Bill Barrett (BBG) 10-Q 2016 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2016

OR

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

For the transition period from to

Commission file number 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(303) 293-9100

(Registrant's telephone number, including area code)

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

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

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

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

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

There were 50,315,695 shares of $0.001 par value common stock outstanding on April 22, 2016.

INDEX TO FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements (Unaudited)	3
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	40
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	41
Item 4.	Mine Safety Disclosures	41
Item 5.	Other Information	41
Item 6.	Exhibits	41
SIGNATURES		42

2

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31, 2016			December 31, 2015
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	105,563		$	128,836
Accounts receivable, net of allowance for doubtful accounts	31,048			43,461
Derivative assets	80,374			99,809
Assets held for sale, net of amortization and impairment	33,717			—
Prepayments and other current assets	2,661			2,211
Total current assets	253,363			274,317
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	1,426,985			2,000,210
Unproved oil and gas properties, excluded from amortization	121,454			79,198
Furniture, equipment and other	26,698			26,021
	1,575,137			2,105,429
Accumulated depreciation, depletion, amortization and impairment	(433,508		)	(934,745		)
Total property and equipment, net	1,141,629			1,170,684
Deferred income taxes	30,849			38,219
Derivative assets	14,803			19,662
Deferred financing costs and other noncurrent assets	3,566			3,638
Total	$	1,444,210		$	1,506,520
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities	$	59,171		$	64,337
Amounts payable to oil and gas property owners	11,621			15,657
Production taxes payable	22,714			26,578
Deferred income taxes	30,849			38,219
Current portion of long-term debt	443			440
Liabilities associated with assets held for sale	4,785			—
Total current liabilities	129,583			145,231
Long-term debt, net of debt issuance costs	794,972			794,652
Asset retirement obligations	10,103			14,066
Derivatives and other noncurrent liabilities	3,575			3,155
Stockholders' equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 50,326,243 and 49,864,512 shares issued and outstanding at March 31, 2016 and December 31, 2015, respectively, with 1,707,252 and 1,471,508 shares subject to restrictions, respectively	49			48
Additional paid-in capital	924,374			921,318
Retained earnings (Accumulated deficit)	(418,446		)	(371,950		)
Treasury stock, at cost: zero shares at March 31, 2016 and December 31, 2015, respectively	—			—
Total stockholders' equity	505,977			549,416
Total	$	1,444,210		$	1,506,520

See notes to Unaudited Consolidated Financial Statements.

3

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2016			2015
	(in thousands, except share and per share data)
Operating and Other Revenues:
Oil, gas and NGL production	$	29,121		$	48,486
Other	313			548
Total operating and other revenues	29,434			49,034
Operating Expenses:
Lease operating expense	8,827			13,791
Gathering, transportation and processing expense	788			942
Production tax expense	(315		)	2,534
Exploration expense	27			33
Impairment, dry hole costs and abandonment expense	558			1,255
(Gain) Loss on divestitures	—			(38		)
Depreciation, depletion and amortization	42,016			52,254
Unused commitments	4,568			4,388
General and administrative expense	12,420			13,329
Total operating expenses	68,889			88,488
Operating Income (Loss)	(39,455		)	(39,454		)
Other Income and Expense:
Interest and other income	37			275
Interest expense	(15,746		)	(16,430		)
Commodity derivative gain (loss)	8,668			34,438
Gain (Loss) on extinguishment of debt	—			2,567
Total other income and expense	(7,041		)	20,850
Income (Loss) before Income Taxes	(46,496		)	(18,604		)
(Provision for) Benefit from Income Taxes	—			6,873
Net Income (Loss)	$	(46,496	)	$	(11,731	)
Net Income (Loss) Per Common Share, Basic	$	(0.96	)	$	(0.24	)
Net Income (Loss) Per Common Share, Diluted	$	(0.96	)	$	(0.24	)
Weighted Average Common Shares Outstanding, Basic	48,499,296			48,198,948
Weighted Average Common Shares Outstanding, Diluted	48,499,296			48,198,948

See notes to Unaudited Consolidated Financial Statements.

4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Three Months Ended March 31,
	2016			2015
	(in thousands)
Net Income (Loss)	$	(46,496	)	$	(11,731	)
Other comprehensive income (loss)	—			—
Comprehensive Income (Loss)	$	(46,496	)	$	(11,731	)

See notes to Unaudited Consolidated Financial Statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2016			2015
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(46,496	)	$	(11,731	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	42,016			52,254
Deferred income tax benefit	—			(6,873		)
Impairment, dry hole costs and abandonment expense	558			1,255
Total commodity derivative (gain) loss	(8,668		)	(34,438		)
Gain (Loss) on settlements of commodity derivatives	32,962			46,375
Stock compensation and other non-cash charges	3,329			2,743
Amortization of deferred financing costs	639			1,067
(Gain) Loss on extinguishment of debt	—			(2,567		)
(Gain) Loss on sale of properties	—			(38		)
Change in operating assets and liabilities:
Accounts receivable	12,413			9,064
Prepayments and other assets	(591		)	(1,364		)
Accounts payable, accrued and other liabilities	12,253			(1,661		)
Amounts payable to oil and gas property owners	(4,036		)	6,838
Production taxes payable	(3,864		)	(7,099		)
Net cash provided by (used in) operating activities	40,515			53,825
Investing Activities:
Additions to oil and gas properties, including acquisitions	(61,261		)	(111,009		)
Additions of furniture, equipment and other	(782		)	(609		)
Proceeds from sale of properties and other investing activities	(1,238		)	66,415
Cash paid for short-term investments	—			(114,883		)
Net cash provided by (used in) investing activities	(63,281		)	(160,086		)
Financing Activities:
Principal payments on debt	(109		)	(24,871		)
Deferred financing costs and other	(398		)	(1,000		)
Net cash provided by (used in) financing activities	(507		)	(25,871		)
Increase (Decrease) in Cash and Cash Equivalents	(23,273		)	(132,132		)
Beginning Cash and Cash Equivalents	128,836			165,904
Ending Cash and Cash Equivalents	$	105,563		$	33,772

See notes to Unaudited Consolidated Financial Statements.

6

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Accumulated Other Comprehensive Income		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		—			—			(384		)	—		(383		)
Stock-based compensation	—		3,440			—			—			—		3,440
Retirement of treasury stock	—		(384		)	—			384			—		—
Net income (loss)	—		—			(46,496		)	—			—		(46,496		)
Balance at March 31, 2016	$	49	$	924,374		$	(418,446	)	$	—		$	—	$	505,977

See notes to Unaudited Consolidated Financial Statements.

7

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

March 31, 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 March 31, 2016		As of December 31, 2015
	(in thousands)
Accrued oil, gas and NGL sales	$	22,775	$	33,594
Due from joint interest owners	6,434		8,373
Other	1,839		1,508
Allowance for doubtful accounts	—		(14		)
Total accounts receivable	$	31,048	$	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

8

proved reserves are added or not. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage 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 March 31, 2016			As of December 31, 2015
	(in thousands)
Proved properties	$	300,444		$	320,538
Wells and related equipment and facilities	1,064,556			1,592,716
Support equipment and facilities	56,149			77,785
Materials and supplies	5,836			9,171
Total proved oil and gas properties (1)	$	1,426,985		$	2,000,210
Unproved properties	31,554			33,336
Wells and facilities in progress	89,900			45,862
Total unproved oil and gas properties, excluded from amortization (1)	$	121,454		$	79,198
Accumulated depreciation, depletion, amortization and impairment (1)	(416,336		)	(918,510		)
Total oil and gas properties, net (1)	$	1,132,103		$	1,160,898

(1) Excludes oil and gas properties held for sale of $33.7 million, comprised of $572.2 million of proved oil and gas properties and $4.3 million of unproved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment of $542.8 million. Held for sale balances are included in current assets as assets held for sale, net of amortization and impairment, in the Unaudited Consolidated Balance Sheet as of March 31, 2016. See Note 4for additional information on assets held for sale.

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.

9

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.

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

	Three Months Ended March 31,
	2016		2015
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	—	$	—
Non-cash impairment of unproved oil and gas properties	183		58
Dry hole costs	57		15
Abandonment expense and lease expirations	318		1,182
Total non-cash impairment, dry hole costs and abandonment expense	$	558	$	1,255

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 March 31, 2016		As of December 31, 2015
	(in thousands)
Accrued drilling, completion and facility costs	$	16,296	$	32,895
Accrued lease operating, gathering, transportation and processing expenses	5,031		4,930
Accrued general and administrative expenses	5,282		10,962
Accrued interest payable	28,545		13,918
Trade payables and other	4,017		1,632
Total accounts payable and accrued liabilities	$	59,171	$	64,337

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

Revenue Recognition. Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenues are recorded on the basis of gas and NGLs actually sold by the Company. In addition, the Company records revenues for its share of gas and NGLs sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenues for other owners' volumetric share of gas and NGLs sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's remaining over- and under-produced gas and NGLs balancing positions are taken into account in determining the Company's proved oil, gas and NGL reserves. Imbalances at March 31, 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.

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 March 31, 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 months ended March 31, 2016 and 2015.

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

	Three Months Ended March 31,
	2016			2015
	(in thousands, except per share amounts)
Net income (loss)	$	(46,496	)	$	(11,731	)
Basic weighted-average common shares outstanding in period	48,499			48,199
Diluted weighted-average common shares outstanding in period	48,499			48,199
Basic net income (loss) per common share	$	(0.96	)	$	(0.24	)
Diluted net income (loss) per common share	$	(0.96	)	$	(0.24	)

New Accounting Pronouncements. In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 the 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 be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is effective for the 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.

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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 sheets 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.

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:

	Three Months Ended March 31,
	2016			2015
	(in thousands)
Cash paid for interest	$	480		$	1,105
Cash paid for income taxes	—			1,050
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	17,518			74,984
Change in asset retirement obligations, net of disposals	(60		)	(525		)
Retirement of treasury stock	(384		)	(975		)

4. Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are analyzed for impairment to identify and expense any excess of carrying value over fair value less costs to sell. In addition, the assets are no longer depreciated or depleted.

During the three months ended March 31, 2016, the Company committed to a plan to sell certain non-core assets in the Uinta Basin. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of March 31, 2016. Assets held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value of the net assets held for sale was $28.9 million and was presented as assets held for sale, net of amortization and impairment, of $33.7 million and liabilities associated with assets held for sale of $4.8 million on the Unaudited Consolidated Balance Sheet as of March 31, 2016.

5. Long-Term Debt

The Company's outstanding debt is summarized below:

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		As of March 31, 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	400,000		(3,502		)	396,498		400,000		(3,752		)	396,248
7.0% Senior Notes (4)	October 15, 2022	400,000		(4,771		)	395,229		400,000		(4,953		)	395,047
Lease Financing Obligation (5)	August 10, 2020	3,113		(4		)	3,109		3,222		(4		)	3,218
Total Debt		$	803,692	$	(8,277	)	$	795,415	$	803,801	$	(8,709	)	$	795,092
Less: Current Portion of Long-Term Debt (6)		443		—			443		440		—			440
Total Long-Term Debt		$	803,249	$	(8,277	)	$	794,972	$	803,361	$	(8,709	)	$	794,652

(1) The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of March 31, 2016 and December 31, 2015 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 $270.0 million and $270.2 million as of March 31, 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 $242.0 million and $272.0 million as of March 31, 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 $3.0 million as of March 31, 2016 and $3.1 million as of December 31, 2015. 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 March 31, 2016 and December 31, 2015 includes the current portion of the Lease Financing Obligation.

Amended Credit Facility

The Amended Credit Facility had commitments and a borrowing base of $375.0 million from 13 lenders as of March 31, 2016. As of March 31, 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 March 31, 2016 to $349.0 million.

Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the unused commitment fee is between 0.375% and 0.5% based on borrowing base utilization. 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 April 11, 2016, the borrowing base was reduced to $335.0 million based on proved reserves and commodity hedge position in place at December 31, 2015. The Company's re-determined borrowing capacity of $335.0 million is reduced by $26.0 million to $309.0 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 also 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

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maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could 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 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 March 31, 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. 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

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.

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Lease Financing Obligation Due 2020

The Company has a lease financing obligation with a balance of $3.1 million as of March 31, 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 12 for discussion of aggregate minimum future lease payments.

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

	Three Months Ended March 31,
	2016		2015
	(in thousands)
Amended Credit Facility (1)
Cash interest	$	438	$	433
Non-cash interest	$	207	$	586
Convertible Notes (2)
Cash interest	$	22	$	276
Non-cash interest	$	—	$	3
7.625% Senior Notes (3)
Cash interest	$	7,625	$	7,625
Non-cash interest	$	250	$	273
7.0% Senior Notes (4)
Cash interest	$	7,000	$	7,000
Non-cash interest	$	181	$	204
Lease Financing Obligation (5)
Cash interest	$	26	$	29
Non-cash interest	$	—	$	—

(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 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.

(3) 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.

(4) 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.

(5) 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 three months ended March 31, 2016 is as follows (in thousands):

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As of December 31, 2015	$	15,176
Liabilities incurred	—
Liabilities settled	(8		)
Disposition of properties	(52		)
Accretion expense	274
Revisions to estimate	—
As of March 31, 2016	$	15,390
Less: liabilities associated with assets held for sale	4,785
Less: current asset retirement obligations	502
Long-term asset retirement obligations	$	10,103

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.

	As of March 31, 2016
	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets
Cash equivalents (1)	$	60,095	$	—	$	—	$	60,095
Deferred compensation plan (1)	1,208		—		—		1,208
Commodity derivatives (1)	—		95,184		—		95,184
Assets held for sale (2)	—		—		33,717		33,717
Liabilities
Commodity derivatives (1)	$	—	$	7	$	—	$	7
Liabilities associated with assets held for sale (2)	—		—		4,785		4,785

(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.

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	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, which approximates fair value, which represent Level 1 inputs.

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 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.

Properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The fair value of net assets classified as held for sale was $28.9 million as of March 31, 2016. See Note 4 for additional information on assets held for sale.

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 $512.0 million as of March 31, 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.

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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 and the Company's borrowing base utilization. The Amended Credit Facility had a balance of zero as of March 31, 2016 and December 31, 2015. The Convertible Notes had a fair value of $0.5 million as of March 31, 2016 and December 31, 2015 and are measured based on market-based parameters of the various components of the Convertible Notes and over the counter trades. The Lease Financing Obligation fair values of $3.0 million and $3.1 million as of March 31, 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.

	As of March 31, 2016
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet				Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets (current)	$	80,381		$	(7	)	(1)	$	80,374
Derivative assets (noncurrent)	14,803			—				14,803
Total derivative assets	$	95,184		$	(7	)		$	95,177
	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	$	(7	)	$	7		(1)	$	—
Derivatives and other noncurrent liabilities	—			—				—
Total derivative liabilities	$	(7	)	$	7			$	—
	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.

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As of March 31, 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:

	April – December 2016			For the year 2017
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	1,906,300	$	78.25	683,250	$	75.61
Natural Gas (MMbtu)	1,375,000	$	4.10	—	$	—

The Company's derivative financial instruments are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had derivatives in place with eight different counterparties as of March 31, 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 Facility or other obligations against monies owed to the Company under the derivative contracts. Where the counterparty is not a lender under the Company's Amended Credit Facility, it may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.

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 months ended March 31, 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 months ended March 31, 2016 and 2015.

Income tax benefit for the three months ended March 31, 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 months ended March 31, 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. 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

19

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 March 31,
	2016		2015
	(in thousands)
Common stock options (1)	$	69	$	242
Nonvested common stock (1)	2,404		1,574
Nonvested common stock units (1)	290		261
Nonvested performance-based shares (1)	678		430
Nonvested performance cash units (2)	485		251
Total	$	3,926	$	2,758

(1) Unrecognized compensation cost as of March 31, 2016 was $9.8 million related to grants of nonvested stock options and nonvested shares of common stock that are expected to be recognized over a weighted-average period of 2.1 years.

(2) The nonvested performance-based cash units are liability awards with $0.9 million and $0.4 million in derivatives and other noncurrent liabilities in the Unaudited Consolidated Balance Sheets as of March 31, 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 March 31, 2016			Three Months Ended March 31, 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	622,609	$	12.30
Nonvested common stock units	3,014	$	6.22	2,259	$	8.30
Nonvested performance-based shares	—	$	—	—	$	—
Total granted	689,514			624,868
	Three Months Ended March 31, 2016			Three Months Ended March 31, 2015
Cash Awards	Number of Units	Fair Value Per Unit		Number of Units	Fair Value Per Unit
Nonvested performance cash units	646,572	$	6.22	405,836	$	12.31

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.

11. 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,

20

will be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange, at market prices, in block transactions, to or through a market maker, through an electronic communications network or as otherwise agreed by the Company and the Manager. As of March 31, 2016, no shares have been sold pursuant to the Agreement.

12. Commitments and Contingencies

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

	As of March 31, 2016
	(in thousands)
2016	$	403
2017	537
2018	537
2019	1,825
2020	—
Thereafter	—
Total	$	3,302

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 March 31, 2016
	(in thousands)
2016	$	13,774
2017	18,692
2018	18,692
2019	18,692
2020	18,692
Thereafter	10,902
Total	$	99,444

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:

	As of March 31, 2016
	(in thousands)
2016 (1)	$	5,715
2017	2,882
2018	2,591
2019	633
2020	—
Thereafter	—
Total	$	11,821

21

(1) Includes a contractual obligation of $3.2 million related to certain drilling commitments on sold properties.

Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. It is the opinion of the Company's management that current claims and litigation involving the Company are not likely to have a material adverse effect on its Unaudited Consolidated Balance Sheet, Cash Flows or Statements of Operations.

13. Guarantor Subsidiaries

In addition to the Amended Credit Facility, the 7.625% 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 March 31, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Assets:
Current assets	$	253,100		$	263		$	—	$	253,363
Property and equipment, net	1,135,183			6,446			—		1,141,629
Intercompany receivable (payable)	21,316			(21,316		)	—		—
Investment in subsidiaries	(14,660		)	—			14,660		—
Noncurrent assets	49,218			—			—		49,218
Total assets	$	1,444,157		$	(14,607	)	$	14,660	$	1,444,210
Liabilities and Stockholders' Equity:
Current liabilities	$	129,530		$	53		$	—	$	129,583
Long-term debt	794,972			—			—		794,972
Other noncurrent liabilities	13,678			—			—		13,678
Stockholders' equity	505,977			(14,660		)	14,660		505,977
Total liabilities and stockholders' equity	$	1,444,157		$	(14,607	)	$	14,660	$	1,444,210

22

	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 March 31, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	29,266		$	168		$	—		$	29,434
Operating expenses	(56,305		)	(164		)	—			(56,469		)
General and administrative	(12,420		)	—			—			(12,420		)
Interest income and other income (expense)	(7,041		)	—			—			(7,041		)
Income (loss) before income taxes and equity in earnings of subsidiaries	(46,500		)	4			—			(46,496		)
(Provision for) Benefit from income taxes	—			—			—			—
Equity in earnings (loss) of subsidiaries	4			—			(4		)	—
Net income (loss)	$	(46,496	)	$	4		$	(4	)	$	(46,496	)

	Three Months Ended March 31, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	48,896		$	138		$	—	$	49,034
Operating expenses	(74,998		)	(161		)	—		(75,159		)
General and administrative	(13,329		)	—			—		(13,329		)
Interest and other income (expense)	20,850			—			—		20,850
Income (loss) before income taxes and equity in earnings of subsidiaries	(18,581		)	(23		)	—		(18,604		)
(Provision for) Benefit from income taxes	6,873			—			—		6,873
Equity in earnings (loss) of subsidiaries	(23		)	—			23		—
Net income (loss)	$	(11,731	)	$	(23	)	$	23	$	(11,731	)

Condensed Consolidating Statements of Comprehensive Income (Loss)

23

	Three Months Ended March 31, 2016
	Parent Issuer			Guarantor Subsidiaries		Intercompany Eliminations			Consolidated
	(in thousands)
Net income (loss)	$	(46,496	)	$	4	$	(4	)	$	(46,496	)
Other comprehensive income (loss)	—			—		—			—
Comprehensive income (loss)	$	(46,496	)	$	4	$	(4	)	$	(46,496	)

	Three Months Ended March 31, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Net income (loss)	$	(11,731	)	$	(23	)	$	23	$	(11,731	)
Other comprehensive income (loss)	—			—			—		—
Comprehensive income (loss)	$	(11,731	)	$	(23	)	$	23	$	(11,731	)

Condensed Consolidating Statements of Cash Flows

	Three Months Ended March 31, 2016
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	40,419		$	96		$	—		$	40,515
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(61,261		)	—			—			(61,261		)
Additions to furniture, fixtures and other	(782		)	—			—			(782		)
Proceeds from sale of properties and other investing activities	(1,238		)	—			—			(1,238		)
Intercompany transfers	96			—			(96		)	—
Cash flows from financing activities:
Principal payments on debt	(109		)	—			—			(109		)
Intercompany transfers	—			(96		)	96			—
Other financing activities	(398		)	—			—			(398		)
Change in cash and cash equivalents	(23,273		)	—			—			(23,273		)
Beginning cash and cash equivalents	128,836			—			—			128,836
Ending cash and cash equivalents	$	105,563		$	—		$	—		$	105,563

24

	Three Months Ended March 31, 2015
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	53,788		$	37		$	—		$	53,825
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	(112,105		)	1,096			—			(111,009		)
Additions to furniture, fixtures and other	(609		)	—			—			(609		)
Proceeds from sale of properties and other investing activities	66,415			—			—			66,415
Cash paid for short-term investments	(114,883		)	—			—			(114,883		)
Intercompany transfers	1,133						(1,133		)	—
Cash flows from financing activities:
Principal payments on debt	(24,871		)	—			—			(24,871		)
Intercompany transfers	—			(1,133		)	1,133			—
Other financing activities	(1,000		)	—			—			(1,000		)
Change in cash and cash equivalents	(132,132		)	—			—			(132,132		)
Beginning cash and cash equivalents	165,904			—			—			165,904
Ending cash and cash equivalents	$	33,772		$	—		$	—		$	33,772

14. Subsequent Events

On April 28, 2016, the Company entered into a purchase and sale agreement for the sale of certain non-core assets in the Uinta Basin. Total gross consideration, prior to customary 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. The transaction is expected to close during the three months ended June 30, 2016. The related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of March 31, 2016.

25

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;

• derivative and hedging activities;

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

• solely operating in the Rocky Mountain region;

• compliance with environmental and other regulations;

• economic and competitive conditions;

• occurrence of property divestitures or acquisitions;

• 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, equity market conditions and availability of capital;

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

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

• 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 other contractual obligations;

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

• changes in tax laws and statutory tax rates; and

• other uncertainties, including those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2015 under the "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" sections and in Item 1A, "Risk Factors" of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management's views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to 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.

26

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 2015 and into 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 current hedges are realized in 2016 and 2017.

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 April 11, 2016, the borrowing base was reduced to $335.0 million based on proved reserves in place at December 31, 2015. Our re-determined borrowing base of $335.0 million is reduced by $26.0 million to $309.0 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.

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 1,906,300 barrels of oil and 1,375,000 MMbtu of natural gas or approximately 46% of our expected 2016 production and 683,250 barrels of oil for our 2017 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 April 28, 2016, the Company entered into a purchase and sale agreement for the sale of certain non-core assets in the Uinta Basin. Total gross consideration, prior to customary 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. The transaction is expected to close during the three months ended June 30, 2016. The related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of March 31, 2016.

27

Three Months Ended March 31, 2016 Compared with Three Months Ended March 31, 2015

	Three Months Ended March 31,						Increase (Decrease)
	2016			2015			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil, gas and NGL production	$	29,121		$	48,486		$	(19,365	)	(40	)%
Other	313			548			(235		)	(43	)%
Operating Expenses
Lease operating expense	8,827			13,791			(4,964		)	(36	)%
Gathering, transportation and processing expense	788			942			(154		)	(16	)%
Production tax expense	(315		)	2,534			(2,849		)	*nm
Exploration expense	27			33			(6		)	(18	)%
Impairment, dry hole costs and abandonment expense	558			1,255			(697		)	(56	)%
(Gain) Loss on divestitures	—			(38		)	38			*nm
Depreciation, depletion and amortization	42,016			52,254			(10,238		)	(20	)%
Unused commitments	4,568			4,388			180			4	%
General and administrative expense (1)	8,494			10,279			(1,785		)	(17	)%
Long-term cash and equity incentive compensation (1)	3,926			3,050			876			29	%
Total operating expenses	$	68,889		$	88,488		$	(19,599	)	(22	)%
Production Data:
Oil (MBbls)	886			1,125			(239		)	(21	)%
Natural gas (MMcf)	1,626			1,764			(138		)	(8	)%
NGLs (MBbls)	210			162			48			30	%
Combined volumes (MBoe)	1,367			1,581			(214		)	(14	)%
Daily combined volumes (Boe/d)	15,022			17,567			(2,545		)	(14	)%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	27.60		$	37.12		$	(9.52	)	(26	)%
Natural gas (per Mcf)	1.66			2.60			(0.94		)	(36	)%
NGLs (per Bbl)	9.43			13.31			(3.88		)	(29	)%
Combined (per Boe)	21.30			30.68			(9.38		)	(31	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	63.69		$	76.28		$	(12.59	)	(17	)%
Natural gas (per Mcf)	2.26			3.92			(1.66		)	(42	)%
NGLs (per Bbl)	9.43			13.31			(3.88		)	(29	)%
Combined (per Boe)	45.42			60.01			(14.59		)	(24	)%
Average Costs (per Boe):
Lease operating expense	$	6.46		$	8.72		$	(2.26	)	(26	)%
Gathering, transportation and processing expense	0.58			0.60			(0.02		)	(3	)%
Production tax expense	(0.23		)	1.60			(1.83		)	*nm
Depreciation, depletion and amortization	30.74			33.05			(2.31		)	(7	)%
General and administrative expense (2)	6.21			6.50			(0.29		)	(4	)%

* Not meaningful.

(1) Long-term cash and equity incentive compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $12.4 million and $13.3 million for the three months ended March 31, 2016 and 2015, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of long-term cash and equity incentive compensation from general and administrative expense allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with cash performance compensation programs and stock-based grants.

28

(2) Excludes long-term cash and equity incentive compensation as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including long-term cash and equity incentive compensation, as presented in the Unaudited Consolidated Statements of Operations, were $9.09 and $8.43 for the three months ended March 31, 2016 and 2015, respectively.

Production Revenues and Volumes. Production revenues decreased to $29.1 million for the three months ended March 31, 2016 from $48.5 million for the three months ended March 31, 2015. The decrease in production revenues was due to a 31% decrease in average realized prices before hedging and a 14% decrease in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately $14.8 million, while the decrease in production volumes reduced production revenues by approximately $4.6 million.

Total production volumes of 1.4 MMBoe for the three months ended March 31, 2016 decreased from 1.6 MMBoe for the three months ended March 31, 2015. The decrease is primarily related to a 41% decrease in production from the Uinta Oil Program due to natural production declines with no significant drilling or recompletion activities to offset these declines. In addition, overall production declined due to non core asset sales in the DJ Basin. Additional information concerning production is in the following table:

	Three Months Ended March 31, 2016				Three Months Ended March 31, 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 (1)	638	198	1,356	1,062	707	136	1,248	1,051	(10	)%	46	%	9	%	1	%
Uinta Oil Program	247	12	270	304	401	26	504	511	(38	)%	(54	)%	(46	)%	(41	)%
Other	1	—	—	1	17	—	12	19	*nm		*nm		*nm		*nm
Total	886	210	1,626	1,367	1,125	162	1,764	1,581	(21	)%	30	%	(8	)%	(14	)%

* Not meaningful.

(1) Includes oil, NGL and natural gas volumes of 62 MBbls, 24 MBbls and 292 MMcf, respectively, from the DJ Basin non core asset sales for the three months ended March 31, 2015.

Lease Operating Expense ("LOE"). LOE decreased to $6.46 per Boe for the three months ended March 31, 2016 from $8.72 per Boe for the three months ended March 31, 2015. The decrease per Boe for the three months ended March 31, 2016 compared with the three months ended March 31, 2015 is related to operational efficiencies, a decrease in service industry costs, reduced workover activity in the Uinta Basin and our decision to shut-in certain Uinta Basin wells due to the current low commodity price environment.

Production Tax Expense. Total production taxes decreased to a credit of $0.3 million for the three months ended March 31, 2016 from $2.5 million for the three months ended March 31, 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 31% 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 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 March 31, 2016 and 2015 are summarized below:

29

	Three Months Ended March 31,
	2016			2015
	(in thousands)
Non-cash impairment of proved oil and gas properties	$	—		$	—
Non-cash impairment of unproved oil and gas properties	183		(1)	58
Dry hole expense	57			15
Abandonment expense	318			1,182
Total non-cash impairment, dry hole costs and abandonment expense	$	558		$	1,255

(1) The $0.2 million of non-cash impairment expense relating to unproved oil and gas properties is the result of unfavorable market conditions and no future plans to evaluate the remaining acreage.

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, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk 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.

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 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. If our attempts to market interests in certain properties to industry partners are unsuccessful, we may record additional leasehold impairments.

Given the decline in 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 March 31, 2016 uses commodity pricing based on a combination of assumptions management uses in its budgeting and forecasting process adjusted 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 March 31, 2016 results in a surplus of future estimated net cash flows over carrying value of approximately $372.0 million and $363.0 million for the Uinta Oil Program and DJ Basin, respectively. 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 $35.0 million to $40.0 million for every $1.00 decrease in the oil price assumptions management uses in its budgeting and forecasting process. 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 management's budgeting and forecasting process are not realized, it is likely that we will incur a significant impairment.

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Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $42.0 million for the three months ended March 31, 2016 compared with $52.3 million for the three months ended March 31, 2015. The decrease of $10.2 million was a result of the 14% decrease in production for the three months ended March 31, 2016 compared with the three months ended March 31, 2015 and a decrease in the DD&A rate. The decrease in production accounted for a $7.0 million decrease in DD&A expense, while the overall decrease in the DD&A rate accounted for a $3.2 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 three months ended March 31, 2016, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $30.74 per Boe compared with $33.05 per Boe for the three months ended March 31, 2015.

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 of $1.5 million regardless of the amount of pipeline capacity utilized and expire July 31, 2021.

General and Administrative Expense. General and administrative expense, excluding long-term cash and equity incentive compensation, decreased to $8.5 million for the three months ended March 31, 2016 from $10.3 million for the three months ended March 31, 2015 primarily due to a reduction of employee related costs and benefits. General and administrative expense, excluding long-term cash and equity incentive compensation, is a non-GAAP measure. See Note 2 to the table on page 28 for a reconciliation and explanation.

Long-term cash and equity incentive compensation for the three months ended March 31, 2016 and 2015 was $3.9 million and $3.1 million, respectively. The components of long-term cash and equity incentive compensation for the three months ended March 31, 2016 and 2015 are shown in the following table:

	Three Months Ended March 31,
	2016		2015
	(in thousands)
Stock options and nonvested shares of common stock	$	3,422	$	2,510
Shares issued for 401(k) plan (1)	—		270
Shares issued for directors' fees	19		19
Performance cash units	485		251
Total	$	3,926	$	3,050

(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 $15.7 million for the three months ended March 31, 2016 from $16.4 million for the three months ended March 31, 2015. The decrease for the three months ended March 31, 2016 was primarily due to our weighted average interest rate for the three months ended March 31, 2016 decreasing to 7.8% compared to 8.0% for the three months ended March 31, 2015.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $8.7 million for the three months ended March 31, 2016 compared with a gain of $34.4 million for the three months ended March 31, 2015. The gain or loss on commodity derivatives is related to fluctuations of oil, natural gas and NGL future pricing compared to actual pricing of commodity hedges in place as of March 31, 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:

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	Three Months Ended March 31,
	2016			2015
	(in thousands)
Realized gain (loss) on derivatives (1)	$	32,962		$	46,375
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	(29,486		)	(40,734		)
Unrealized gain (loss) on derivatives (1)	5,192			28,797
Total commodity derivative gain (loss)	$	8,668		$	34,438

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

During the three months ended March 31, 2016, approximately 75% of our oil volumes and 27% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $32.0 million and natural gas income of $1.0 million after settlements for all commodity derivatives. The $33.0 million gain on settlements for the three months ended March 31, 2016 was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

During the three months ended March 31, 2015, approximately 90% of our oil volumes and 97% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $44.0 million and natural gas income of $2.4 million after settlements for all commodity derivatives. The $46.4 million gain on settlements for the three months ended March 31, 2015 was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

Income Tax (Expense) Benefit. For three months ended March 31, 2016, we recorded a valuation allowance against our deferred tax asset balance which reduced our effective tax rate to zero. For the three months ended March 31, 2015, the income tax benefit was $6.9 million resulting in an effective tax rate of 36.9%. 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 primarily 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, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility for our planned uses of capital for the remainder of 2015. However, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions, such as additional property dispositions, if we believe conditions to be favorable.

At March 31, 2016, we had cash and cash equivalents of $105.6 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 $375.0 million as of March 31, 2016. Our remaining borrowing capacity was reduced by $26.0 million to $349.0 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 April 11,

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2016, the borrowing base was reduced to $335.0 million based on December 31, 2015 reserves. Our re-determined borrowing capacity of $335.0 million is reduced by $26.0 million to $309.0 million due to the letter of credit related to a firm transportation agreement.

Cash Flow from Operating Activities

Net cash provided by operating activities for the three months ended March 31, 2016 and 2015 was $40.5 million and $53.8 million, respectively. The decrease in net cash provided by operating activities was primarily due to a decrease in production revenues and derivative settlements.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production revenues. At March 31, 2016, we had in place crude oil swaps covering portions of our 2016 and 2017 production and natural gas swaps covering portions of our 2016 production.

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

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

At March 31, 2016, the estimated fair value of all of our commodity derivative instruments, summarized in the following table, was a net asset of $95.2 million, comprised of current and noncurrent assets.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price (1)	Fair Market Value (in thousands)
Swap Contracts:
2016
Oil	1,906,300	Bbls	$	78.25	WTI	$	71,515
Natural gas	1,375,000	MMBtu	$	4.10	NWPL	2,839
2017
Oil	683,250	Bbls	$	75.61	WTI	20,823
Total						$	95,177

(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 subsequent to March 31, 2016 through April 22, 2016.

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Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price
Swap Contracts:
2016
Oil	92,000	Bbls	$	45.00	WTI
2017
Oil	113,125	Bbls	$	45.45	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 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:

	Three Months Ended March 31,
Basin/Area	2016		2015
	(in millions)
DJ	$	44.1	$	99.6
Uinta Oil Program	0.7		12.9
Other	1.0		1.8
Total	$	45.8	$	114.3

	Three Months Ended March 31,
	2016		2015
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	0.8	$	1.6
Drilling, development, exploration and exploitation of oil and natural gas properties	42.4		108.1
Gathering and compression facilities	1.9		2.7
Geologic and geophysical costs	—		1.3
Furniture, fixtures and equipment	0.7		0.6
Total	$	45.8	$	114.3

Our current estimated capital expenditure budget in 2016 is between $90.0 million and $135.0 million, with all drilling activities targeting oil. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures throughout the year as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline to levels below our

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acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity generally by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow. The 2016 capital program is designed to closely align capital expenditures with expected cash flows as certain drilling activity may be deferred to protect the Company's 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

The Amended Credit Facility had commitments and a borrowing base of $375.0 million from 13 lenders as of March 31, 2016. As of March 31, 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 of the Amended Credit Facility as of March 31, 2016 to $349.0 million.

Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the unused commitment fee is between 0.375% to 0.5% based on borrowing base utilization. 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 April 11, 2016, the borrowing base was reduced to $335.0 million based on proved reserves in place at December 31, 2015. Our re-determined borrowing capacity of $335.0 million is reduced by $26.0 million to $309.0 million due to the 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 also 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. Realization of any of these factors could 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 March 31, 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

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unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.

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

7.625% Senior Notes Due 2019

On September 27, 2011, we issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are 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 $3.1 million as of March 31, 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 12 to the accompanying Unaudited Consolidated Financial Statements for a discussion of aggregate minimum future lease payments.

Our outstanding debt is summarized below:

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		As of March 31, 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)	March 15, 2028 (2)	579		—			579		579		—			579
7.625% Senior Notes (3)	October 1, 2019	400,000		(3,502		)	396,498		400,000		(3,752		)	396,248
7.0% Senior Notes (4)	October 15, 2022	400,000		(4,771		)	395,229		400,000		(4,953		)	395,047
Lease Financing Obligation (5)	August 10, 2020	3,113		(4		)	3,109		3,222		(4		)	3,218
Total Debt		$	803,692	$	(8,277	)	$	795,415	$	803,801	$	(8,709	)	$	795,092
Less: Current Portion of Long-Term Debt (6)		443		—			443		440		—			440
Total Long-Term Debt		$	803,249	$	(8,277	)	$	794,972	$	803,361	$	(8,709	)	$	794,652

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

(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 $270.0 million and $270.2 million as of March 31, 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 $242.0 million and $272.0 million as of March 31, 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 $3.0 million and $3.1 million as of March 31, 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 March 31, 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 March 31, 2016 is provided in the following table:

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	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	Twelve Months Ended March 31, 2017		Twelve Months Ended March 31, 2018		Twelve Months Ended March 31, 2019		Twelve Months Ended March 31, 2020		Twelve Months Ended March 31, 2021		After March 31, 2021
	(in thousands)
Notes payable (1)	$	553	$	553	$	45	$	—	$	—	$	—	$	1,151
7.625% Senior Notes (2)	30,500		30,500		30,500		430,500		—		—		522,000
7.0% Senior Notes (3)	28,000		28,000		28,000		28,000		28,000		456,000		596,000
Convertible Notes (4)	29		607		—		—		—		—		636
Lease Financing Obligation (5)	537		537		2,228		—		—		—		3,302
Office and office equipment leases and other (6)(7)	6,440		2,822		2,559		—		—		—		11,821
Firm transportation and processing agreements (8)	18,447		18,692		18,692		18,692		18,692		6,229		99,444
Asset retirement obligations (9)	502		58		3		233		66		14,528		15,390
Total	$	85,008	$	81,769	$	82,027	$	477,425	$	46,758	$	476,757	$	1,249,744

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

(2) On September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. We are obligated to make annual interest payments through maturity in 2019 equal to $30.5 million.

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

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

(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 the Company 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 a contractual obligation of $3.2 million related to certain drilling commitments on sold properties.

(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) This balance includes asset retirement obligations of $4.8 million at March 31, 2016 related to assets held for sale. 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.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of March 31, 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.

Critical Accounting Policies and Estimates

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We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 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 three months ended March 31, 2016, our income before income taxes would have decreased by approximately $0.2 million for each $1.00 per barrel decrease in crude oil prices, a de minimis amount for each $0.10 decrease per MMBtu in natural gas prices and $0.2 million for each $1.00 per barrel decrease in NGL prices.

We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty. These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations.

As of April 22, 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."

	April – December 2016			For the year 2017
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	1,998,300	$	76.72	796,375	$	71.33
Natural Gas (MMbtu)	1,375,000	$	4.10	—	$	—

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 March 31, 2016 uses commodity pricing based on a combination of assumptions management uses in its budgeting and forecasting process adjusted 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 March 31, 2016 results in a surplus of future estimated net cash flows over carrying value of approximately $372.0 million and $363.0 million for the Uinta Oil Program and DJ Basin, respectively. 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 $35.0 million to $40.0 million for every $1.00 decrease in the oil price assumptions management uses in its budgeting and forecasting process. 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 management's budgeting and forecasting process are not realized, it is likely that we will incur a significant impairment.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of March 31, 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 March 31, 2016.

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the first 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. 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.

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

Unregistered Sales of Securities

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

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended March 31, 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
January 1 – 31, 2016	229	$	2.83	—	—
February 1 – 29, 2016	117,643	2.89		—	—
March 1 – 31, 2016	7,946	5.40		—	—
Total	125,818	$	3.05	—	—

(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.

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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
10.1	Deferred Compensation Plan.
10.2	Severance Agreement with Robert W. Howard, dated March 14, 2016. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2016.]
10.3	Severance Agreement with Larry A. Parnell, dated April 8, 2016. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 8, 2016.]
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer.
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Principal Financial Officer.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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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:	May 5, 2016	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President
			(Principal Executive Officer)
Date:	May 5, 2016	By:	/s/ David R. Macosko
			David R. Macosko
			Senior Vice President-Accounting
			(Principal Accounting Officer)

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