012.

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(4)	The stated interest rate for the 7.625% Senior Notes is 7.625%  per annum with an effective interest rate of 8.0%  per annum.

(5)	The stated interest rate for the 7.0% Senior Notes is 7.0%  per annum with an effective interest rate of 7.2%  per annum.

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

6. Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the nine months ended September 30, 2016 is as follows (in thousands):

As of December 31, 2015	$	15,176
Liabilities incurred	83
Liabilities settled	(10		)
Disposition of properties	(4,835		)
Accretion expense	661
Revisions to estimate	(26		)
As of September 30, 2016	$	11,049
Less: current asset retirement obligations	417
Long-term asset retirement obligations	$	10,632

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 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.

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	As of September 30, 2016
	Level 1				Level 2				Level 3				Total
	(in thousands)
Assets
Cash equivalents (1)	$	40,093			$	—			$	—			$	40,093
Deferred compensation plan (1)	1,387				—				—				1,387
Commodity derivatives (1)	—				36,300				—				36,300
Liabilities
Commodity derivatives (1)	$	—			$	2,504			$	—			$	2,504

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

	As of December 31, 2015
	Level 1				Level 2				Level 3				Total
	(in thousands)
Assets
Cash equivalents (1)	$	60,065			$	—			$	—			$	60,065
Deferred compensation plan (1)	1,231				—				—				1,231
Commodity derivatives (1)	—				119,471				—				119,471
Proved oil and gas properties (2)	—				—				178,221				178,221
Unproved oil and gas properties (2)	—				—				5,539				5,539

(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.

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 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. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

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, 2016 , no properties were measured at fair

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value. During the year ended December 31, 2015, the Company reduced its Uinta Oil Program assets to a fair value of $183.8 million , resulting in a non-cash impairment charge of $572.4 million .

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 fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $584.3 million as of September 30, 2016 . The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $542.2 million as of December 31, 2015 . The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

The Company estimated the fair value of the Debt Exchange based on the fair value of the Company's common stock. The fair value of the common stock is based on active market quotes, which represent Level 1 inputs. The Company recognized an $8.7 million gain on extinguishment of debt on the Consolidated Statement of Operations for the nine months ended September 30, 2016 as a result of the Debt Exchange. See Note 5 for additional information regarding the Debt Exchange.

There is no active, public market for the Amended Credit Facility, Convertible Notes or Lease Financing Obligation. 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, 2016 and December 31, 2015 . The Convertible Notes had a fair value of $0.6 million and $0.5 million as of September 30, 2016 and December 31, 2015 , respectively. The fair value of the Convertible Notes is measured based on market-based parameters of the various components of the Convertible Notes and over the counter trades. The Lease Financing Obligation fair values of $2.8 million and $3.1 million as of September 30, 2016 and December 31, 2015 , 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.

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.

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	As of September 30, 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 (current)	$	32,735			$	(1,995	)	(1)	$	30,740
Derivative assets (noncurrent)	3,565				(227		)	(1)	3,338
Total derivative assets	$	36,300			$	(2,222	)		$	34,078
	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	$	(1,995	)		$	1,995		(1)	$	—
Derivatives and other noncurrent liabilities	(509		)		227			(1)	(282		)	(2)
Total derivative liabilities	$	(2,504	)		$	2,222			$	(282	)
	As of December 31, 2015
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 (current)	$	99,809			$	—			$	99,809
Derivative assets (noncurrent)	19,662				—				19,662
Total derivative assets	$	119,471			$	—			$	119,471

 

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

(2)	As of September 30, 2016 , this line item on the Unaudited Consolidated Balance Sheet includes $4.1 million of other noncurrent liabilities.

As of September 30, 2016 , 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 2016							For the year 2017							For the year 2018
	Derivative Volumes			Weighted Average Price				Derivative Volumes			Weighted Average Price				Derivative Volumes			Weighted Average Price
Oil (Bbls)	713,000			$	72.57			1,456,250			$	61.71			136,500			$	51.67
Natural Gas (MMbtu)	460,000			$	4.10			3,650,000			$	2.96			—			$	—

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 eight different counterparties as of September 30, 2016 . Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of 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. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit

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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, 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, 2016 and 2015 .

Income tax benefit for the three and nine months ended September 30, 2016 and 2015 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, 2016 , the effective tax rate remains at zero as a result of recording a full valuation allowance against our 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 judgment 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

On June 3, 2016, the Company issued 10 million 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 million 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,
	2016				2015				2016				2015
	(in thousands)
Common stock options (1)	$	—			$	137			$	69			$	528
Nonvested common stock (1)	1,458				1,816				5,273				5,007
Nonvested common stock units  (1)	165				250				711				779
Nonvested performance-based shares (1)	275				(50		)		1,510				903
Nonvested performance cash units (2)	242				(164		)		1,088				281
Total	$	2,140			$	1,989			$	8,651			$	7,498

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(1)	Unrecognized compensation cost as of September 30, 2016 was $7.8 million , which related to grants of nonvested stock options and nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.6 years .

(2)	The nonvested performance-based cash units are liability awards with $1.5 million and $0.4 million in derivatives and other noncurrent liabilities in the Unaudited Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015 , respectively.

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, 2016							Three Months Ended September 30, 2015
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		—			$	—			32,618			$	5.24
Nonvested common stock units		2,922			$	5.56			5,681			$	3.30
Total granted		2,922							38,299
		Three Months Ended September 30, 2016							Three Months Ended September 30, 2015
Cash Awards		Number of Units			Fair Value Per Unit				Number of Units			Fair Value Per Unit
Nonvested performance cash units		—			$	—			12,052			$	3.40
		Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015
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		686,500			$	5.11			664,757			$	11.91
Nonvested common stock units		96,650			$	7.02			130,669			$	8.47
Total granted		783,150							795,426
		Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015
Cash Awards		Number of Units			Fair Value Per Unit				Number of Units			Fair Value Per Unit
Nonvested performance cash units		646,572			$	5.56			419,743			$	3.40

Performance Cash Program

2016 Program. In March 2016, the Compensation Committee approved a performance cash program (the "2016 Program") granting performance cash units that will settle in cash. The performance-based awards contingently vest in February 2019, 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, 2018, will be the Company's total shareholder return ("TSR") based on a matrix measurement of the Company's absolute performance and ranking relative to a defined peer group's individual TSRs ("Relative TSR"). The Company's absolute performance is measured against the December 31, 2015 closing share price of $3.93 and if the Company's absolute performance is lower than the $3.93 share price, the payout is zero . If the Company's absolute performance is greater than the $3.93 share price, then the performance cash units will vest depending on the compound annual growth rate of the Company's absolute performance and the Relative TSR up to 200% of the original grant.

12. Equity Distribution Agreement

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

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agreed by the Company and the Manager. As of September 30, 2016 , and the date of this filing, no shares have been sold pursuant to the Agreement.

13 . 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, 2016
	(in thousands)
2016	$	134
2017	537
2018	537
2019	1,825
2020	—
Thereafter	—
Total	$	3,033

Transportation Charges . The Company is party to two firm transportation contracts to provide capacity on natural gas pipeline systems. The remaining term on these contracts is five years. 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, 2016
	(in thousands)
2016	$	4,638
2017	18,692
2018	18,692
2019	18,692
2020	18,692
Thereafter	10,902
Total	$	90,308

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

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

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	As of September 30, 2016
	(in thousands)
2016	$	818
2017  (1)	3,960
2018	2,683
2019	693
2020	—
Thereafter	—
Total	$	8,154

(1)	Includes contractual obligation of $1.0 million related to certain drilling and completion commitments due in 2017.

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.

14. Guarantor Subsidiaries

In addition to the Amended Credit Facility, the 7.625% Senior Notes, 7.0% Senior Notes and Convertible 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, 2016
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Assets:
Current assets	$	236,721			$	139			$	—			$	236,860
Property and equipment, net	1,074,906				6,160				—				1,081,066
Intercompany receivable (payable)	20,918				(20,918		)		—				—
Investment in subsidiaries	(14,675		)		—				14,675				—
Noncurrent assets	17,627				—				—				17,627
Total assets	$	1,335,497			$	(14,619	)		$	14,675			$	1,335,553
Liabilities and Stockholders' Equity:
Current liabilities	$	99,782			$	—			$	—			$	99,782
Long-term debt	711,544				—				—				711,544
Other noncurrent liabilities	14,992				56				—				15,048
Stockholders' equity	509,179				(14,675		)		14,675				509,179
Total liabilities and stockholders' equity	$	1,335,497			$	(14,619	)		$	14,675			$	1,335,553

 

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	As of December 31, 2015
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Assets:
Current assets	$	274,115			$	202			$	—			$	274,317
Property and equipment, net	1,164,086				6,598				—				1,170,684
Intercompany receivable (payable)	21,412				(21,412		)		—				—
Investment in subsidiaries	(14,664		)		—				14,664				—
Noncurrent assets	61,519				—				—				61,519
Total assets	$	1,506,468			$	(14,612	)		$	14,664			$	1,506,520
Liabilities and Stockholders' Equity:
Current liabilities	$	145,231			$	—			$	—			$	145,231
Long-term debt	794,652				—				—				794,652
Other noncurrent liabilities	17,169				52				—				17,221
Stockholders' equity	549,416				(14,664		)		14,664				549,416
Total liabilities and stockholders' equity	$	1,506,468			$	(14,612	)		$	14,664			$	1,506,520

Condensed Consolidating Statements of Operations  

	Three Months Ended September 30, 2016
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Operating and other revenues	$	50,325			$	156			$	—			$	50,481
Operating expenses	(59,498		)		(155		)		—				(59,653		)
General and administrative	(9,178		)		—				—				(9,178		)
Interest income and other income (expense)	(7,836		)		—				—				(7,836		)
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 (loss) 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 and other revenues	$	126,730			$	469			$	—			$	127,199
Operating expenses	(172,759		)		(480		)		—				(173,239		)
General and administrative	(31,535		)		—				—				(31,535		)
Interest income and other income (expense)	(43,526		)		—				—				(43,526		)
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	)

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	Three Months Ended September 30, 2015
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Operating and other revenues	$	49,562			$	117			$	—			$	49,679
Operating expenses	(630,783		)		(14,929		)		—				(645,712		)
General and administrative	(11,025		)		—				—				(11,025		)
Interest and other income (expense)	53,479				—				—				53,479
Income (loss) before income taxes and equity in earnings of subsidiaries	(538,767		)		(14,812		)		—				(553,579		)
(Provision for) Benefit from income taxes	143,265				—				—				143,265
Equity in earnings of subsidiaries	(14,812		)		—				14,812				—
Net income (loss)	$	(410,314	)		$	(14,812	)		$	14,812			$	(410,314	)
	Nine Months Ended September 30, 2015
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Operating and other revenues	$	160,963			$	368			$	—			$	161,331
Operating expenses	(779,377		)		(15,247		)		—				(794,624		)
General and administrative	(39,026		)		—				—				(39,026		)
Interest and other income (expense)	28,608				—				—				28,608
Income (loss) before income taxes and equity in earnings of subsidiaries	(628,832		)		(14,879		)		—				(643,711		)
(Provision for) Benefit from income taxes	177,085				—				—				177,085
Equity in earnings (loss) of subsidiaries	(14,879		)		—				14,879				—
Net income (loss)	$	(466,626	)		$	(14,879	)		$	14,879			$	(466,626	)

Condensed Consolidating Statements of Comprehensive Income (Loss)

 

	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	)

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	Three Months Ended September 30, 2015
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Net income (loss)	$	(410,314	)		$	(14,812	)		$	14,812			$	(410,314	)
Other comprehensive income (loss)	—				—				—				—
Comprehensive income (loss)	$	(410,314	)		$	(14,812	)		$	14,812			$	(410,314	)
	Nine Months Ended September 30, 2015
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Net income (loss)	$	(466,626	)		$	(14,879	)		$	14,879			$	(466,626	)
Other comprehensive income (loss)	—				—				—				—
Comprehensive income (loss)	$	(466,626	)		$	(14,879	)		$	14,879			$	(466,626	)

Condensed Consolidating Statements of Cash Flows

 

	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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	Nine Months Ended September 30, 2015
	Parent Issuer				Guarantor Subsidiaries				Intercompany Eliminations				Consolidated
	(in thousands)
Cash flows from operating activities	$	165,911			$	(10	)		$	—			$	165,901
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(257,399		)		1,340				—				(256,059		)
Additions to furniture, fixtures and other	(1,036		)		—				—				(1,036		)
Proceeds from sale of properties and other investing activities	66,617				—				—				66,617
Cash paid for short-term investments	(114,883		)		—				—				(114,883		)
Proceeds from sale of short-term investments	95,000				—				—				95,000
Intercompany transfers	1,330				—				(1,330		)		—
Cash flows from financing activities:
Principal payments on debt	(25,083		)		—				—				(25,083		)
Intercompany transfers	—				(1,330		)		1,330				—
Other financing activities	(3,525		)		—				—				(3,525		)
Change in cash and cash equivalents	(73,068		)		—				—				(73,068		)
Beginning cash and cash equivalents	165,904				—				—				165,904
Ending cash and cash equivalents	$	92,836			$	—			$	—			$	92,836

  

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;

•	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;

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

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

•	changes in estimates of proved reserves;

•	the potential for production decline rates from our wells, 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, 2015 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 core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.

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

Oil prices declined severely beginning in 2014, and price decreases continued through 2016. Natural gas and NGL prices have experienced decreases of comparable magnitude over the same period. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and in the Company's 2015 Annual Report on Form 10-K, have impacted our average realized unit price and are having an impact on our business and financial condition. Commodity prices are inherently volatile and are influenced by many factors outside of our control. We endeavor to maintain flexibility in our activities and capital budgeting using what we believe to be conservative sales price assumptions and our existing hedge position. If commodity prices continue at current or lower levels, our capital availability, liquidity and profitability are likely to be adversely affected.

As we go through 2016, our priority remains ensuring ample liquidity and adjusting our development plans as necessary to this end. Further, we continue to monitor debt, equity and hedging markets for opportunities to strengthen our liquidity position. On October 28, 2016, the borrowing base under our Amended Credit Facility was reduced to $300.0 million based on proved reserves in place at July 31, 2016. Our re-determined borrowing base of $300.0 million is reduced by $26.0 million to $274.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

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

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

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

Commodity prices are inherently volatile and are influenced by many factors outside of our control. We currently have hedged 713,000 barrels of oil and 460,000 MMbtu of natural gas or approximately 52% of our expected remaining 2016 production, 1,456,250 barrels of oil and 3,650,000 MMbtu of natural gas for our 2017 production and 136,500 barrels of oil for our 2018 production 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.

On July 14, 2016, we closed on the sale of certain non-core assets in the Uinta Basin. Total gross consideration, including preliminary closing adjustments, was $33.7 million, including cash proceeds of $28.9 million and $4.8 million related to the relief of asset retirement obligations.

Results of Operations

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

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Three Months Ended September 30, 2016 Compared with Three Months Ended September 30, 2015

 

	Three Months Ended September 30,								Increase (Decrease)
	2016				2015				Amount				Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	50,133			$	48,799			$	1,334			3	%
Other	348				880				(532		)		(60	)%
Operating Expenses
Lease operating expense	4,795				9,638				(4,843		)		(50	)%
Gathering, transportation and processing expense	472				684				(212		)		(31	)%
Production tax expense	3,832				3,670				162				4	%
Exploration expense	16				20				(4		)		(20	)%
Impairment, dry hole costs and abandonment expense	974				572,651				(571,677		)		(100	)%
(Gain) Loss on divestitures	1,914				(77		)		1,991				*nm
Depreciation, depletion and amortization	43,083				54,738				(11,655		)		(21	)%
Unused commitments	4,567				4,388				179				4	%
General and administrative expense (1)	9,178				11,025				(1,847		)		(17	)%
Total operating expenses	$	68,831			$	656,737			$	(587,906	)		(90	)%
Production Data:
Oil (MBbls)	1,016				1,066				(50		)		(5	)%
Natural gas (MMcf)	1,734				2,214				(480		)		(22	)%
NGLs (MBbls)	261				264				(3		)		(1	)%
Combined volumes (MBoe)	1,566				1,699				(133		)		(8	)%
Daily combined volumes (Boe/d)	17,022				18,467				(1,445		)		(8	)%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	41.92			$	38.71			$	3.21			8	%
Natural gas (per Mcf)	2.29				2.08				0.21				10	%
NGLs (per Bbl)	13.65				11.17				2.48				22	%
Combined (per Boe)	32.02				28.73				3.29				11	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	61.30			$	79.15			$	(17.85	)		(23	)%
Natural gas (per Mcf)	2.71				3.36				(0.65		)		(19	)%
NGLs (per Bbl)	13.65				11.17				2.48				22	%
Combined (per Boe)	45.06				55.77				(10.71		)		(19	)%
Average Costs (per Boe):
Lease operating expense	$	3.06			$	5.67			$	(2.61	)		(46	)%
Gathering, transportation and processing expense	0.30				0.40				(0.10		)		(25	)%
Production tax expense	2.45				2.16				0.29				13	%
Depreciation, depletion and amortization	27.51				32.22				(4.71		)		(15	)%
General and administrative expense (1)	5.86				6.49				(0.63		)		(10	)%

*	Not meaningful.

(1)	Included in general and administrative expense is long-term cash and equity incentive compensation of $2.1 million (or $1.37 per Boe) and $2.0 million (or $1.18 per Boe) for the three months ended September 30, 2016 and 2015 , respectively.

Production Revenues and Volumes . Production revenues increased to $50.1 million for the three months ended September 30, 2016 from $48.8 million for the three months ended September 30, 2015 . The increase in production revenues was due to an 11% increase in average realized prices before hedging, offset by an 8% decrease in production volumes. The increase in average realized prices before hedging increased production revenues by approximately $5.6 million, while the decrease in production volumes reduced production revenues by approximately $4.3 million.

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Total production volumes were 1.6 MMBoe for the three months ended September 30, 2016 and 1.7 MMBoe for the three months ended September 30, 2015 . The decrease is primarily related to a 41% decrease in production from the Uinta Oil Program due to the sale of certain non-core Uinta Oil Program assets during the three months ended September 30, 2016 and natural production declines in the Uinta Oil Program with no significant drilling or recompletion activities to offset these declines. The overall production volume decrease was offset by an increase in the DJ Basin production volumes, which were partially offset by non-core asset sales completed during the year ended December 31, 2015. Additional information concerning production is in the following table:

	Three Months Ended September 30, 2016									Three Months Ended September 30, 2015									% 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	827		252		1,554		1,338			762		246		1,818		1,311			9	%	2	%	(15	)%	2	%
Uinta Oil Program	188		9		174		226			303		18		384		385			(38	)%	(50	)%	(55	)%	(41	)%
Other	1		—		6		2			1		—		12		3			*nm		*nm		*nm		*nm
Total	1,016		261		1,734		1,566			1,066		264		2,214		1,699			(5	)%	(1	)%	(22	)%	(8	)%

*	Not meaningful.

Lease Operating Expense ("LOE") . LOE decreased to $3.06 per Boe for the three months ended September 30, 2016 from $5.67 per Boe for the three months ended September 30, 2015 . The decrease per Boe for the three months ended September 30, 2016 compared with the three months ended September 30, 2015 is related to operational efficiencies, a decrease in service industry costs, the DJ Basin becoming a greater component of total corporate operations and sales of certain non-core assets in the DJ and Uinta Basins, which had higher LOE costs on a per Boe basis. We anticipate that LOE per Boe will increase for the three months ended December 31, 2016 due to an increase in LOE from seasonal costs with no new production to offset the increase.

Production Tax Expense . Total production taxes increased to $3.8 million for the three months ended September 30, 2016 from $3.7 million for the three months ended September 30, 2015 . The increase in production tax expense is primarily related to the 3% increase in oil, gas and NGL production revenues. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 7.6% and 7.5% for the three months ended September 30, 2016 and September 30, 2015 , 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, 2016 and 2015 is summarized below:

	Three Months Ended September 30,
	2016				2015
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	—			$	556,291		(1)
Non-cash impairment of unproved oil and gas properties	—				15,572			(1)
Dry hole expense	1				14
Abandonment expense/ Lease expirations	973				774
Total non-cash impairment, dry hole costs and abandonment expense	$	974			$	572,651

(1)	Due to the decline in oil prices, the Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved and unproved oil and gas properties for the three months ended September 30, 2015.

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We review our proved 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 future cash flows of our oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value 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 revenues, 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.

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 proved oil and gas properties as of September 30, 2016 uses commodity pricing based on 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, 2016 results in a surplus of future estimated net cash flows over carrying value of approximately $391.4 million and $114.4 million for the Uinta Oil Program and DJ Basin, respectively. We completed a sensitivity test on the surplus of future estimated net cash flows by decreasing the oil price by $1.00. Natural gas and NGL pricing were not considered in this sensitivity analysis as the majority of future cash flows from these two Basins are derived from oil revenues. As a result, we estimate that the surplus in the Uinta Oil program would decrease by approximately $15.0 million to $20.0 million and the DJ Basin would decrease by approximately $20.0 million to $25.0 million for every $1.00 decrease in the oil price assumptions used in the recoverability test. If impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, it is likely that we will incur a significant impairment.

(Gain) Loss on Divestitures. The loss on divestitures for the three months ended September 30, 2016 consisted of a $1.9 million loss related to a contingent contractual obligation associated with previously sold properties. The amount was previously disclosed in commitments and contingencies in Note 13 to the accompanying financial statements as of June 30, 2016.

Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $43.1 million for the three months ended September 30, 2016 compared with $54.7 million for the three months ended September 30, 2015 . The decrease of $11.7 million was primarily due to a 15% decrease in the DD&A rate and an 8% decrease in production volumes for the three months ended September 30, 2016 compared with the three months ended September 30, 2015 .

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, 2016 , the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $27.51 per Boe compared with $32.22 per Boe for the three months ended September 30, 2015 .

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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 and expire July 31, 2021. Unused commitments expense for the three months ended September 30, 2016 and September 30, 2015 consisted of $4.6 million and $4.4 million related to these contracts, respectively.

General and Administrative Expense. General and administrative expense decreased to $9.2 million for the three months ended September 30, 2016 from $11.0 million for the three months ended September 30, 2015 primarily due to a decrease in employee compensation and benefits.

Included in general and administrative expense is long-term cash and equity incentive compensation of $2.1 million and $2.0 million for the three months ended September 30, 2016 and 2015 , respectively. The components of long-term cash and equity incentive compensation for the three months ended September 30, 2016 and 2015 are shown in the following table:

	Three Months Ended September 30,
	2016				2015
	(in thousands)
Stock options and nonvested shares of common stock	$	1,882			$	2,153
Shares issued for directors' fees	16				18
Performance cash units (1)	242				(164		)
Total	$	2,140			$	2,007

(1)	The decrease for the three months ended September 30, 2015 was due to a decrease in the fair value share price used to determine the inception to date performance cash unit expense to $3.40 as of September 30, 2015 from $8.92 as of June 30, 2015.

Interest Expense. Interest expense decreased to $14.0 million for the three months ended September 30, 2016 from $15.8 million for the three months ended September 30, 2015 primarily due to the Debt Exchange completed on June 3, 2016 (see Note 5 to the accompanying financial statements), which reduced the principal of our 7.625% Senior Notes by $84.7 million.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $6.1 million for the three months ended September 30, 2016 compared with a gain of $69.1 million for the three months ended September 30, 2015 . 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, 2016 and 2015 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,
	2016				2015
	(in thousands)
Realized gain (loss) on derivatives (1)	$	20,412			$	45,936
Reversal of prior year unrealized gain transferred to realized gain (1)	(21,706		)		(34,374		)
Unrealized gain (loss) on derivatives (1)	7,348				57,571
Total commodity derivative gain (loss)	$	6,054			$	69,133

(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.

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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.

During the three months ended September 30, 2015 , approximately 93% of our oil volumes and 83% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $43.1 million and natural gas income of $2.8 million after settlements for all commodity derivatives.

Income Tax (Expense) Benefit . For the three months ended September 30, 2016 , we recorded an additional valuation allowance of $10.0 million against our deferred tax asset balance which reduced our effective tax rate to zero. The income tax benefit of $143.3 million for the three months ended September 30, 2015 resulted in an effective tax rate of 25.9% . 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 2016 and 2015 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.

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Nine Months Ended September 30, 2016 Compared with Nine Months Ended September 30, 2015

	Nine Months Ended September 30,								Increase (Decrease)
	2016				2015				Amount				Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	126,279			$	158,667			$	(32,388	)		(20	)%
Other	920				2,664				(1,744		)		(65	)%
Operating Expenses
Lease operating expense	22,101				34,834				(12,733		)		(37	)%
Gathering, transportation and processing expense	1,871				2,559				(688		)		(27	)%
Production tax expense	7,037				10,020				(2,983		)		(30	)%
Exploration expense	64				145				(81		)		(56	)%
Impairment, dry hole costs and abandonment expense	1,766				574,996				(573,230		)		(100	)%
(Gain) Loss on divestitures	1,206				(759		)		1,965				259	%
Depreciation, depletion and amortization	125,491				159,666				(34,175		)		(21	)%
Unused commitments	13,703				13,163				540				4	%
General and administrative expense (1)	31,535				39,026				(7,491		)		(19	)%
Total operating expenses	$	204,774			$	833,650			$	(628,876	)		(75	)%
Production Data:
Oil (MBbls)	2,925				3,311				(386		)		(12	)%
Natural gas (MMcf)	5,298				5,772				(474		)		(8	)%
NGLs (MBbls)	732				635				97				15	%
Combined volumes (MBoe)	4,540				4,908				(368		)		(7	)%
Daily combined volumes (Boe/d)	16,569				17,978				(1,409		)		(7	)%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	36.88			$	41.54			$	(4.66	)		(11	)%
Natural gas (per Mcf)	1.81				2.31				(0.50		)		(22	)%
NGLs (per Bbl)	12.05				12.24				(0.19		)		(2	)%
Combined (per Boe)	27.82				32.33				(4.51		)		(14	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	62.74			$	77.93			$	(15.19	)		(19	)%
Natural gas (per Mcf)	2.34				3.76				(1.42		)		(38	)%
NGLs (per Bbl)	12.05				12.24				(0.19		)		(2	)%
Combined (per Boe)	45.09				58.58				(13.49		)		(23	)%
Average Costs (per Boe):
Lease operating expense	$	4.87			$	7.10			$	(2.23	)		(31	)%
Gathering, transportation and processing expense	0.41				0.52				(0.11		)		(21	)%
Production tax expense	1.55				2.04				(0.49		)		(24	)%
Depreciation, depletion and amortization	27.64				32.53				(4.89		)		(15	)%
General and administrative expense (1)	6.95				7.95				(1.00		)		(13	)%

(1)	Included in general and administrative expense is long-term cash and equity incentive compensation of $8.7 million (or $1.91 per Boe) and $7.8 million (or $1.59 per Boe) for the nine months ended September 30, 2016 and 2015 , respectively.

Production Revenues and Volumes . Production revenues decreased to $126.3 million for the nine months ended September 30, 2016 from $158.7 million for the nine months ended September 30, 2015 . The decrease in production revenues was due to a 14% decrease in average realized prices before hedging and a 7% decrease in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately $22.1 million, while the decrease in production volumes reduced production revenues by approximately $10.3 million.

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Total production volumes of 4.5 MMBoe for the nine months ended September 30, 2016 decreased from 4.9 MMBoe for the nine months ended September 30, 2015 . The decrease is primarily related to a 39% decrease in production from the Uinta Oil Program due to natural production declines with no significant drilling or recompletion activities to offset these declines as well as the sale of certain non-core Uinta Oil Program assets during the three months ended September 30, 2016. The overall production volume decrease was offset by an increase in the DJ Basin production volumes, which were partially offset by non-core asset sales completed during the year ended December 31, 2015. Additional information concerning production is in the following table:

	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015									% 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	2,247		693		4,500		3,690			2,198		569		4,410		3,502			2	%	22	%	2	%	5	%
Uinta Oil Program	674		37		762		838			1,092		65		1,344		1,381			(38	)%	(43	)%	(43	)%	(39	)%
Other	4		2		36		12			21		1		18		25			*nm		*nm		*nm		*nm
Total	2,925		732		5,298		4,540			3,311		635		5,772		4,908			(12	)%	15	%	(8	)%	(7	)%

*	Not meaningful.

Lease Operating Expense . LOE decreased to $4.87 per Boe for the nine months ended September 30, 2016 from $7.10 per Boe for the nine months ended September 30, 2015 . The decrease per Boe for the nine months ended September 30, 2016 compared with the nine months ended September 30, 2015 is primarily related to operational efficiencies, a decrease in service industry costs, reduced workover activity in the Uinta Basin and sales of certain non-core assets in the DJ and Uinta Basins, which had higher LOE costs on a per Boe basis.

Production Tax Expense . Total production taxes decreased to $7.0 million for the nine months ended September 30, 2016 from $10.0 million for the nine months ended September 30, 2015 . The overall decrease in production tax expense is related to the annual true-up of Colorado ad valorem tax based on actual assessments and a true-up of the Colorado severance tax based on the annual severance tax calculation. In addition, production tax expense decreased due to a 14% decrease in average realized prices before hedging. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 5.6% and 6.3% for the nine months ended September 30, 2016 and September 30, 2015 , 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, 2016 and 2015 are summarized below:

	Nine Months Ended September 30,
	2016				2015
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	—			$	556,563		(1)
Non-cash impairment of unproved oil and gas properties	183				15,803			(1)
Dry hole expense	71				(29		)
Abandonment expense	1,512				2,659
Total non-cash impairment, dry hole costs and abandonment expense	$	1,766			$	574,996

(1)	Due to the decline in oil prices, the Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved and unproved oil and gas properties for the nine months ended September 30, 2015.

We review our proved 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

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future cash flows of our oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value 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 revenues, 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.

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 proved oil and gas properties as of September 30, 2016 uses commodity pricing based on 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, 2016 results in a surplus of future estimated net cash flows over carrying value of approximately $391.4 million and $114.4 million for the Uinta Oil Program and DJ Basin, respectively. We completed a sensitivity test on the surplus of future estimated net cash flows by decreasing the oil price by $1.00. Natural gas and NGL pricing were not considered in this sensitivity analysis as the majority of future cash flows from these two Basins are derived from oil revenues. We estimate that the surplus in the Uinta Oil program would decrease by approximately $15.0 million to $20.0 million and the DJ Basin would decrease by approximately $20.0 million to $25.0 million for every $1.00 decrease in the oil price assumptions used in the recoverability test. If impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, it is likely that we will incur a significant impairment.

(Gain) Loss on Divestitures. The loss on divestitures for the nine months ended September 30, 2016 consisted of a $1.9 million loss related to a contingent contractual obligation associated with previously sold properties, offset by a $0.7 million gain related to post-closing adjustments on previously sold properties. The gain on divestitures for the nine months ended September 30, 2015 consisted of $0.8 million related to post-closing adjustments associated with previously sold properties.

Depreciation, Depletion and Amortization. DD&A decreased to $125.5 million for the nine months ended September 30, 2016 compared with $159.7 million for the nine months ended September 30, 2015 . The decrease of $34.2 million was a result of a 15% decrease in the DD&A rate and a 7% decrease in production for the nine months ended September 30, 2016 compared with the nine months ended September 30, 2015 . The decrease in the DD&A rate accounted for a $22.2 million decrease in DD&A expense, while the decrease in production accounted for a $12.0 million decrease 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, 2016 , the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $27.64 per Boe compared with $32.53 per Boe for the nine months ended September 30, 2015 .

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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 and expire July 31, 2021. Unused commitments expense for the nine months ended September 30, 2016 and September 30, 2015 consisted of $13.7 million and $13.2 million related to these contracts, respectively.

General and Administrative Expense. General and administrative expense decreased to $31.5 million for the nine months ended September 30, 2016 from $39.0 million for the nine months ended September 30, 2015 primarily due to a decrease in employee compensation and benefits.

Included in general and administrative expense is long-term cash and equity incentive compensation of $8.7 million and $7.8 million for the nine months ended September 30, 2016 and 2015 , respectively. The components of long-term cash and equity incentive compensation for the nine months ended September 30, 2016 and 2015 are shown in the following table:

	Nine Months Ended September 30,
	2016				2015
	(in thousands)
Stock options and nonvested shares of common stock	$	7,509			$	7,217
Shares issued for 401(k) plan (1)	—				273
Shares issued for directors' fees	54				55
Performance cash units	1,088				281
Total	$	8,651			$	7,826

(1)	Beginning in the second quarter of 2015, the employer matching contribution to the employees 401(k) account was paid entirely in cash.

Interest Expense. Interest expense decreased to $45.2 million for the nine months ended September 30, 2016 from $49.6 million for the nine months ended September 30, 2015 primarily due to the Debt Exchange completed on June 3, 2016 (see Note 5 to the accompanying financial statements), which reduced the principal of our 7.625% Senior Notes by $84.7 million. In addition, we recognized additional interest expense associated with amending the credit facility during the nine months ended September 30, 2015.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a loss of $7.3 million for the nine months ended September 30, 2016 compared with a gain of $75.9 million for the nine months ended September 30, 2015 . 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, 2016 and 2015 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,
	2016				2015
	(in thousands)
Realized gain (loss) on derivatives (1)	$	78,417			$	128,834
Reversal of prior year unrealized gain transferred to realized gain (1)	(79,055		)		(113,342		)
Unrealized gain (loss) on derivatives (1)	(6,620		)		60,422
Total commodity derivative gain (loss)	$	(7,258	)		$	75,914

(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.

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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.

During the nine months ended September 30, 2015 , approximately 92% of our oil volumes and 88% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $120.5 million and natural gas income of $8.4 million after settlements for all commodity derivatives.

Income Tax (Expense) Benefit . For the nine months ended September 30, 2016 , we recorded an additional valuation allowance of $45.8 million against our deferred tax asset balance which reduced our effective tax rate to zero . For the nine months ended September 30, 2015 , the income tax benefit was $177.1 million resulting in an effective tax rate of 27.5% . 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 2016 and 2015 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.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, notes and senior notes, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including potential issuances of equity and debt securities, available to us to meet our future financial obligations, 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 2016 and 2017. 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.

At September 30, 2016 , we had cash and cash equivalents of $174.3 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2015, we had cash and cash equivalents of $128.8 million and no amounts outstanding under our Amended Credit Facility. Our borrowing base was $335.0 million as of September 30, 2016 . Our effective borrowing capacity as of that date was reduced by $26.0 million to $309.0 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. On October 28, 2016, the borrowing base was reduced from $335.0 million to $300.0 million based on proved reserves in place at July 31, 2016. Our re-determined borrowing capacity of $300.0 million is reduced by $26.0 million to $274.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

Cash Flow from Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2016 and 2015 was $116.2 million and $165.9 million , respectively. The decrease in net cash provided by operating activities was primarily due to decreases in production revenues and cash from derivative settlements.

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.

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To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production revenues. At September 30, 2016 , we had in place crude oil swaps covering portions of our 2016, 2017 and 2018 production and natural gas swaps covering portions of our 2016 and 2017 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, 2016 , the estimated fair value of all of our commodity derivative instruments, summarized in the following table, was a net asset of $33.8 million , comprised of current and noncurrent assets and noncurrent liabilities.

Contract	Total Hedged Volumes			Quantity Type		Weighted Average Fixed Price				Index Price (1)		Fair Market Value (in thousands)
Swap Contracts:
2016
Oil	713,000			Bbls		$	72.57			WTI		$	18,368
Natural gas	460,000			MMBtu		$	4.10			NWPL		555
2017
Oil	1,456,250			Bbls		$	61.71			WTI		14,808
Natural gas	3,650,000			MMBtu		$	2.96			NWPL		295
2018
Oil	136,500			Bbls		$	51.67			WTI		(230		)
Total												$	33,796

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

The following table includes all hedges entered into from October 1, 2016 to October 21, 2016 :

Contract	Total Hedged Volumes			Quantity Type		Weighted Average Fixed Price				Index Price
Swap Contracts:
2017
Oil	216,875			Bbls		$	53.10			WTI
2018
Oil	91,250			Bbls		$	55.25			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 or affiliates of lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard

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contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.

Capital Expenditures

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

	Nine Months Ended September 30,
Basin/Area	2016				2015
	(in millions)
DJ	$	67.0			$	214.3
Uinta Oil Program	1.1				26.3
Other	1.4				2.0
Total	$	69.5			$	242.6

	Nine Months Ended September 30,
	2016				2015
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	2.5			$	4.2
Drilling, development, exploration and exploitation of oil and natural gas properties	60.8				227.0
Gathering and compression facilities	5.0				7.4
Geologic and geophysical costs	—				3.0
Furniture, fixtures and equipment	1.2				1.0
Total	$	69.5			$	242.6

Our current estimated capital expenditure budget in 2016 is approximately $100.0 million, with all drilling activities targeting oil. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline 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. The 2016 capital program is designed to closely align capital expenditures with expected cash flows as certain drilling activity may be deferred to protect our liquidity position.

We believe that we have sufficient available liquidity with available cash on hand, cash under the Amended Credit Facility and cash flow from operations to fund our 2016 budgeted 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 operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

Financing Activities

Amended Credit Facility

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The Amended Credit Facility had commitments from 13 lenders and a borrowing base of $335.0 million as of September 30, 2016 . As of September 30, 2016 , we had no amounts outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduced the available borrowing capacity under the Amended Credit Facility as of September 30, 2016 to $309.0 million .

Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the unused commitment fee is between 0.375% to 0.5% based on borrowing base utilization. There have not been any borrowings under the Amended Credit Facility in 2016.

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 such 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. On October 28, 2016, the borrowing base was reduced from $335.0 million to $300.0 million based on proved reserves in place at July 31, 2016. Our re-determined borrowing capacity of $300.0 million is reduced by $26.0 million to $274.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement. 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 impact the amount lenders will provide for a 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 2016 budget. However, if commodity prices continue at current levels or lower, EBITDAX will be significantly reduced, which is a critical underpinning of our required financial covenants. If this were to occur, it will make it necessary for us to negotiate an amendment to one or more of these financial covenants.

If we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our convertible notes and 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. 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.

5% Convertible Senior Notes Due 2028

On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to us and redeemed by us at par. On March 20, 2015, $24.8 million of the remaining outstanding principal amount, or approximately 98% of the remaining outstanding Convertible Notes, were put to us and redeemed by us at par. After the redemption, $0.6 million aggregate principal amount of the Convertible Notes were outstanding as of September 30, 2016 . The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by us. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, are senior in right of payment to all of our future subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.

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

7.625% Senior Notes Due 2019

On September 27, 2011, we issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. On June 3, 2016, we completed the Debt Exchange, pursuant to which a holder of the 7.625% Senior Notes exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10 million newly issued shares of our common stock. Based on the fair value

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of the shares issued, we recognized an $8.7 million gain on extinguishment of debt on the Consolidated Statement of Operations for the nine months ended September 30, 2016 . After the Debt Exchange, $315.3 million aggregate principal amount of the 7.625% Senior Notes were outstanding as of September 30, 2016 .

The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are currently redeemable at our option at a specified redemption price. The 7.625% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

7.0% Senior Notes Due 2022

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

Lease Financing Obligation Due 2020

We have a Lease Financing Obligation with a balance of $2.9 million as of September 30, 2016 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 13 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, 2016												As of December 31, 2015
	Maturity Date	Principal				Unamortized Discount				Carrying Amount				Principal				Unamortized Discount				Carrying Amount
		(in thousands)
Amended Credit Facility	April 9, 2020	$	—			$	—			$	—			$	—			$	—			$	—
Convertible Notes (1)(2)	March 15, 2028	579				—				579				579				—				579
7.625% Senior Notes (3)	October 1, 2019	315,300				(2,366		)		312,934				400,000				(3,752		)		396,248
7.0% Senior Notes (4)	October 15, 2022	400,000				(4,408		)		395,592				400,000				(4,953		)		395,047
Lease Financing Obligation (5)	August 10, 2020	2,893				(4		)		2,889				3,222				(4		)		3,218
Total Debt		$	718,772			$	(6,778	)		$	711,994			$	803,801			$	(8,709	)		$	795,092
Less: Current Portion of Long-Term Debt (6)		450				—				450				440				—				440
Total Long-Term Debt		$	718,322			$	(6,778	)		$	711,544			$	803,361			$	(8,709	)		$	794,652

(1)	The aggregate estimated fair value of the Convertible Notes was approximately $0.6 million and $0.5 million as of September 30, 2016 and December 31, 2015 , respectively, based on reported market trades of these instruments.

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

(3)	The aggregate estimated fair value of the 7.625% Senior Notes was approximately $274.3 million and $270.2 million as of September 30, 2016 and December 31, 2015 , respectively, based on reported market trades of these instruments.

(4)	The aggregate estimated fair value of the 7.0% Senior Notes was approximately $310.0 million and $272.0 million as of September 30, 2016 and December 31, 2015 , respectively, based on reported market trades of these instruments.

(5)	The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.8 million and $3.1 million as of September 30, 2016 and December 31, 2015 , respectively. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.

(6)	The current portion of the long-term debt as of September 30, 2016 and December 31, 2015 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 7.625% Senior Notes and 7.0% Senior Notes and have assigned a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, Convertible Notes, 7.625% Senior Notes or 7.0% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Contractual Obligations. A summary of our contractual obligations as of and subsequent to September 30, 2016 is provided in the following table:

	Payments Due By Year
	Year 1				Year 2				Year 3				Year 4				Year 5				Thereafter				Total
	Twelve Months Ended September 30, 2017				Twelve Months Ended September 30, 2018				Twelve Months Ended September 30, 2019				Twelve Months Ended September 30, 2020				Twelve Months Ended September 30, 2021				After September 30, 2021
	(in thousands)
Notes payable (1)	$	553			$	538			$	—			$	—			$	—			$	—			$	1,091
7.625% Senior Notes (2)	24,042				24,042				24,042				327,321				—				—				399,447
7.0% Senior Notes (3)	28,000				28,000				28,000				28,000				28,000				442,000				582,000
Convertible Notes (4)	29				593				—				—				—				—				622
Lease Financing Obligation (5)	537				537				1,959				—				—				—				3,033
Office and office equipment leases and other (6)(7)	4,060				2,745				1,349				—				—				—				8,154
Firm transportation and processing agreements (8)	18,657				18,692				18,692				18,692				15,575				—				90,308
Asset retirement obligations (9)	417				393				238				41				250				9,710				11,049
Derivative liability (10)	—				244				38				—				—				—				282
Total	$	76,295			$	75,784			$	74,318			$	374,054			$	43,825			$	451,710			$	1,095,986

(1)	Included in notes payable is a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term of the letter of credit is April 30, 2018. There is currently no balance outstanding under the Amended Credit Facility.

(2)	On September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. On June 3, 2016, we completed the Debt Exchange, reducing our aggregate principal balance to $315.3 million. We are obligated to make annual interest payments through maturity in 2019 equal to $24.0 million.

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

(4)

On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012 approximately 85% of the outstanding Convertible Notes, representing $147.2 million of the then outstanding principal amount, were put to us. On March 20, 2015, approximately 98% of the remaining outstanding Convertible Notes, representing $24.8 million of the then outstanding principal amount, were put to us, leaving $0.6 million principal amount remaining. We are obligated to make semi-annual interest payments on the Convertible Notes until either we call the remaining Convertible Notes or the holders put the Convertible Notes to us, which is expected to occur by 2018.

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(5)	The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component. The Lease Financing Obligation contains an early buyout option pursuant to which we may purchase the equipment for $1.8 million on February 10, 2019.

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

(7)	Includes contractual obligations of $1.0 million related to certain drilling commitments.

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

(9)	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, 2015 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(10)

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, 2016 . 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, 2015 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, 2016 .

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, 2015 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, 2015 and the notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly Report on Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our primary market risk exposure is in the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. oil and natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. 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, 2016 , our income before income taxes would have decreased by approximately $0.7 million for each $1.00 per barrel decrease in crude oil prices, approximately $0.4 million for each $0.10 decrease per MMBtu in natural gas prices and $0.1 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

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

As of October 21, 2016 , 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 2016							For the year 2017							For the year 2018
	Derivative Volumes			Weighted Average Price				Derivative Volumes			Weighted Average Price				Derivative Volumes			Weighted Average Price
Oil (Bbls)	713,000			$	72.57			1,673,125			$	60.60			227,750			$	53.11
Natural Gas (MMbtu)	460,000			$	4.10			3,650,000			$	2.96			—			$	—

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

Our current recoverability test on our existing proved oil and gas properties as of September 30, 2016 uses commodity pricing based on 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, 2016 results in a surplus of future estimated net cash flows over carrying value of approximately $391.4 million and $114.4 million for the Uinta Oil Program and DJ Basin, respectively. We completed a sensitivity test on the surplus of future estimated net cash flows by decreasing the oil price by $1.00. Natural gas and NGL pricing were not considered in this sensitivity analysis as the majority of future cash flows from these two Basins are derived from oil revenues. We estimate that the surplus in the Uinta Oil program would decrease by approximately $15.0 million to $20.0 million and the DJ Basin would decrease by approximately $20.0 million to $25.0 million for every $1.00 decrease in the oil price assumptions used in the recoverability test. If impairment is necessary, we would reduce the carrying value to fair value. The factors used to determine fair value 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 used by market participants that are commensurate with the risks inherent in the development and production of the underlying oil and natural gas. If future commodity prices assumed in the recoverability test are not realized, it is likely that we will incur a significant impairment.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of September 30, 2016 , 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, 2016 .

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the third fiscal quarter of 2016 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, 2015 except as described below.

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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, 2015 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.

Land owner demands arising as a result of a recent decision of the Wyoming Supreme Court could have adverse effects on our business.

In December, 2015, the Wyoming Supreme Court issued its " Pennaco" decision, the essence of which is that parties to a contract, such as a surface use agreement, remain liable for the obligations under that agreement - even when the agreement and the underlying assets have been sold and assigned to a third party - unless the agreement contains express language releasing and discharging the original party upon such subsequent assignment.

Landowners across Wyoming are making Pennaco claims against companies that sold assets to other oil and gas companies that are now in default. To date, our exposure relates to coalbed methane ("CBM") leases and wells that we sold to entities which are now essentially defunct, if not in actual bankruptcy proceedings. These operators have defaulted on several annual surface use payments, as well as leaving more than 150 CBM wells acquired from the Company in non-producing (shut-in) status. The Company has been contacted by several ranches or their attorneys demanding payment of amounts in arrears, as well as conducting the plugging of the wells and land reclamation. Each case entails determining what contractual obligations are imposed by the applicable surface use agreement, taking into account state and federal plugging and reclamation requirements.

The Company obtained orders from the Wyoming Oil & Gas Conservation Commission ("WOGCC") requiring certain of the defaulting operators to "show cause" as to why the WOGCC should not authorize the Company to take over the wells in order to conduct plugging and reclamation operations. The Company is exploring a number of options including investigating third party interest in acquiring the wells, assumption of obligations related to the shallow CBM wells by operators holding "deep rights" under the leases, and negotiated settlement and release agreements with the ranches. It should also be noted that the WOGCC holds substantial plugging bonds posted by the defaulting operators. The Company is under no regulatory compulsion to plug these wells at this time.

At this time, the Company does not believe that resolving this matter will have a material financial impact. The Company believes that, if necessary, the currently identified roster of shut-in wells can be plugged, and reclaimed at cost of approximately $15,000 per well. There is no assurance, however, that this issue will not expand to wells sold to other purchasers of Wyoming assets previously owned by the Company.

Possible future ballot initiatives in Colorado, if approved, could have severely adverse effects on our operations, reserves and financial condition.

As previously disclosed, several statewide ballot initiatives were filed for the 2016 election cycle that sought to restrict or limit oil and natural gas development in Colorado. Proponents attempted to collect the required number of signatures to have two such proposals included on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a 2,500 foot statewide drilling setback from occupied structures and other sensitive areas. If implemented, this proposal would have had the effect of rendering the vast majority of the surface area of the state ineligible for drilling, including many of our planned future drilling locations. The second would have amended the state constitution to give local governmental authorities the ability to regulate, or to ban, oil and gas development activities within their boundaries notwithstanding state rules to the contrary. If implemented, this proposal could have caused us to be subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans on our activities in the state. The Colorado Secretary of State determined that proponents of these proposals did not submit a sufficient number of valid signatures for the proposals to be included on the November 2016 ballot. However, similar proposals, or other proposals limiting oil and natural gas development activities, could be made in the future. Because substantially all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.

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.

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Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended September 30, 2016 :

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, 2016	2,873			$	5.93			—			—
August 1 – 31, 2016	5,331			6.09				—			—
September 1 – 30, 2016	1,125			5.61				—			—
Total	9,329			$	5.98			—			—

(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.

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

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Exhibit Number		Description of Exhibits
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

		BILL BARRETT CORPORATION
Date:	November 3, 2016	By:		/s/ R. Scot Woodall
				R. Scot Woodall
				Chief Executive Officer and President
				(Principal Executive Officer)
Date:	November 3, 2016	By:		/s/ David R. Macosko
				David R. Macosko
				Senior Vice President-Accounting
				(Principal Accounting Officer)

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