10-Q

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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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: 001-35467

Halcón Resources Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 1311
(Primary Standard Industrial
Classification Code Number) 20-0700684
(I.R.S. Employer
Identification Number)

1000 Louisiana Street, Suite 6700, Houston, TX 77002
(Address of principal executive offices)

(832) 538-0300
(Registrant's telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

        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 twelve 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. Yes ý    No o

        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). Yes ý    No o

        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 ý 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). Yes o    No ý

        At July 22, 2016, 122,639,612 shares of the Registrant's Common Stock were outstanding.

TABLE OF CONTENTS

		Page
PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements (Unaudited)		5
	Condensed Consolidated Statements of Operations (Unaudited) for the Three and Six Months Ended June 30, 2016 and 2015		5
	Condensed Consolidated Balance Sheets as of June 30, 2016 (Unaudited) and December 31, 2015		6
	Condensed Consolidated Statements of Stockholders' Equity for the Six Months Ended June 30, 2016 (Unaudited) and Year Ended December 31, 2015		7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2016 and 2015		8
	Notes to Unaudited Condensed Consolidated Financial Statements		9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		49
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		64
ITEM 4.	Controls and Procedures		65
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings		66
ITEM 1A.	Risk Factors		66
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		70
ITEM 3.	Defaults Upon Senior Securities		70
ITEM 4.	Mine Safety Disclosures		71
ITEM 5.	Other Information		71
ITEM 6.	Exhibits		72
Signatures			74

2

Special note regarding forward-looking statements

        This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition or divestiture opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2015 and herein as well as the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

•

the potential adverse impact of the restructuring transactions on our operations, management, and employees and the risks associated with operating our business during the restructuring process;

•

our ability to satisfy the conditions set forth in the Restructuring Support Agreement and consummate the Plan outlined in the Restructuring Support Agreement or another plan of reorganization;

•

risks and uncertainties associated with chapter 11 proceedings;

•

our ability to reduce the level of our debt and lower our cash interest obligations through consummation of the Plan or otherwise;

•

volatility in commodity prices for oil and natural gas, including the current sustained decline in the price for oil;

•

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and fully develop our undeveloped acreage positions;

•

we have substantial indebtedness and may incur more debt;

•

higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;

•

our ability to replace our oil and natural gas reserves;

•

our ability to successfully develop our large inventory of undeveloped acreage in our resource plays;

•

our ability to retain key members of senior management, the board of directors, and key technical employees;

•

access to and availability of water and other treatment materials to carry out fracture stimulations in our resource plays;

•

access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices;

3

•

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

•

contractual limitations that affect our management's discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;

•

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

•

competition, including competition for acreage in resource play holdings;

•

environmental risks;

•

drilling and operating risks;

•

exploration and development risks;

•

the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations);

•

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;

•

social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or acts of terrorism or sabotage;

•

other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

•

our ability to successfully integrate acquired oil and natural gas businesses and operations;

•

the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management's time and energy;

•

the insurance coverage maintained by us may not adequately cover all losses that we may sustain;

•

title to the properties in which we have an interest may be impaired by title defects;

•

senior management's ability to execute our plans to meet our goals;

•

the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars; and

•

our dependency on the skill, ability and decisions of third party operators of the oil and natural gas properties in which we have a non-operated working interest.

        All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

4

PART I. FINANCIAL INFORMATION

Item 1.    Condensed Consolidated Financial Statements (Unaudited)

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	99,095		$	158,110		$	174,062		$	282,523
Natural gas		3,159			5,578			6,901			12,537
Natural gas liquids		3,504			3,889			5,441			7,957
Total oil, natural gas and natural gas liquids sales		105,758			167,577			186,404			303,017
Other		389			447			1,092			1,201
Total operating revenues		106,147			168,024			187,496			304,218
Operating expenses:
Production:
Lease operating		16,981			25,233			37,559			59,018
Workover and other		7,915			3,731			15,706			6,845
Taxes other than income		9,753			12,903			17,011			25,144
Gathering and other		10,519			7,746			21,903			21,492
Restructuring		189			309			5,073			2,230
General and administrative		24,708			22,662			66,324			47,071
Depletion, depreciation and accretion		39,671			101,194			94,937			220,338
Full cost ceiling impairment		257,869			948,633			754,769			1,502,636
Other operating property and equipment impairment		—			—			28,056			—
Total operating expenses		367,605			1,122,411			1,041,338			1,884,774
Income (loss) from operations		(261,458	)		(954,387	)		(853,842	)		(1,580,556	)
Other income (expenses):
Net gain (loss) on derivative contracts		(54,523	)		(87,564	)		(35,781	)		12,184
Interest expense and other, net		(58,322	)		(60,922	)		(106,113	)		(122,229	)
Gain (loss) on extinguishment of debt		—			22,766			81,434			22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			(8,219	)		—			(8,219	)
Total other income (expenses)		(112,845	)		(133,939	)		(60,460	)		(95,498	)
Income (loss) before income taxes		(374,303	)		(1,088,326	)		(914,302	)		(1,676,054	)
Income tax benefit (provision)		—			(286	)		—			(199	)
Net income (loss)		(374,303	)		(1,088,612	)		(914,302	)		(1,676,253	)
Series A preferred dividends		(3,198	)		(4,902	)		(6,396	)		(9,803	)
Preferred dividends and accretion on redeemable noncontrolling interest		(4,852	)		(11,067	)		(28,517	)		(19,718	)
Net income (loss) available to common stockholders	$	(382,353	)	$	(1,104,581	)	$	(949,215	)	$	(1,705,774	)
Net income (loss) per share of common stock:
Basic	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)
Diluted	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)
Weighted average common shares outstanding:
Basic		120,708			109,063			120,360			96,569
Diluted		120,708			109,063			120,360			96,569

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	June 30, 2016			December 31, 2015
Current assets:
Cash	$	7,173		$	8,026
Accounts receivable		112,855			173,624
Receivables from derivative contracts		135,455			348,861
Restricted cash		17,164			16,812
Inventory		1,498			4,635
Debt issuance costs, net		5,557			—
Prepaids and other		8,694			4,635
Total current assets		288,396			556,593
Oil and natural gas properties (full cost method):
Evaluated		7,679,917			7,060,721
Unevaluated		1,180,148			1,641,356
Gross oil and natural gas properties		8,860,065			8,702,077
Less—accumulated depletion		(6,779,116	)		(5,933,688	)
Net oil and natural gas properties		2,080,949			2,768,389
Other operating property and equipment:
Gas gathering and other operating assets		100,355			130,090
Less—accumulated depreciation		(23,155	)		(22,435	)
Net other operating property and equipment		77,200			107,655
Other noncurrent assets:
Receivables from derivative contracts		5,642			16,614
Debt issuance costs, net		—			7,633
Equity in oil and natural gas partnership		11			209
Funds in escrow and other		1,613			1,599
Total assets	$	2,453,811		$	3,458,692
Current liabilities:
Accounts payable and accrued liabilities	$	242,189		$	295,085
Asset retirement obligations		412			163
Current portion of long-term debt, net		2,825,807			—
Total current liabilities		3,068,408			295,248
Long-term debt, net		—			2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts		194			290
Asset retirement obligations		48,554			46,853
Other		9,283			6,264
Commitments and contingencies (Note 8)
Mezzanine equity:
Redeemable noncontrolling interest		212,503			183,986
Stockholders' equity (deficit):
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 222,454 and 244,724 shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding at June 30, 2016 and December 31, 2015, respectively		—			—
Common stock: 1,340,000,000 shares of $0.0001 par value authorized; 122,647,511 and 122,523,559 shares issued and outstanding at June 30, 2016 and December 31, 2015, respectively		12			12
Additional paid-in capital		3,288,371			3,283,097
Accumulated deficit		(4,173,514	)		(3,230,695	)
Total stockholders' equity (deficit)		(885,131	)		52,414
Total liabilities and stockholders' equity (deficit)	$	2,453,811		$	3,458,692

The accompanying notes are an integral part of these unaudited condensed consolidated financial
statements.

6

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Preferred Stock					Common Stock
											Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity (Deficit)
	Shares			Amount		Shares			Amount
Balance at December 31, 2014		345		$	—		85,562		$	8	$	2,995,436		$	(1,223,275	)	$	1,772,169
Net income (loss)		—			—		—			—		—			(1,922,621	)		(1,922,621	)
Dividends on Series A preferred stock		—			—		1,354			1		9,801			(17,979	)		(8,177	)
Conversion of Series A preferred stock		(100	)		—		3,258			—		—			—			—
Preferred dividends on redeemable noncontrolling interest		—			—		—			—		—			(12,614	)		(12,614	)
Accretion of redeemable noncontrolling interest		—			—		—			—		—			(53,561	)		(53,561	)
Change in fair value of redeemable noncontrolling interest		—			—		—			—		—			(645	)		(645	)
Common stock issuance		—			—		1,888			—		15,356			—			15,356
Common stock issuance on conversion of senior notes		—			—		28,955			3		231,380			—			231,383
Modification of February 2012 Warrants		—			—		—			—		14,129			—			14,129
Offering costs		—			—		—			—		(1,871	)		—			(1,871	)
Long-term incentive plan grants		—			—		2,048			—		—			—			—
Long-term incentive plan forfeitures		—			—		(388	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(153	)		—		(947	)		—			(947	)
Share-based compensation		—			—		—			—		19,813			—			19,813
Balances at December 31, 2015		245			—		122,524			12		3,283,097			(3,230,695	)		52,414
Net income (loss)		—			—		—			—		—			(914,302	)		(914,302	)
Conversion of Series A preferred stock		(23	)		—		724			—		—			—			—
Preferred dividends on redeemable noncontrolling interest		—			—		—			—		—			(6,655	)		(6,655	)
Accretion of redeemable noncontrolling interest		—			—		—			—		—			(21,862	)		(21,862	)
Reverse stock split rounding		—			—		5			—		—			—			—
Offering costs		—			—		—			—		(10	)		—			(10	)
Long-term incentive plan forfeitures		—			—		(499	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(106	)		—		(50	)		—			(50	)
Share-based compensation		—			—		—			—		5,334			—			5,334
Balances at June 30, 2016		222		$	—		122,648		$	12	$	3,288,371		$	(4,173,514	)	$	(885,131	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial
statements.

7

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Six Months Ended June 30,
	2016			2015
Cash flows from operating activities:
Net income (loss)	$	(914,302	)	$	(1,676,253	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		94,937			220,338
Full cost ceiling impairment		754,769			1,502,636
Other operating property and equipment impairment		28,056			—
Share-based compensation, net		3,652			8,210
Unrealized loss (gain) on derivative contracts		224,281			183,713
Amortization and write-off of deferred loan costs		3,024			4,092
Non-cash interest and amortization of discount and premium		1,269			1,709
Loss (gain) on extinguishment of debt		(81,434	)		(22,766	)
Loss (gain) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			8,219
Accrued settlements on derivative contracts		(23,072	)		(26,781	)
Other income (expense)		3,973			5,008
Change in assets and liabilities:
Accounts receivable		72,286			45,320
Inventory		(449	)		(5	)
Prepaids and other		(4,086	)		1,037
Accounts payable and accrued liabilities		(20,161	)		(36,947	)
Net cash provided by (used in) operating activities		142,743			217,530
Cash flows from investing activities:
Oil and natural gas capital expenditures		(170,258	)		(407,751	)
Other operating property and equipment capital expenditures		(886	)		(7,478	)
Funds held in escrow and other		(233	)		3,012
Net cash provided by (used in) investing activities		(171,377	)		(412,217	)
Cash flows from financing activities:
Proceeds from borrowings		425,000			1,296,000
Repayments of borrowings		(395,648	)		(1,129,000	)
Debt issuance costs		(1,186	)		(18,612	)
Common stock issued		—			15,354
Restricted cash		(325	)		(352	)
Offering costs and other		(60	)		(2,443	)
Net cash provided by (used in) financing activities		27,781			160,947
Net increase (decrease) in cash		(853	)		(33,740	)
Cash at beginning of period		8,026			43,713
Cash at end of period	$	7,173		$	9,973
Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	(2,387	)	$	(2,614	)
Asset retirement obligations		919			1,754
Series A preferred dividends paid in common stock		—			9,803
Preferred dividends on redeemable noncontrolling interest paid-in-kind		6,655			6,131
Accretion of redeemable noncontrolling interest		21,862			12,942
Change in fair value of redeemable noncontrolling interest		—			645
Common stock issued on conversion of senior notes		—			231,383
Accrued debt issuance costs		904			—

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

        Halcón Resources Corporation (Halcón or the Company) is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries and an equity method investment. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. The Company's oil and natural gas properties are managed as a whole rather than through discrete operating areas. Operational information is tracked by operating area; however, financial performance is assessed as a whole. Allocation of capital is made across the Company's entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company's management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its 2015 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on February 26, 2016. Please refer to the notes in the 2015 Annual Report on Form 10-K when reviewing interim financial results.

        On December 28, 2015, the Company completed a one-for-five reverse stock split. As a result, all share and per share information included for all periods presented in these unaudited condensed consolidated financial statements reflect the reverse stock split.

Ability to Continue as a Going Concern

        On July 27, 2016, the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a pre-packaged plan of reorganization. The Company expects to continue operations in the normal course during the pendency of the chapter 11 proceedings. Prior to filing the bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company's 13% senior secured notes due 2022 (the Third Lien Holders), the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of the Company's 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of the Company's 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders and together with the Third Lien Holders, Unsecured Noteholders and Convertible Noteholder, referred to collectively herein as, the Stakeholders). See Note 2, "Restructuring Support Agreement, " for more information. On June 20, 2016, the Halcón Entities commenced a solicitation for acceptance of the plan of reorganization (the Plan) contemplated in the Restructuring Support Agreement from the holders of impaired claims and interests entitled to vote under the Plan. At the conclusion of the Company's thirty day solicitation period, the Plan received sufficient votes to satisfy the voting conditions set forth in Section 1126(c) of the Bankruptcy Code. The Restructuring Support Agreement contains certain covenants on the part of the Halcón Entities and the Stakeholders, including that the Stakeholders vote in favor of the Plan contemplated in the Restructuring Support Agreement and otherwise facilitate and support the restructuring transaction, subject to the achievement of certain milestones and various conditions.

9

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

        The Company's debt agreements provide that the commencement of a voluntary proceeding in bankruptcy is an event of default leading to the automatic acceleration of the associated obligations. Accordingly, the filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code accelerated the Company's obligations under all of its outstanding debt instruments, although any efforts to enforce payment obligations thereunder have been automatically stayed by, and the creditors' rights of enforcement are subject to, the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Accordingly, the Company classified all of its outstanding debt as a current liability on its unaudited condensed consolidated balance sheet as of June 30, 2016.

        The significant risks and uncertainties related to the Halcón Entities' chapter 11 proceeding raise substantial doubt about the Company's ability to continue as a going concern. The unaudited condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Use of Estimates

        The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's unaudited condensed consolidated financial statements.

        Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Accounts Receivable and Allowance for Doubtful Accounts

        The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. There were no material allowances for doubtful accounts as of June 30, 2016 or December 31, 2015.

Other Operating Property and Equipment

        Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year or 10-year estimated useful life applicable to gas gathering systems and a compressed natural gas facility, respectively. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company capitalized $57.8 million and $87.2 million as of June 30, 2016 and December 31, 2015, respectively, related to the construction of its gas gathering systems, after any amounts impaired.

        Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years or the lesser of the lease term; trailers, seven years; heavy equipment, ten years; buildings, twenty years and leasehold improvements, lease term. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

        The Company reviews its gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from an asset's undiscounted cash flows, then the Company recognizes an impairment loss for the difference between the carrying amount and the current fair value. The Company also evaluates the remaining useful lives of its gas gathering systems and other operating assets at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. For the three months ended March 31, 2016, the Company recorded a non-cash impairment charge of $28.1 million in "Other operating property and equipment impairment" in the Company's unaudited condensed consolidated statements of operations and in "Gas gathering and other operating assets" in the Company's unaudited condensed consolidated balance sheets. The impairment primarily relates to the Company's gross investments of $32.8 million in gas gathering infrastructure that will not likely be economically recoverable due to its shift in exploration, drilling and developmental plans to its most economic areas as a result of the low commodity price environment.

        In accordance with ASC 820, Fair Value Measurements and Disclosures (ASC 820), a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The estimate of the fair value of the Company's gas gathering systems

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

was based on an income approach that estimated future cash flows associated with those assets, which resulted in negative net cash flows due to insufficient throughput of natural gas volumes and certain fixed costs necessary to operate and maintain the assets. This estimation includes the use of unobservable inputs, such as estimated future production, and gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company's gas gathering systems being classified as Level 3.

Recently Issued Accounting Pronouncements

        In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09, Compensation—Stock Compensation (ASU 2016-09). For public business entities, ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. The areas for simplification in this ASU 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. Some of the areas for simplification apply only to nonpublic entities. As there are multiple amendments in this ASU, the FASB has issued guidance on how an entity should apply each amendment, either prospectively or retrospectively. The Company is in the process of assessing the effects of the application of the new guidance.

        In March 2016, the FASB issued ASU No. 2016-06, Contingent Put and Call Options in Debt Instruments (ASU 2016-06). For public business entities, ASU 2016-06 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. ASU 2016-06 provides new guidance that simplifies the analysis of whether a contingent put or call option in a debt instrument qualifies as a separate derivative. An entity should apply the amendments in this ASU on a modified retrospective basis to existing debt instruments as of the beginning of the fiscal year for which the amendments are effective. The Company is in the process of assessing the effects of the application of the new guidance.

        In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and early adoption is permitted. The FASB issued ASU 2016-02 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. An entity should apply the amendments in this ASU on a modified retrospective basis. The transition will require application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the effects of the application of the new guidance.

        In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (ASU 2015-17) to simplify the presentation of deferred income taxes. Under ASU 2015-17, all deferred tax assets and liabilities, along with any related valuation allowance, are required to be classified as noncurrent on the balance sheet. Effective December 31, 2015, the Company early adopted ASU 2015-17, on a prospective basis, which resulted in the reclassification of its current deferred tax assets and liabilities as a non-current deferred tax asset and liability, net of the valuation allowance, in the accompanying unaudited condensed consolidated balance sheets. No prior periods were retrospectively adjusted.

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

        In September 2015, the FASB issued ASU No. 2015-16, Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). For public business entities, ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and early adoption is permitted. The amendments in this ASU require that an acquirer, in a business combination, recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. To simplify the accounting for adjustments made to provisional amounts recognized in a business combination, the amendments in this ASU eliminate the requirement to retrospectively account for those adjustments, and instead present separately on the face of the income statement or disclose in the footnotes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods. The adoption of ASU 2015-16 did not have an impact to the Company's financial statements or disclosures.

        In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory (ASU 2015-11). ASU 2015-11 states that an entity should measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments in this update should be applied prospectively and early application is permitted. The Company does not expect the adoption of ASU 2015-11 to have a material impact to its financial statements or disclosures.

        In April 2015, the FASB issued ASU No. 2015-05, Intangibles—Goodwill and Other—Internal-Use Software (ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. For public business entities, the guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. An entity can elect to adopt the guidance either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. Early adoption is permitted. The Company adopted prospectively and it did not have a material impact to the Company's financial statements or disclosures.

        In February 2015, the FASB issued ASU No. 2015-02, Amendments to the Consolidation Analysis (ASU 2015-02). The amendments in ASU 2015-02 eliminate the previous presumption that a general partner controls a limited partner. ASU 2015-02 may impact the Company's accounting for its general partner interest in SBE Partners LP (SBE Partners), which is currently accounted for as an equity method investment. ASU 2015-02 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Entities may apply the guidance using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the first fiscal year adopted or it may apply the amendment retrospectively. The adoption of ASU 2015-02 did not have an impact on the Company's accounting for its general partner interest in SBE Partners, LP.

        In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (ASU 2014-15). ASU 2014-15 is effective for annual reporting periods (including interim

13

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

periods within those periods) ending after December 15, 2016. Early application is permitted with companies applying the guidance prospectively. The amendments in ASU 2014-15 create a new ASC Sub-topic 205-40, Presentation of Financial Statements—Going Concern and require management to assess for each annual and interim reporting period if conditions exist that raise substantial doubt about an entity's ability to continue as a going concern. The rule requires various disclosures depending on the facts and circumstances surrounding an entity's ability to continue as a going concern. Effective June 30, 2016, the Company early adopted ASU 2014-15, on a prospective basis, which resulted in additional disclosures as discussed above.

        In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2016, or after December 2017, if companies choose to elect the deferred adoption date approved by the FASB. Early adoption is not permitted. The Company is in the process of assessing the effects of the application of the new guidance.

2. RESTRUCTURING SUPPORT AGREEMENT

        On June 9, 2016, the Halcón Entities entered into a Restructuring Support Agreement with the Stakeholders. On July 27, 2016, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware to effect an accelerated pre-packaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement.

        Pursuant to the terms of the Plan contemplated by the Restructuring Support Agreement, Stakeholders and other claim and interest holders will receive the following treatment in full and final satisfaction of their claims and interests:

•

the Halcón Entities' Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) shall be unimpaired and reinstated;

•

the Third Lien Holders will receive their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016;

•

the Unsecured Noteholders will receive their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón with a four year term and an exercise price based

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. RESTRUCTURING SUPPORT AGREEMENT (Continued)

on an equity value of $1.33 billion, and accrued and unpaid interest on their notes through May 15, 2016;

•

the Convertible Noteholder will receive 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón with a four year term and an exercise price based on an equity value of $1.33 billion;

•

the general unsecured claims are unimpaired;

•

the Preferred Holders will receive their pro rata share of $11.1 million in cash; and

•

the existing common stockholders will receive their pro rata share of 4% of the common stock of reorganized Halcón.

        Each of the foregoing percentages of equity in the reorganized company is subject to dilution from the exercise of the new warrants described above and a management incentive plan.

        The Restructuring Support Agreement contains certain covenants on the part of the Halcón Entities and the Stakeholders, including that the Stakeholders vote in favor of the Plan contemplated in the Restructuring Support Agreement and otherwise facilitate and support the restructuring transaction. The Restructuring Support Agreement also provides for termination by each party upon the occurrence of certain events, including without limitation, the failure of the Halcón Entities to achieve certain milestones, including having the Plan confirmed and effective by certain dates, and requires the satisfaction of certain conditions, such as that the Halcón Entities obtain a credit facility pursuant to an amendment or an amendment and restatement of its existing Senior Credit Agreement, defined below, (or any replacement financing) in an aggregate principal amount of not less than $600.0 million (the Amended Revolving Credit Agreement), which Amended Revolving Credit Agreement shall be (a) in form and substance reasonably satisfactory to the Requisite Unsecured Noteholders (as defined in the Restructuring Support Agreement), and (b) in form and substance satisfactory to the Requisite Third Lien Noteholders (as defined in the Restructuring Support Agreement).

        On June 20, 2016, the Halcón Entities commenced a solicitation for acceptance of the Plan. As a result of the solicitation, 99.997% in aggregate principal amount of the Third Lien Notes (defined below), that voted, 99.860% in aggregate principal amount of the Unsecured Notes (consisting of the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020) that voted, 100.000% of the aggregate principal amount of the Convertible Note (defined below), and 99.300% in aggregate amount of the shares of the Series A Preferred Stock (defined below) that voted, voted to support the Plan, which exceeded the voting condition under the Restructuring Support Agreement. In addition, the Company entered into an agreement dated as of July 22, 2016 with holders of more than 51% in aggregate principal amount of its 8.625% and 12.0% Second Lien Notes due 2020 and 2022 regarding certain amendments to the indentures governing such notes in exchange for the commitment of such holders to support the Plan (the Second Lien Support Agreement). Under the terms of the Second Lien Support Agreement, each holder of the Second Lien Notes that agrees to the proposed amendments and is either party to the Second Lien Support Agreement or otherwise does not object to the Plan will, subject to the occurrence of the effective date of the Plan (and, in the case of the Second Lien Notes, the effectiveness of the proposed amendment) receive a consent fee equal to 1.25% of the aggregate principal amount of such holder's outstanding second lien notes. To effect the treatment of claims and

15

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. RESTRUCTURING SUPPORT AGREEMENT (Continued)

interests set forth above in accordance with the Plan, the Company withheld the regularly scheduled July 15, 2016 interest payment on its 2020 Notes, defined below. The Company also withheld the regularly scheduled June 30, 2016 interest payment on its Convertible Note, defined below, which was waived by the holder of the Convertible Note in the Restructuring Support Agreement. The Company made the payments of accrued and unpaid interest through May 15, 2016 on the Third Lien Notes and Unsecured Notes prior to its chapter 11 filing. Also, to provide financial flexibility until such time as an Amended Revolving Credit Agreement is finalized and approved, prior to its chapter 11 filing, the Company drew approximately $338.0 million on July 25, 2016 under its Senior Credit Agreement, bringing its outstanding borrowings up to approximately $444.0 million.

        See Note 4, "Debt," and Note 10, "Stockholders' Equity," for information regarding the Company's debt and equity instruments.

3. OIL AND NATURAL GAS PROPERTIES

        The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

        The Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

        Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that are excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the unaudited condensed consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. For the six months ended June 30, 2016 and 2015, the Company capitalized interest costs of $52.9 million and $51.2 million, respectively.

        At June 30, 2016, the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2016 of the West Texas

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. OIL AND NATURAL GAS PROPERTIES (Continued)

Intermediate (WTI) crude oil spot price of $43.12 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2016 of the Henry Hub natural gas price of $2.24 per million British thermal units (MMBtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2016 exceeded the ceiling amount by $257.9 million ($163.1 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. The impairment at June 30, 2016 primarily reflects a 7% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $46.26 per barrel at March 31, 2016. At March 31, 2016, the Company recorded a full cost ceiling impairment before income taxes of $496.9 million ($315.1 million after taxes, before valuation allowance). The impairment at March 31, 2016 reflects additional transfers of the remaining unevaluated Utica / Point Pleasant (Utica) and Tuscaloosa Marine Shale (TMS) properties of approximately $330.4 million and $74.8 million, respectively, to the full cost pool and, to a lesser extent, an 8% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $50.28 per barrel at December 31, 2015. As discussed above, the Company considers the facts and circumstances around its unevaluated properties that may indicate impairment on a quarterly basis. Management concluded that it is no longer probable that capital will be available or approved to continue exploratory drilling activities in the Company's Utica or TMS acreage positions in advance of the related lease expirations due to the Company's evaluation of strategic alternatives to reduce its debt while preserving liquidity in light of continued low commodity prices, together with a reduction of the Company's exploration department and the Company's intent to expend capital only on its most economical and proven areas.

        At June 30, 2015, the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2015 of the WTI spot price of $71.68 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2015 of the Henry Hub price of $3.39 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2015 exceeded the ceiling amount by $948.6 million ($597.3 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. At March 31, 2015, the Company recorded a full cost ceiling impairment before income taxes of $554.0 million ($348.8 million after taxes, before valuation allowance). The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014, when the first-day-of-the-month average price for crude oil was $94.99 per barrel and $82.71 per barrel at March 31, 2015.

        The Company recorded the full cost ceiling test impairments in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT

        As of June 30, 2016 and December 31, 2015, the Company's current and long-term debt, respectively, consisted of the following:

	June 30, 2016(1)		December 31, 2015
	(In thousands)
Senior revolving credit facility	$	101,000	$	62,000
8.625% senior secured second lien notes due 2020(2)		689,064		687,797
12.0% senior secured second lien notes due 2022(3)		111,408		111,598
13.0% senior secured third lien notes due 2022(4)		1,010,048		1,009,585
9.25% senior notes due 2022(5)		36,660		51,887
8.875% senior notes due 2021(6)		296,184		347,671
9.75% senior notes due 2020(7)		312,522		336,470
8.0% convertible note due 2020(8)		268,921		266,629
	$	2,825,807	$	2,873,637

(1)

The Company's debt balance as of June 30, 2016 was classified as current. See "Senior Revolving Credit Facility" below for more details.

(2)

Amounts are net of $10.9 million and $12.2 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.

(3)

Amounts are net of $1.4 million and $1.2 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.

(4)

Amounts are net of $7.9 million and $8.4 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.

(5)

Amounts are net of $0.5 million and $0.8 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.

(6)

Amounts are net of a $0.8 million and a $1.0 million unamortized discount at June 30, 2016 and December 31, 2015, respectively, related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $4.3 million and $5.5 million at June 30, 2016 and December 31, 2015, respectively. Amounts are net of $4.5 million and $5.8 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively. See "8.875% Senior Notes" below for more details.

(7)

Amounts are net of a $1.6 million and a $1.9 million unamortized discount at June 30, 2016 and December 31, 2015, respectively, related to the issuance of the original 2020 Notes. The unamortized premium related to the additional 2020 Notes was approximately $2.2 million and $2.6 million at June 30, 2016 and December 31, 2015, respectively. Amounts are net of $3.6 million and $4.3 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively. See "9.75% Senior Notes" below for more details.

(8)

Amounts are net of a $20.7 million and a $23.0 million unamortized discount at June 30, 2016 and December 31, 2015, respectively. See "8.0% Convertible Note" below for more details.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT (Continued)

Senior Revolving Credit Facility

        On February 8, 2012, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Senior Credit Agreement provides for a $1.5 billion facility with a borrowing base of $700.0 million. However, pursuant to the Waiver Agreement, defined below, the Company agreed not to request borrowings in excess of $450.0 million for a specified period of time. On July 25, 2016, the Company borrowed approximately $338.0 million, resulting in the Company having an aggregate $444.0 million of indebtedness outstanding under the Senior Credit Agreement. The borrowing base is redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. At June 30, 2016, the weighted average interest rate on the Company's variable rate debt was 3.2% per year. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's and its restricted subsidiaries' properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on the Company's capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and a ratio of total secured debt (excluding the Third Lien Notes) to EBITDA of no greater than 2.75 to 1.0.

        On May 26, 2016, the Company entered into a waiver to its Senior Credit Agreement (the Waiver Agreement), which, among other things, temporarily limited the borrowings under its senior credit facility in connection with the Company's chapter 11 reorganization plans. The Company agreed that for a specified period of time it would not request, nor will it be permitted to request, a borrowing which would result in the aggregate exposure on the Senior Credit Agreement to exceed $450.0 million. Refer to Note 2, "Restructuring Support Agreement," for further details regarding the Company's chapter 11 reorganization plans.

        On March 17, 2016, the Company entered into the Thirteenth Amendment to its Senior Credit Agreement (the Thirteenth Amendment), which, among other things, reduced the borrowing base to $700.0 million and scheduled the Company's next borrowing base redetermination for September 1, 2016. Additionally, the Thirteenth Amendment changed the Company's interest margins under the facility to those described above.

        At June 30, 2016, the Company had $101.0 million of indebtedness outstanding, $5.2 million letters of credit outstanding and was in compliance with the financial covenants under the Senior Credit Agreement.

        The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 1, "Financial Statement Presentation," constituted an event of default under the Senior Credit Agreement that accelerated the Company's obligations and terminated the lenders' commitments under the Senior Credit Agreement.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT (Continued)

        In connection with the chapter 11 proceedings, the Company entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and a $600.0 million exit senior secured reserve-based revolving credit facility. Proceeds from the DIP Facility will, among other things, be used to refinance borrowings under the Company's current Senior Credit Agreement. Availability under the DIP Facility will be $500.0 million upon interim approval by the Bankruptcy Court, rising to $600.0 million upon entry of a final order. The DIP Facility will be converted into or otherwise refinanced by the exit credit facility following confirmation of the Plan. The DIP Facility will mature in three (3) months, subject to three-month extensions at the request of the borrower, but not beyond twelve (12) months from the commencement of the bankruptcy proceedings or the effective date of a plan of reorganization confirmed by the Bankruptcy Court. Loans under the DIP Facility will bear interest at a rate per annum equal to, as selected by the Company, an alternative base rate plus an applicable margin of 1.75% to 2.75% or adjusted LIBOR plus an applicable margin of 2.75% to 3.75%, in each case based on utilization. The DIP Facility will contain certain customary affirmative and negative covenants, including limitations on indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements and transactions with affiliates, as well as compliance with an approved bi-weekly budget, subject to minor variances. The DIP Facility will also contain specified events of default, including non-payment; non-compliance with covenants or other agreements; default in other material indebtedness; certain adverse judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

8.625% Senior Secured Second Lien Notes

        On May 1, 2015, the Company issued $700.0 million aggregate principal amount of its 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes) in a private placement. The 2020 Second Lien Notes were issued at par. The net proceeds from the sale of the 2020 Second Lien Notes were approximately $686.2 million (after deducting offering fees and expenses). The Company used the net proceeds from the offering to repay the majority of the then outstanding borrowings under its Senior Credit Agreement.

        The 2020 Second Lien Notes bear interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2020 Second Lien Notes will mature on February 1, 2020. The 2020 Second Lien Notes are secured by second-priority liens on substantially all of the Company's and its guarantors' assets to the extent such assets secure the Company's Senior Credit Agreement, its 2022 Second Lien Notes (defined below) and its Third Lien Notes (defined below) (the Collateral). Pursuant to the terms of an Intercreditor Agreement, dated May 1, 2015, as amended by those certain Priority Confirmation Joinders, dated September 10, 2015 and December 21, 2015, in connection with the issuance of the Third Lien Notes and the 2022 Second Lien Notes, respectively (the Intercreditor Agreement), the security interest in those assets that secure the 2020 Second Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2020 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness to the extent of the value of such assets. The Collateral does not include any of the assets of HK TMS, LLC, a wholly owned subsidiary of the Company, or any of the Company's future unrestricted subsidiaries.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT (Continued)

12.0% Senior Secured Second Lien Notes

        On December 21, 2015, the Company completed the issuance in a private placement of approximately $112.8 million aggregate principal amount of new 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes) in exchange for approximately $289.6 million principal amount of its senior unsecured notes, consisting of $116.6 million principal amount of 9.75% senior notes due 2020, $137.7 million principal amount of 8.875% senior notes due 2021 and $35.3 million principal amount of 9.25% senior notes due 2022. At closing, the Company paid all accrued and unpaid interest since the respective interest payment dates of the unsecured notes surrendered in the exchange. The Company recorded the issuance of the 2022 Second Lien Notes at par.

        Interest on the 2022 Second Lien Notes accrues at a rate of 12.0% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2016. The 2022 Second Lien Notes will mature on February 15, 2022. The 2022 Second Lien Notes are secured by second-priority liens on the Collateral. Pursuant to the terms of the Intercreditor Agreement, dated December 21, 2015, the security interest in the Collateral securing the 2022 Second Lien Notes and the guarantees are contractually equal with the liens that secure the 2020 Second Lien Notes and contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2022 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness and effectively equal to the 2020 Second Lien Notes, in each case to the extent of the value of the Collateral.

13.0% Senior Secured Third Lien Notes

        On September 10, 2015, the Company issued approximately $1.02 billion aggregate principal amount of new 13.0% senior secured third lien notes due 2022 (the Third Lien Notes) in a private placement in exchange for approximately $497.2 million principal amount of its 9.75% senior notes due 2020, $774.7 million principal amount of its 8.875% senior notes due 2021 and $294.4 million principal amount of its 9.25% senior notes due 2022 in privately negotiated transactions with certain holders of its outstanding senior unsecured notes. At closing, the Company paid all accrued and unpaid interest since the respective interest payment dates of the notes surrendered in the exchange. The Company recorded the issuance of the Third Lien Notes at par.

        The Third Lien Notes bear interest at a rate of 13.0% per annum, payable semi-annually on February 15 and August 15, commencing on February 15, 2016. The Third Lien Notes mature on February 15, 2022. The Third Lien Notes are secured by third-priority liens on the Collateral. The Third Lien Notes are governed by an Indenture dated September 10, 2015, which contains affirmative and negative covenants substantially similar to those governing the Company's outstanding 2020 Second Lien Notes and the 2022 Second Lien Notes. Pursuant to the terms of the Intercreditor Agreement, the security interest in those assets that secure the Third Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and certain other permitted indebtedness. Consequently, the Third Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and such other indebtedness to the extent of the value of the Collateral.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT (Continued)

9.25% Senior Notes

        On August 13, 2013, the Company issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting offering fees and expenses) were used to repay a portion of the then outstanding borrowings under the Company's Senior Credit Agreement.

        The 2022 Notes bear interest at a rate of 9.25% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2014. The 2022 Notes will mature on February 15, 2022. The 2022 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2022 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2022 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        During the first quarter of 2016, the Company repurchased $15.5 million principal amount of 2022 Notes for cash at prevailing market prices at the time of the transactions and recognized an $11.1 million net gain on the extinguishment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2022 Notes. As of June 30, 2016, $37.2 million principal amount of the Company's 2022 Notes remained outstanding.

8.875% Senior Notes

        On November 6, 2012, the Company issued $750.0 million aggregate principal amount of its 8.875% senior notes due 2021 (the 2021 Notes), at a price to the initial purchasers of 99.247% of par. The net proceeds from the offering of approximately $725.6 million (after deducting offering fees and expenses) and were used to fund a portion of the cash consideration paid in the Williston Basin Acquisition.

        On January 14, 2013, the Company issued an additional $600.0 million aggregate principal amount of the 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes of approximately $619.5 million (after offering fees and expenses) were used to repay all of the then outstanding borrowings under the Senior Credit Agreement and for general corporate purposes, including funding a portion of the Company's 2013 capital expenditures program. These notes were issued as "additional notes" under the indenture governing the 2021 Notes and under the indenture are treated as a single series with substantially identical terms as the 2021 Notes previously issued.

        The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The 2021 Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2021 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT (Continued)

the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        In conjunction with the issuance of the 2021 Notes, the Company recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $0.8 million at June 30, 2016. In conjunction with the issuance of the additional 2021 Notes, the Company recorded a premium of approximately $30.0 million to be amortized over the remaining life of the additional 2021 Notes using the effective interest method. The remaining unamortized premium was $4.3 million at June 30, 2016.

        During the first quarter of 2016, the Company repurchased $51.8 million principal amount of the 2021 Notes for cash at prevailing market prices at the time of the transactions and recognized a $47.5 million net gain on the extinguishment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2021 Notes. As of June 30, 2016, $297.2 million principal amount of the Company's 2021 Notes remained outstanding.

9.75% Senior Notes

        On July 16, 2012, the Company issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million (after deducting offering fees and expenses) and were used to fund a portion of the cash consideration paid in the merger with GeoResources, Inc., and the acquisition of certain oil and gas leaseholds located in East Texas.

        On December 19, 2013, the Company issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.3 million (after deducting offering fees and expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

        The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2020 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2020 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        In conjunction with the issuance of the 2020 Notes, the Company recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $1.6 million at June 30, 2016. In conjunction with the issuance of the additional 2020 Notes, the Company recorded a premium of approximately $11.0 million to be amortized over the remaining life of the additional 2020 Notes using

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT (Continued)

the effective interest method. The remaining unamortized premium was approximately $2.2 million at June 30, 2016.

        During the first quarter of 2016, the Company repurchased $24.5 million principal amount of the 2020 Notes for cash at prevailing market prices at the time of the transactions and recognized a $22.8 million net gain on the extinguishment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2020 Notes. As of June 30, 2016, $315.5 million principal amount of the Company's 2020 Notes remained outstanding.

8.0% Convertible Note

        On February 8, 2012, the Company issued to HALRES, LLC (HALRES), a note in the principal amount of $275.0 million due 2017 (the Convertible Note) together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. The Convertible Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year. Through the March 31, 2014 interest payment date, the Company was permitted to elect to pay the interest in kind, by adding to the principal of the Convertible Note, all or any portion of the interest due on the Convertible Note. The Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and added $3.2 million, $5.7 million and $5.8 million of interest incurred, respectively, to the Convertible Note, increasing the principal amount to $289.7 million. The Company did not elect to pay-in-kind interest for the subsequent quarterly payments. The Convertible Note is a senior unsecured obligation of the Company.

        On March 9, 2015, the Company entered into an amendment (the HALRES Note Amendment) to its Convertible Note. The HALRES Note Amendment extended the maturity date of the Convertible Note by three years, from February 8, 2017 to February 8, 2020. The Convertible Note originally provided for prepayment without premium or penalty at any time after February 8, 2014, at which time it also became convertible into shares of the Company's common stock at a conversion price of $22.50 per share. These dates have been extended pursuant to the HALRES Note Amendment and the conversion price has been adjusted, such that at any time after March 9, 2017, the Company may prepay the Convertible Note without premium or penalty, and HALRES may elect to convert all or any portion of unpaid principal and interest outstanding under the Convertible Note to shares of the Company's common stock at a conversion price of $12.20 per share, subject to adjustments for stock splits and other customary anti-dilution provisions as set forth in the Convertible Note. At the same time, the Company also entered into an amendment to the February 2012 Warrants (the Warrant Amendment) which extended the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusted the exercise price of the February 2012 Warrants from $22.50 to $12.20 per share. The HALRES Note Amendment and the Warrant Amendment were approved by the Company's stockholders on May 6, 2015, in accordance with the rules of the New York Stock Exchange. In conjunction with the HALRES Note Amendment, the Company recorded a discount of $25.9 million to be amortized over the remaining life of the Convertible Note using the effective interest method. As of June 30, 2016, the remaining unamortized discount was $20.7 million.

Debt Issuance Costs

        The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. For the six months ended June 30, 2016, the Company

24

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. DEBT (Continued)

expensed $2.5 million of debt issuance costs in conjunction with the debt repurchases and a decrease in the borrowing base under the Senior Credit Agreement. At June 30, 2016 and December 31, 2015, the Company had approximately $34.5 million and $40.3 million, respectively, of unamortized debt issuance costs. The debt issuance costs for the Company's Senior Credit Agreement are presented in "Debt issuance costs, net" within total assets on the unaudited condensed consolidated balance sheets, and the debt issuance costs for the Company's senior secured and unsecured debt are presented in "Current portion of long-term debt, net" and "Long-term debt, net" within total liabilities on the unaudited condensed consolidated balance sheets.

5. FAIR VALUE MEASUREMENTS

        Pursuant to ASC 820, Fair Value Measurements (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's unaudited condensed consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value 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). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

        The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of June 30, 2016 and December 31, 2015. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the six months ended June 30, 2016 or the year ended December 31, 2015.

	June 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	141,097	$	—	$	141,097
Liabilities
Liabilities from derivative contracts	$	—	$	42	$	152	$	194

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. FAIR VALUE MEASUREMENTS (Continued)

	December 31, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	365,475	$	—	$	365,475
Liabilities
Liabilities from derivative contracts	$	—	$	105	$	185	$	290

        Derivative contracts listed above as Level 2 include collars, swaps and swaptions that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" in the Company's unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 6, "Derivative and Hedging Activities" for additional discussion of derivatives.

        Derivative contracts listed above as Level 3 include extendable collars that are carried at fair value. The significant unobservable inputs for these Level 3 contracts include unpublished forward strip prices and market volatilities. The following table sets forth a reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy:

	Significant Unobservable Inputs (Level 3)
	June 30, 2016			December 31, 2015
	(In thousands)
Beginning Balance	$	(185	)	$	(1,319	)
Net gain (loss) on derivative contracts		33			1,134
Ending Balance	$	(152	)	$	(185	)
Change in unrealized gains (losses) included in earnings related to derivatives still held at June 30, 2016 and December 31, 2015	$	33		$	(185	)

        The Company's derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.

        The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivables and accounts payables approximate their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. FAIR VALUE MEASUREMENTS (Continued)

values of the Company's fixed interest rate debt instruments as of June 30, 2016 and December 31, 2015 (excluding discounts, premiums and debt issuance costs):

	June 30, 2016				December 31, 2015
Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
	(In thousands)
8.625% senior secured second lien notes	$	700,000	$	659,120	$	700,000	$	479,500
12.0% senior secured second lien notes		112,826		106,237		112,826		77,286
13.0% senior secured third lien notes		1,017,970		539,524		1,017,970		333,385
9.25% senior notes		37,194		8,276		52,694		14,422
8.875% senior notes		297,193		66,125		348,944		95,506
9.75% senior notes		315,535		70,207		340,035		93,068
8.0% convertible note		289,669		69,926		289,669		87,393
	$	2,770,387	$	1,519,415	$	2,862,138	$	1,180,560

        The fair value of the Company's fixed interest rate debt instruments was calculated using Level 2 criteria. The fair value of the Company's senior notes is based on quoted market prices from trades of such debt. The fair value of the Company's Convertible Note is based on published market prices and risk-free rates.

        During the three months ended March 31, 2016, the Company recorded a non-cash impairment charge of $28.1 million related to its gas gathering systems. See Note 1, "Financial Statement Presentation," for a discussion of the valuation approach used and the classification of the estimate within the fair value hierarchy.

        As discussed in Note 4, "Debt" and in Note 10, "Stockholders' Equity," on May 6, 2015, the HALRES Note Amendment and the Warrant Amendment became effective. The fair value estimates for the Convertible Note and the February 2012 Warrants include the use of observable inputs such as the Company's stock price, expected volatility, and credit spread and the risk-free rate. The use of these observable inputs results in the fair value estimates being classified as Level 2.

        The Company follows the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company's initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management's expectation of future cost environments; consequently, the Company has designated these liabilities as Level 3. See Note 7, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

6. DERIVATIVE AND HEDGING ACTIVITIES

        The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to economically hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. When derivative contracts are available at terms (or prices) acceptable to the Company, it generally hedges a substantial, but varying,

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company's hedge policies and objectives may change significantly as its operational profile changes and/or commodities prices change. The Company does not enter into derivative contracts for speculative trading purposes.

        It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company did not post collateral under any of its derivative contracts as they are secured under the Company's Senior Credit Agreement or are uncollateralized trades.

        At June 30, 2016 and December 31, 2015, the Company's crude oil and natural gas derivative positions consisted of swaps, swaptions, costless put/call "collars," and extendable costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. Extendable collars are costless put/call contracts that may be extended annually at the option of the counterparty on a designated date. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

        At June 30, 2016, the Company had 34 open commodity derivative contracts summarized in the following tables: one natural gas collar arrangement, 14 crude oil collar arrangements, 13 crude oil swaps, five crude oil swaptions and one crude oil extendable collar.

        At December 31, 2015, the Company had 36 open commodity derivative contracts summarized in the following tables: one natural gas collar arrangement, 16 crude oil collar arrangements, 13 crude oil swaps, five crude oil swaptions and one crude oil extendable collar.

        All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2016 and December 31, 2015:

		Asset derivative contracts					Liability derivative contracts
Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	June 30, 2016		December 31, 2015		Balance sheet location	June 30, 2016			December 31, 2015
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	135,455	$	348,861	Current liabilities—liabilities from derivative contracts	$	—		$	—
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		5,642		16,614	Other noncurrent liabilities—liabilities from derivative contracts		(194	)		(290	)
Total derivatives not designated as hedging contracts under ASC 815		$	141,097	$	365,475		$	(194	)	$	(290	)

        The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's unaudited condensed consolidated statements of operations:

		Amount of gain or (loss) recognized in income on derivative contracts for the Three Months Ended June 30,						Amount of gain or (loss) recognized in income on derivative contracts for the Six Months Ended June 30,
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2016			2015			2016			2015
		(In thousands)						(In thousands)
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(135,303	)	$	(175,712	)	$	(224,281	)	$	(183,713	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		80,780			88,148			188,500			195,897
Total net gain (loss) on derivative contracts		$	(54,523	)	$	(87,564	)	$	(35,781	)	$	12,184

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

        At June 30, 2016 and December 31, 2015, the Company had the following open crude oil and natural gas derivative contracts:

			June 30, 2016
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
July 2016 - December 2016	Collars	Natural Gas		368,000	$4.00	$	4.00	$4.22	$	4.22
July 2016 - December 2016(1)(3)	Collars	Crude Oil		2,024,000	60.00 - 90.00		73.00	64.00 - 95.10		78.87
July 2016 - December 2016(2)(3)	Swaps	Crude Oil		2,392,000	62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750	50.00 - 60.00		57.33	70.00 - 76.84		74.16

			December 31, 2015
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
January 2016 - June 2016	Collars	Crude Oil		182,000	$90.00	$	90.00	$96.85	$	96.85
January 2016 - December 2016	Collars	Natural Gas		732,000	4.00		4.00	4.22		4.22
January 2016 - December 2016(1)	Collars	Crude Oil		4,392,000	60.00 - 90.00		71.91	64.00 - 95.10		77.71
January 2016 - December 2016(2)	Swaps	Crude Oil		4,758,000	62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750	50.00 - 60.00		57.33	70.00 - 76.84		74.16

(1)

Includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $60.00 per Bbl and a ceiling of $75.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2017.

(2)

Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended by the counterparty at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

(3)

Subsequent to June 30, 2016, crude oil collars totaling 184,000 Bbls and crude oil swaps totaling 184,000 Bbls for the remainder of 2016 were terminated resulting in proceeds of $9.6 million to the Company.

        The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at June 30, 2016 and December 31, 2015:

	Derivative Assets						Derivative Liabilities
Offsetting of Derivative Assets and Liabilities	June 30, 2016			December 31, 2015			June 30, 2016			December 31, 2015
	(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	141,097		$	365,475		$	(194	)	$	(290	)
Amounts Not Offset in the Consolidated Balance Sheet		(21	)		(53	)		20			52
Net Amount	$	141,076		$	365,422		$	(174	)	$	(238	)

        The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective

30

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

        The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 1, "Financial Statement Presentation," constituted an event of default under the Company's derivatives contracts that gives the counterparties the option to terminate such contracts. If terminated, the contracts would be net settled in cash. The Company obtained a waiver from its hedge counterparties indicating that they will not exercise their option to terminate their contracts so long as the Restructuring Support Agreement is not terminated, the DIP Facility commitment letter is not terminated and the Company meet its various obligations thereunder, among other things.

7. ASSET RETIREMENT OBLIGATIONS

        The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For gas gathering systems and equipment, the Company records an ARO when the system is placed in service and it can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work when it is required. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes a portion of the cost in "Oil and natural gas properties" or "Other operating property and equipment" during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in "Depletion, depreciation and accretion" expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

        The Company recorded the following activity related to its ARO liability for the six months ended June 30, 2016 (in thousands, inclusive of the current portion):

Liability for asset retirement obligations as of December 31, 2015	$	47,016
Liabilities settled and divested		(180	)
Additions		1,024
Acquisitions		75
Accretion expense		1,031
Liability for asset retirement obligations as of June 30, 2016	$	48,966

8. COMMITMENTS AND CONTINGENCIES

Commitments

        The Company leases corporate office space in Houston, Texas; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $4.3 million for the six months ended June 30, 2016 and 2015. As of June 30, 2016, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2015, as disclosed in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, approximating $46.8 million in the aggregate, and containing various expiration dates through 2024.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. COMMITMENTS AND CONTINGENCIES (Continued)

        In addition, the Company has commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2018. In the first quarter of 2016, the Company entered into an amendment to one of its drilling rig contracts with an original term ending date of August 31, 2016, whereby, as of April 5, 2016, the Company early terminated the rig contract, incurred a termination fee of approximately $1.2 million and reduced its 2016 drilling commitments by extending part of the contract term on another of its drilling rig contracts out further in 2018. In January 2015, the Company made the decision to early terminate a drilling rig contract in response to the decline in crude oil prices, and the Company incurred an early termination fee of $6.0 million, paid over the first half of 2015. If certain requirements are not met by two separate trigger dates, the first being January 1, 2017 and the second being January 12, 2020, the Company may incur up to an additional $3.0 million in connection with this drilling rig contract. Rig termination fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations.

        In addition, the Company has two drilling rig commitments, for which the Company is incurring a stacking fee of $16,000 and $17,000 per day. The contract terms for these drilling rig commitments extends through the second quarter of 2017 and 2018, respectively. Rig stacking fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations. Early termination of the Company's additional drilling rig commitments would result in termination penalties approximating $14.8 million, which would be in lieu of the remaining $20.8 million of drilling rig commitments as of June 30, 2016.

        The Company has entered into various long-term gathering, transportation and sales contracts with respect to production from the Bakken/Three Forks formations in North Dakota. As of June 30, 2016, the Company had in place nine long-term crude oil contracts and five long-term natural gas contracts in this area. Under the terms of these contracts, the Company has committed a substantial portion of its Bakken/Three Forks production for periods ranging from one to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. Historically, the Company has been able to meet its delivery commitments.

        On June 16, 2014, the Company entered into a transaction to develop its TMS assets with funds and accounts managed by affiliates of Apollo Global Management, LLC and on June 1, 2015 amended this agreement. See Note 9, "Mezzanine Equity," for a discussion of the drilling obligation associated with the transaction.

Contingencies

        From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company's management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company's unaudited condensed consolidated operating results, financial position or cash flows.

9. MEZZANINE EQUITY

        On June 16, 2014, funds and accounts managed by affiliates of Apollo Global Management, LLC (Apollo) contributed $150 million in cash to HK TMS, LLC, a Delaware limited liability company

32

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. MEZZANINE EQUITY (Continued)

(HK TMS), wholly owned by the Company that, as of June 16, 2014 held all of the Company's undeveloped acreage in the TMS formation, located in Mississippi and Louisiana, in exchange for the issuance by HK TMS of 150,000 preferred shares. At the closing, the Company also contributed $50 million in cash to HK TMS. Holders of the HK TMS preferred shares will receive quarterly cash dividends of 8% cumulative perpetual per annum, subject to HK TMS' option to pay such dividends "in-kind" through the issuance of additional preferred shares. The preferred shares will be automatically redeemed and cancelled when the holders receive cash dividends and distributions on the preferred shares equating to the greater of a 12% annual rate of return plus principal and 1.25 times their investment plus applicable fees (the Redemption Price), subject to adjustment under certain circumstances. The preferred shares have a liquidation preference in the event of dissolution in an amount equal to the Redemption Price plus any unpaid dividends not otherwise included in the calculation of the Redemption Price through the date of liquidation payment. HK TMS may also redeem the preferred shares at any time after December 31, 2016 by paying the Redemption Price, or may be required to redeem the preferred shares for the Redemption Price plus certain fees under certain circumstances.

        On June 1, 2015, HK TMS and Apollo entered into an amendment to the original agreement (the HK TMS Amendment) which, among other things, i) commits HK TMS to drill a minimum of 6.5 net wells in each of the five consecutive twelve month periods beginning December 31, 2015 and ii) allows for the redemption of preferred shares at the Redemption Price between March 1, 2016 and June 30, 2016 at the election of Apollo to the extent there is available cash above the minimum cash balance, which is discussed further below. For any commitment period in which HK TMS does not meet its drilling obligation, HK TMS must use available cash, above the minimum cash balance, to redeem preferred shares at the Redemption Price.

        The preferred shares have been classified as "Redeemable noncontrolling interest" and included in "Mezzanine equity" between total liabilities and stockholders' equity on the unaudited condensed consolidated balance sheets pursuant to ASC 480-10-S99-3A. The preferred shares are considered probable of becoming redeemable and therefore were accreted up to the estimated required redemption value through June 30, 2016. The accretion is presented as a deemed dividend and recorded in "Redeemable noncontrolling interest" on the unaudited condensed consolidated balance sheets and within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. In accordance with ASC 480-10-S99-3A, an adjustment to the carrying amount presented in "Mezzanine equity" will be recognized as charges against retained earnings and will reduce income available to common shareholders in the calculation of earnings per share. Adjustments to the carrying amount may not be necessary if the application of ASC No. 810, Consolidation (ASC 810) results in a noncontrolling interest balance in excess of what is required pursuant to ASC 480-10-S99-3A.

        In March 2015, Apollo delivered a withdrawal notice to HK TMS indicating their election not to acquire additional preferred shares in HK TMS (the Withdrawal Notice). Upon issuance of the Withdrawal Notice, HK TMS incurs a fee escalating from $2.50 per share to $20.00 per share for the next eight full fiscal quarters for any preferred shares then outstanding, which began in the quarter ended June 30, 2015 (the Withdrawal Exit Fee). The Withdrawal Exit Fee is payable upon redemption of the preferred shares. As of June 30, 2016, HK TMS incurred Withdrawal Exit Fees of $6.2 million. The Withdrawal Exit Fees were recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. MEZZANINE EQUITY (Continued)

        As part of the transaction, there are certain restrictions on the transfer of assets, including cash, to the Company from HK TMS. HK TMS is required to maintain a minimum cash balance equal to two quarterly dividend payments, of approximately $3.5 million each, plus $10.0 million, which is presented on the unaudited condensed consolidated balance sheets in "Restricted cash." Additionally, the quarterly 8% dividends paid to holders of the HK TMS preferred shares have priority over other cash distributions. No dividends are permitted to be paid to the Company from HK TMS prior to December 31, 2016. HK TMS is restricted from transferring more than 20% of its maximum net acres and from transferring any assets exceeding 20% of HK TMS's proved reserves at any one time without approval from the Company and Apollo. Finally, proceeds from any such transfers of acres or other assets must be used for HK TMS's capital or operating expenditures, or to redeem preferred shares.

        The following table sets forth a reconciliation of the changes in fair value of the embedded derivative associated with the amended transaction, which is classified as Level 3 in the fair value hierarchy (in thousands):

	Embedded derivative
Balance at December 31, 2015	$	6,100
Change in fair value		3,020
Balance at June 30, 2016	$	9,120

        The Company recorded the following activity related to the preferred shares recorded in "Mezzanine equity" on the unaudited condensed consolidated balance sheets for the period presented (in thousands, except share amounts):

	Redeemable noncontrolling interest
	Shares		Amount
Balances at December 31, 2015		165,639	$	183,986
Dividends paid in-kind		6,655		6,655
Accretion of redeemable noncontrolling interest		—		21,862
Balances at June 30, 2016		172,294	$	212,503

        For the six months ended June 30, 2016 and 2015, HK TMS issued 6,655 and 6,131 additional preferred shares to Apollo for dividends paid-in-kind, respectively. These dividends are presented within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. Upon the election of in-kind dividends, HK TMS must pay a fee of $5.00 per preferred share then outstanding (PIK Exit Fee). Such fees will be due upon redemption of the preferred shares. As of June 30, 2016, HK TMS incurred PIK Exit Fees totaling $5.6 million, which were recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

        HK TMS was not included in the chapter 11 filings or the Restructuring Support Agreement discussed in Note 1, "Financial Statement Presentation" and Note 2, "Restructuring Support Agreement," respectively.

34

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCKHOLDERS' EQUITY

5.75% Series A Convertible Perpetual Preferred Stock

        On June 18, 2013, the Company completed its offering of 345,000 shares of its 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred Stock) at a public offering price of $1,000 per share (the Liquidation Preference). The net proceeds to the Company were approximately $335.2 million, after deducting the underwriting discount and offering expenses. The Company used the net proceeds to repay a portion of the then outstanding borrowings under its Senior Credit Agreement.

        Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Company's Board of Directors, cumulative dividends at the rate of 5.75% per annum (the Dividend Rate) on the Liquidation Preference per share of the Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, in common stock of the Company, or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year. In January 2016, the Company announced that future quarterly dividends on the Series A Preferred Stock will be suspended due to the weakened market conditions as a result of low commodity prices. As of June 30, 2016, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $7.5 million.

        The Series A Preferred Stock has no maturity date, is not redeemable by the Company at any time, and will remain outstanding unless converted by the holders or mandatorily converted by the Company. Each share of Series A Preferred Stock is convertible, at the holder's option at any time, into approximately 32.49 shares of common stock of the Company (which is equivalent to a conversion price of approximately $30.80 per share), subject to certain adjustments. Based on the initial conversion rate and Series A Preferred Stock outstanding, approximately 11.2 million shares of common stock of the Company are issuable upon conversion of all the shares of Series A Preferred Stock. On or after June 6, 2018, the Company may, at its option, give notice of its election to cause all outstanding shares of the Series A Preferred Stock to be automatically converted into shares of common stock of the Company at the conversion rate (as defined in the Series A Designation), if the closing sale price of the Company's common stock equals or exceeds 150% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days. As of June 30, 2016, 122,546 shares of Series A Preferred Stock have been converted into approximately 4.0 million shares of common stock and 222,454 shares of Series A Preferred Stock remained outstanding.

        If the Company undergoes certain fundamental changes, including failure of the Company's common stock to be listed on the NYSE, NASDAQ Global Select or NASDAQ Global Market, and a holder converts its shares of the Series A Preferred Stock at any time beginning at the opening of business on the trading day immediately following the effective date of such fundamental change and ending at the close of business on the 30th trading day immediately following such effective date, the holder will receive, for each share of the Series A Preferred Stock surrendered for conversion, a number of shares of common stock of the Company equal to the greater of: (1) the sum of (i) the conversion rate and (ii) the make-whole premium, if any, as described in the Series A Designation; and (2) the conversion rate which will be increased to equal (i) the sum of the $1,000 liquidation preference plus all accumulated and unpaid dividends to, but excluding, the settlement date for such conversion, divided by (ii) the average of the closing sale prices of the Company's common stock for the five consecutive trading days ending on the third business day prior to such settlement date; provided that the prevailing conversion rate as adjusted pursuant to this will not exceed 58.48 shares of common

35

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCKHOLDERS' EQUITY (Continued)

stock of the Company per share of the Series A Preferred Stock (subject to adjustment in the same manner as the conversion rate).

        Except as required by Delaware law, holders of the Series A Preferred Stock will have no voting rights unless dividends are in arrears and unpaid for six or more quarterly periods. Until such arrearage is paid in full, the holders (voting as a single class with the holders of any other preferred shares having similar voting rights) will be entitled to elect two additional directors and the number of directors on the Company's board of directors will increase by that same number.

Common Stock

        On December 28, 2015, the Company completed a one-for-five reverse stock split. Retroactive application of the reverse stock split is required and all share and per share information included for all periods presented in these unaudited condensed consolidating financial statements reflects the reverse stock split.

        On March 18, 2015, the Company entered into an Equity Distribution Agreement (the Equity Distribution Agreement) with BMO Capital Markets Corp., Jefferies LLC and MLV & Co. LLC (collectively, the Managers), pursuant to which, during 2015, the Company publicly sold approximately 1.9 million shares for net proceeds of approximately $15.0 million, after deducting offering expenses. The shares sold were registered under the Securities Act pursuant to a Registration Statement on Form S-3 (No. 333-188640), which was filed with the SEC and became effective March 13, 2015. The Company used the net proceeds from the offering to repay a portion of outstanding borrowings under its Senior Credit Agreement and for general corporate purposes.

        On May 22, 2014, with stockholder approval, the Company filed a Certificate of Amendment to its Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to increase its authorized common stock by approximately 670.0 million shares for a total of 1.34 billion authorized shares of common stock.

Warrants

        In February 2012, in conjunction with the issuance of the Convertible Note, the Company issued warrants to purchase 7.3 million shares of the Company's common stock at an exercise price of $22.50 per share of common stock, which the Company refers to as the February 2012 Warrants. The Company allocated $43.6 million to the February 2012 Warrants which is reflected in additional paid-in capital in stockholders' equity, net of $0.6 million in issuance costs. The February 2012 Warrants entitled the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

        On March 9, 2015, in conjunction with the HALRES Note Amendment, the Company entered into an amendment to the February 2012 Warrants, the Warrant Amendment, which extended the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusted the exercise price from $22.50 to $12.20 per share. The HALRES Note Amendment and the Warrant Amendment (the Amendments) were approved by the Company's stockholders on May 6, 2015, in accordance with the rules of the New York Stock Exchange. See Note 4, "Debt," for further discussion of the Amendments.

36

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCKHOLDERS' EQUITY (Continued)

Incentive Plan

        On May 8, 2006, the Company's stockholders first approved the 2006 Long-Term Incentive Plan (the Plan). On May 6, 2015, the Company's stockholders last approved an increase in authorized shares under the Plan from 8.3 million to 16.3 million. As of June 30, 2016 and December 31, 2015, a maximum of 7.4 million and 6.3 million shares of common stock, respectively, remained reserved for issuance under the Plan.

        The Company accounts for share-based payment accruals under authoritative guidance on stock compensation, as set forth in ASC 718. The guidance requires all share-based payments to employees and directors, including grants of performance units, stock options, and restricted stock, to be recognized in the financial statements based on their fair values.

        For the three and six months ended June 30, 2016, the Company recognized $1.5 million and $3.7 million, respectively, of share-based compensation expense. For the three and six months ended June 30, 2015, the Company recognized $3.4 million and $8.2 million, respectively, of share-based compensation expense. These were recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

Performance Share Units

        As of June 30, 2016 and 2015, the Company had outstanding performance share units (PSU) under the Plan covering 0.3 million shares of common stock, respectively, granted to senior management of the Company in 2014. The PSU provides that the number of shares of common stock received upon vesting will vary if the market price of the Company's common stock exceeds certain pre-established target thresholds as measured by the average of the adjusted closing price of a share of the Company's common stock during the sixty trading days preceding the third anniversary of issuance, or the measurement date. The PSU utilizes $20.00 as the floor price, below which the PSU will not vest and will expire. If the average market price at the measurement date is equal to $20.00, the PSU will vest and represent the right to receive 50% of the number of shares of common stock underlying the PSU. At $35.00, the PSU will vest and represent the right to receive the full number of shares of common stock underlying the PSU; and at $50.00, the PSU will vest and represent the right to receive 200% of the number of shares of common stock underlying the PSU. All stock price targets are subject to customary adjustments based upon changes in the Company's capital structure. In the event the average market price falls between targeted price thresholds, the PSU will represent the right to receive a proportionate number of shares. The Company has reserved for issuance under the Plan the maximum number of shares that participants might have the right to receive upon vesting of the PSU, or 0.6 million shares of common stock.

        At June 30, 2016, the Company had $1.1 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 0.7 years. At June 30, 2015, the Company had $2.7 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 1.7 years.

Stock Options

        At June 30, 2016, the Company had $2.8 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.2 years.

37

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCKHOLDERS' EQUITY (Continued)

        During the six months ended June 30, 2015, the Company granted stock options under the Plan covering 0.7 million shares of common stock to employees of the Company. These stock options have exercise prices ranging from $7.85 to $9.85 with a weighted average exercise price of $9.60. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. At June 30, 2015, the Company had $9.0 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.3 years.

Restricted Stock

        At June 30, 2016, the Company had $5.2 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

        During the six months ended June 30, 2015, the Company granted 0.5 million shares of restricted stock under the Plan to non-employee directors and employees of the Company. These restricted shares were granted at prices ranging from $6.10 to $9.85 with a weighted average price of $8.70. Employee shares vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six-months from the date of grant. At June 30, 2015, the Company had $13.4 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

38

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. EARNINGS PER COMMON SHARE

        The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Basic:
Net income (loss) available to common stockholders	$	(382,353	)	$	(1,104,581	)	$	(949,215	)	$	(1,705,774	)
Weighted average basic number of common shares outstanding		120,708			109,063			120,360			96,569
Basic net income (loss) per share of common stock	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)
Diluted:
Net income (loss) available to common stockholders	$	(382,353	)	$	(1,104,581	)	$	(949,215	)	$	(1,705,774	)
Weighted average basic number of common shares outstanding		120,708			109,063			120,360			96,569
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of performance units		—			—			—			—
Conversion of Convertible Note		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Conversion of Series A Preferred Stock		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Weighted average diluted number of common shares outstanding		120,708			109,063			120,360			96,569
Diluted net income (loss) per share of common stock	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)

        Common stock equivalents, including stock options, warrants, restricted shares, convertible debt and preferred stock totaling 44.6 million and 45.2 million shares for the three and six months ended June 30, 2016 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses. Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock totaling 48.3 million and 48.2 million shares for the three and six months ended June 30, 2015 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

39

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. ADDITIONAL FINANCIAL STATEMENT INFORMATION

        Certain balance sheet amounts are comprised of the following:

	June 30, 2016		December 31, 2015
	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	55,250	$	55,129
Joint interest accounts		32,685		67,626
Accrued settlements on derivative contracts		23,072		47,011
Affiliated partnership		123		176
Other		1,725		3,682
	$	112,855	$	173,624
Prepaids and other:
Prepaids	$	8,643	$	4,585
Other		51		50
	$	8,694	$	4,635
Accounts payable and accrued liabilities:
Trade payables	$	23,357	$	47,261
Accrued oil and natural gas capital costs		25,356		54,651
Revenues and royalties payable		56,296		64,002
Accrued interest expense		105,782		88,499
Accrued employee compensation		4,954		2,829
Accrued lease operating expenses		16,435		20,036
Drilling advances from partners		223		7,964
Income taxes payable		9,172		9,172
Affiliated partnership		241		365
Other		373		306
	$	242,189	$	295,085

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

        The Company's obligations under its Senior Credit Agreement, 2020 Second Lien Notes, 2022 Second Lien Notes, Third Lien Notes and senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, by all of the Company's existing 100% owned subsidiaries, other than HK TMS. See Note 4, "Debt," for information regarding the Company's Senior Credit Agreement, 2020 Second Lien Notes, 2022 Second Lien Notes, Third Lien Notes and senior unsecured notes. On June 16, 2014, the Company contributed its TMS undeveloped acreage located in Mississippi and Louisiana to HK TMS. See Note 9, "Mezzanine Equity," for a discussion of the restrictions on the transfer of assets between the Company and HK TMS.

        The following condensed consolidating balance sheets, condensed consolidating statements of operations, and condensed consolidating statements of cash flows for the parent company, subsidiary guarantors on a combined basis, the non-guarantor subsidiary, the consolidating adjustments and the total consolidated amounts are presented as of June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015. Investments in the subsidiaries are accounted for under the equity method. Such condensed consolidating financial information may not necessarily be indicative of the financial position, results of operations or cash flows had these subsidiaries operated as independent entities.

40

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

	Three Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	96,995		$	2,100		$	—		$	99,095
Natural gas		—			3,159			—			—			3,159
Natural gas liquids		—			3,504			—			—			3,504
Total oil, natural gas and natural gas liquids sales		—			103,658			2,100			—			105,758
Other		—			388			1			—			389
Total operating revenues		—			104,046			2,101			—			106,147
Operating expenses:
Production:
Lease operating		—			16,667			314			—			16,981
Workover and other		—			7,896			19			—			7,915
Taxes other than income		—			9,565			188			—			9,753
Gathering and other		—			10,516			3			—			10,519
Restructuring		—			189			—			—			189
General and administrative		20,243			4,453			237			(225	)		24,708
Depletion, depreciation and accretion		367			38,397			1,188			(281	)		39,671
Full cost ceiling impairment		—			250,753			6,835			281			257,869
Total operating expenses		20,610			338,436			8,784			(225	)		367,605
Income (loss) from operations		(20,610	)		(234,390	)		(6,683	)		225			(261,458	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(54,523	)		—			—			(54,523	)
Interest expense and other, net		(77,069	)		20,786			(2,039	)		—			(58,322	)
Total other income (expenses)		(77,069	)		(33,737	)		(2,039	)		—			(112,845	)
Income (loss) before income taxes		(97,679	)		(268,127	)		(8,722	)		225			(374,303	)
Income tax benefit (provision)		—			—			—			—			—
Equity in earnings of subsidiary, net of tax		(281,476	)		(13,349	)		—			294,825			—
Net income (loss)		(379,155	)		(281,476	)		(8,722	)		295,050			(374,303	)
Series A preferred dividends		(3,198	)		—			—			—			(3,198	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(4,852	)		—			(4,852	)
Net income (loss) available to common stockholders	$	(382,353	)	$	(281,476	)	$	(13,574	)	$	295,050		$	(382,353	)

41

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	Three Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	153,792		$	4,318		$	—		$	158,110
Natural gas		—			5,578			—			—			5,578
Natural gas liquids		—			3,889			—			—			3,889
Total oil, natural gas and natural gas liquids sales		—			163,259			4,318			—			167,577
Other		—			447			—			—			447
Total operating revenues		—			163,706			4,318			—			168,024
Operating expenses:
Production:
Lease operating		—			24,595			638			—			25,233
Workover and other		—			3,731			—			—			3,731
Taxes other than income		—			12,614			289			—			12,903
Gathering and other		—			7,746			—			—			7,746
Restructuring		—			309			—			—			309
General and administrative		15,097			7,519			723			(677	)		22,662
Depletion, depreciation and accretion		568			97,572			4,386			(1,332	)		101,194
Full cost ceiling impairment		—			911,496			35,805			1,332			948,633
Total operating expenses		15,665			1,065,582			41,841			(677	)		1,122,411
Income (loss) from operations		(15,665	)		(901,876	)		(37,523	)		677			(954,387	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(87,564	)		—			—			(87,564	)
Interest expense and other, net		(85,042	)		24,734			(614	)		—			(60,922	)
Gain (loss) on extinguishment of debt		22,766			—			—			—			22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			—			—			(8,219	)
Total other income (expenses)		(70,495	)		(62,830	)		(614	)		—			(133,939	)
Income (loss) before income taxes		(86,160	)		(964,706	)		(38,137	)		677			(1,088,326	)
Income tax benefit (provision)		—			(285	)		—			(1	)		(286	)
Equity in earnings of subsidiary, net of tax		(1,013,519	)		(48,528	)		—			1,062,047			—
Net income (loss)		(1,099,679	)		(1,013,519	)		(38,137	)		1,062,723			(1,088,612	)
Series A preferred dividends		(4,902	)		—			—			—			(4,902	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(11,067	)		—			(11,067	)
Net income (loss) available to common stockholders	$	(1,104,581	)	$	(1,013,519	)	$	(49,204	)	$	1,062,723		$	(1,104,581	)

42

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	Six Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	170,445		$	3,617		$	—		$	174,062
Natural gas		—			6,901			—			—			6,901
Natural gas liquids		—			5,441			—			—			5,441
Total oil, natural gas and natural gas liquids sales		—			182,787			3,617			—			186,404
Other		—			1,091			1			—			1,092
Total operating revenues		—			183,878			3,618			—			187,496
Operating expenses:
Production:
Lease operating		—			36,799			760			—			37,559
Workover and other		—			15,692			14			—			15,706
Taxes other than income		—			16,791			220			—			17,011
Gathering and other		—			21,899			4			—			21,903
Restructuring		—			5,073			—			—			5,073
General and administrative		55,840			10,406			528			(450	)		66,324
Depletion, depreciation and accretion		769			90,528			5,414			(1,774	)		94,937
Full cost ceiling impairment		—			670,828			82,167			1,774			754,769
Other operating property and equipment impairment		—			28,056			—			—			28,056
Total operating expenses		56,609			896,072			89,107			(450	)		1,041,338
Income (loss) from operations		(56,609	)		(712,194	)		(85,489	)		450			(853,842	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(35,781	)		—			—			(35,781	)
Interest expense and other, net		(155,863	)		52,753			(3,003	)		—			(106,113	)
Gain (loss) on extinguishment of debt		81,434			—			—			—			81,434
Total other income (expenses)		(74,429	)		16,972			(3,003	)		—			(60,460	)
Income (loss) before income taxes		(131,038	)		(695,222	)		(88,492	)		450			(914,302	)
Income tax benefit (provision)		—			—			—			—			—
Equity in earnings of subsidiary, net of tax		(811,781	)		(116,559	)		—			928,340			—
Net income (loss)		(942,819	)		(811,781	)		(88,492	)		928,790			(914,302	)
Series A preferred dividends		(6,396	)		—			—			—			(6,396	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(28,517	)		—			(28,517	)
Net income (loss) available to common stockholders	$	(949,215	)	$	(811,781	)	$	(117,009	)	$	928,790		$	(949,215	)

43

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	Six Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	272,997		$	9,526		$	—		$	282,523
Natural gas		—			12,537			—			—			12,537
Natural gas liquids		—			7,957			—			—			7,957
Total oil, natural gas and natural gas liquids sales		—			293,491			9,526			—			303,017
Other		—			1,201			—			—			1,201
Total operating revenues		—			294,692			9,526			—			304,218
Operating expenses:
Production:
Lease operating		—			57,930			1,088			—			59,018
Workover and other		—			6,841			4			—			6,845
Taxes other than income		—			24,596			548			—			25,144
Gathering and other		—			21,492			—			—			21,492
Restructuring		—			2,230			—			—			2,230
General and administrative		30,352			16,637			1,435			(1,353	)		47,071
Depletion, depreciation and accretion		1,192			212,198			9,770			(2,822	)		220,338
Full cost ceiling impairment		—			1,451,630			48,184			2,822			1,502,636
Total operating expenses		31,544			1,793,554			61,029			(1,353	)		1,884,774
Income (loss) from operations		(31,544	)		(1,498,862	)		(51,503	)		1,353			(1,580,556	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			12,184			—			—			12,184
Interest expense and other, net		(168,760	)		49,566			(3,034	)		(1	)		(122,229	)
Gain (loss) on extinguishment of debt		22,766			—			—			—			22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			—			—			(8,219	)
Total other income (expenses)		(154,213	)		61,750			(3,034	)		(1	)		(95,498	)
Income (loss) before income taxes		(185,757	)		(1,437,112	)		(54,537	)		1,352			(1,676,054	)
Income tax benefit (provision)		—			(6,121	)		—			5,922			(199	)
Equity in earnings of subsidiary, net of tax		(1,510,214	)		(66,981	)		—			1,577,195			—
Net income (loss)		(1,695,971	)		(1,510,214	)		(54,537	)		1,584,469			(1,676,253	)
Series A preferred dividends		(9,803	)		—			—			—			(9,803	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(19,718	)		—			(19,718	)
Net income (loss) available to common stockholders	$	(1,705,774	)	$	(1,510,214	)	$	(74,255	)	$	1,584,469		$	(1,705,774	)

44

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS

	June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	104		$	7,069		$	—		$	7,173
Accounts receivable		—			111,219			2,401			(765	)		112,855
Receivables from derivative contracts		—			135,455			—			—			135,455
Restricted cash		165			—			16,999			—			17,164
Inventory		—			1,498			—			—			1,498
Debt issuance costs, net		5,557			—			—			—			5,557
Prepaids and other		4,006			4,688			—			—			8,694
Total current assets		9,728			252,964			26,469			(765	)		288,396
Oil and natural gas properties (full cost method):
Evaluated		—			7,172,496			511,771			(4,350	)		7,679,917
Unevaluated		—			1,180,148			—			—			1,180,148
Gross oil and natural gas properties		—			8,352,644			511,771			(4,350	)		8,860,065
Less—accumulated depletion		—			(6,285,845	)		(497,621	)		4,350			(6,779,116	)
Net oil and natural gas properties		—			2,066,799			14,150			—			2,080,949
Other operating property and equipment:
Gas gathering and other operating assets		12,473			87,707			175			—			100,355
Less—accumulated depreciation		(9,475	)		(13,604	)		(76	)		—			(23,155	)
Net other operating property and equipment		2,998			74,103			99			—			77,200
Other noncurrent assets:
Receivables from derivative contracts		—			5,642			—			—			5,642
Intercompany notes and accounts receivable		4,642,675			367,525			—			(5,010,200	)		—
Equity in oil and natural gas partnership		—			11			—			—			11
Funds in escrow and other		515			1,098			—			—			1,613
Total assets	$	4,655,916		$	2,768,142		$	40,718		$	(5,010,965	)	$	2,453,811
Current liabilities:
Accounts payable and accrued liabilities	$	—		$	275,141		$	2,269		$	(35,221	)	$	242,189
Asset retirement obligations		—			412			—			—			412
Current portion of long-term debt, net		2,825,807			—			—			—			2,825,807
Total current liabilities		2,825,807			275,553			2,269			(35,221	)		3,068,408
Other noncurrent liabilities:
Liabilities from derivative contracts		—			194			—			—			194
Asset retirement obligations		—			47,274			1,280			—			48,554
Deferred income taxes		1,848			(1,848	)		—			—			—
Intercompany notes and accounts payable		367,525			4,642,675			—			(5,010,200	)		—
Investment in subsidiary		2,345,867			149,999			—			(2,495,866	)		—
Other		—			162			9,121			—			9,283
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			212,503			—			212,503
Stockholders' equity (deficit):
Preferred stock		—			—			—			—			—
Common stock		12			—			—			—			12
Additional paid-in capital		3,288,371			—			403,678			(403,678	)		3,288,371
Retained earnings (accumulated deficit)		(4,173,514	)		(2,345,867	)		(588,133	)		2,934,000			(4,173,514	)
Total stockholders' equity (deficit)		(885,131	)		(2,345,867	)		(184,455	)		2,530,322			(885,131	)
Total liabilities and stockholders' equity (deficit)	$	4,655,916		$	2,768,142		$	40,718		$	(5,010,965	)	$	2,453,811

45

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	December 31, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	100		$	7,926		$	—		$	8,026
Accounts receivable		88			166,770			9,985			(3,219	)		173,624
Receivables from derivative contracts		—			348,861			—			—			348,861
Restricted cash		138			—			16,674			—			16,812
Inventory		—			4,554			81			—			4,635
Prepaids and other		328			4,307			—			—			4,635
Total current assets		554			524,592			34,666			(3,219	)		556,593
Oil and natural gas properties (full cost method):
Evaluated		—			6,634,426			430,645			(4,350	)		7,060,721
Unevaluated		—			1,566,705			74,651			—			1,641,356
Gross oil and natural gas properties		—			8,201,131			505,296			(4,350	)		8,702,077
Less—accumulated depletion		—			(5,527,948	)		(410,090	)		4,350			(5,933,688	)
Net oil and natural gas properties		—			2,673,183			95,206			—			2,768,389
Other operating property and equipment:
Gas gathering and other operating assets		12,474			117,441			175			—			130,090
Less—accumulated depreciation		(8,705	)		(13,676	)		(54	)		—			(22,435	)
Net other operating property and equipment		3,769			103,765			121			—			107,655
Other noncurrent assets:
Receivables from derivative contracts		—			16,614			—			—			16,614
Debt issuance costs, net		7,633			—			—			—			7,633
Intercompany notes and accounts receivable		4,749,760			302,096			—			(5,051,856	)		—
Equity in oil and natural gas partnership		—			209			—			—			209
Funds in escrow and other		517			1,082			—			—			1,599
Total assets	$	4,762,233		$	3,621,541		$	129,993		$	(5,055,075	)	$	3,458,692
Current liabilities:
Accounts payable and accrued liabilities	$	—		$	326,655		$	6,102		$	(37,672	)	$	295,085
Asset retirement obligations		—			163			—			—			163
Total current liabilities		—			326,818			6,102			(37,672	)		295,248
Long-term debt, net		2,873,637			—			—			—			2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts		—			290			—			—			290
Asset retirement obligations		—			45,602			1,251			—			46,853
Intercompany notes and accounts payable		302,096			4,749,760			—			(5,051,856	)		—
Investment in subsidiary		1,534,086			32,993			—			(1,567,079	)		—
Other		—			164			6,100			—			6,264
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			183,986			—			183,986
Stockholders' equity:
Preferred stock		—			—			—			—			—
Common stock		12			—			—			—			12
Additional paid-in capital		3,283,097			—			403,678			(403,678	)		3,283,097
Retained earnings (accumulated deficit)		(3,230,695	)		(1,534,086	)		(471,124	)		2,005,210			(3,230,695	)
Total stockholders' equity		52,414			(1,534,086	)		(67,446	)		1,601,532			52,414
Total liabilities and stockholders' equity	$	4,762,233		$	3,621,541		$	129,993		$	(5,055,075	)	$	3,458,692

46

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Six Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(207,084	)	$	348,223		$	1,604		$	—			142,743
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(168,122	)		(2,136	)					(170,258	)
Other operating property and equipment capital expenditures		—			(886	)		—			—			(886	)
Advances to subsidiary		178,978			—			—			(178,978	)		—
Funds held in escrow and other		—			(233	)		—			—			(233	)
Net cash provided by (used in) investing activities		178,978			(169,241	)		(2,136	)		(178,978	)		(171,377	)
Cash flows from financing activities:
Proceeds from borrowings		425,000			—			—			—			425,000
Repayments of borrowings		(395,648	)		—			—			—			(395,648	)
Debt issuance costs		(1,186	)		—			—			—			(1,186	)
Restricted cash		—			—			(325	)		—			(325	)
Proceeds from subsidiary		—			(178,978	)		—			178,978			—
Offering costs and other		(60	)		—			—			—			(60	)
Net cash provided by (used in) financing activities		28,106			(178,978	)		(325	)		178,978			27,781
Net increase (decrease) in cash		—			4			(857	)		—			(853	)
Cash at beginning of period		—			100			7,926			—			8,026
Cash at end of period	$	—		$	104		$	7,069		$	—		$	7,173

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	Six Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(187,977	)	$	400,988		$	4,519		$	—		$	217,530
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(369,816	)		(37,935	)		—			(407,751	)
Other operating property and equipment capital expenditures		(457	)		(7,024	)		3			—			(7,478	)
Advances to subsidiary		27,136			—			—			(27,136	)		—
Funds held in escrow and other		—			3,012			—			—			3,012
Net cash provided by (used in) investing activities		26,679			(373,828	)		(37,932	)		(27,136	)		(412,217	)
Cash flows from financing activities:
Proceeds from borrowings		1,296,000			—			—			—			1,296,000
Repayments of borrowings		(1,129,000	)		—			—			—			(1,129,000	)
Debt issuance costs		(18,612	)		—			—			—			(18,612	)
Common stock issued		15,354			—			—			—			15,354
Restricted cash		—			—			(352	)		—			(352	)
Proceeds from subsidiary		—			(27,136	)		—			27,136			—
Offering costs and other		(2,444	)		—			1			—			(2,443	)
Net cash provided by (used in) financing activities		161,298			(27,136	)		(351	)		27,136			160,947
Net increase (decrease) in cash		—			24			(33,764	)		—			(33,740	)
Cash at beginning of period		—			15			43,698			—			43,713
Cash at end of period	$	—		$	39		$	9,934		$	—		$	9,973

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        The following discussion is intended to assist in understanding our results of operations for the six months ended June 30, 2016 and 2015 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

        Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see "Special note regarding forward-looking statements."

Overview

        We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production growth and broad flexibility to direct our capital resources to projects with the greatest potential returns. In the years since, we focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays. Our oil and natural gas assets consist of proved reserves and undeveloped acreage positions in unconventional liquids-rich basins/fields, including the Bakken/Three Forks formations in North Dakota and the Eagle Ford formation in East Texas, as well as other areas.

        Our average daily oil and natural gas production decreased in the first six months of 2016 when compared to the same period in the prior year as we have curtailed our drilling and completion activities in response to the decline in commodity prices. We have focused our drilling efforts on our most economic areas due to the current price environment. During the first six months of 2016, production averaged 37,703 barrels of oil equivalent (Boe) per day (Boe/d) compared to average daily production of 42,182 Boe/d during the first six months of 2015. Additional production declines are anticipated, as we shut-in approximately 5,000 Boe/d of net production during the three months ended June 30, 2016 due to low commodity prices. During the first six months of 2016, we participated in the drilling of 48 gross (20.0 net) wells, all of which were completed and capable of production.

        Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

        Oil and natural gas prices are inherently volatile and have declined dramatically since mid-year 2014. In response to this we have significantly curtailed our capital spending, reduced operating costs, and have incurred substantial asset impairments, primarily as a result of the full cost ceiling test calculation. Sustained lower commodity prices will continue to have a material impact upon our full cost ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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        The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If the average of the oil and natural gas prices for the first day of each month for the trailing 12-month period ended June 30, 2016 had been $42.91 per Bbl for oil and $2.28 per MMBtu for natural gas, holding all other factors constant, our ceiling test limitation related to the net book value of our proved oil and natural gas properties would have been reduced by an additional $10.6 million. The foregoing prices were calculated using a simple average of the oil and natural gas prices on the first day of the month for each of the 10 months ended July 2016, with the crude oil price for July 2016 of $48.99 per Bbl held constant for the remaining two months to create a trailing 12-month period. As a consequence of the reduction in the ceiling test limitation, our ceiling test impairment would have increased by an additional $10.6 million, primarily as a result of a decrease in our proved undeveloped reserves of approximately 3%, due to certain locations that would not be economical when using these prices. The foregoing calculation of the impact of lower commodity prices was prepared assuming that all inputs and factors other than oil and natural gas prices remain constant, thereby isolating the impact of commodity prices on our ceiling test limitation and proved reserves. Price is only one variable in the estimation of our proved reserves, and other factors could have a significant impact on future reserves and the present value of future cash flows, including, but not limited to, extensions and discoveries, changes in costs, drilling results, well performance and changes in our development plans. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this estimate should not be construed as indicative of our development plans or future results.

Recent Developments

        The prices of crude oil and natural gas have declined dramatically since mid-year 2014, having recently reached multiyear lows, as a result of robust non-Organization of the Petroleum Exporting Countries' (OPEC) supply growth led by unconventional production in the United States, weakening demand in emerging markets, and OPEC's decision to continue to produce at current levels. These market dynamics have led many to conclude that commodity prices are likely to remain lower for a prolonged period. In response to these developments, among other things, we have reduced our spending and completed a series of transactions that resulted in the reduction of our debt by approximately $1.1 billion and reduced our annual interest burden by approximately $61.5 million. We also extended the maturity date and amended other provisions of certain of our debt agreements. Although we believe that we have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements, based on current market conditions, we believe that a reduction in our debt and cash interest obligations is needed to improve our financial position and flexibility and to position us to take advantage of opportunities that may arise out of the current industry downturn.

        On July 27, 2016, we and certain of our subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware to pursue a pre-packaged plan of reorganization in accordance with the terms of the Restructuring Support Agreement discussed below. We expect to continue operations in the normal course during the pendency of the chapter 11 proceedings. Prior to filing the bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of our 13% senior secured notes due 2022 (the Third Lien Holders), our 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of our 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of our 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders), and together with the Third Lien Holders, Unsecured Noteholders and Convertible Noteholder, the Stakeholders, to support a restructuring on the terms of a plan of reorganization as described therein (the Plan).

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        Pursuant to the terms of the Plan as contemplated by the Restructuring Support Agreement, Stakeholders and other claims and interest holders will receive the following treatment in full and final satisfaction of such claims and interests:

•

the Halcón Entities' Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) shall be unimpaired and reinstated;

•

the Third Lien Holders will receive their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016;

•

the Unsecured Noteholders will receive their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón with a four year term and an exercise price based on an equity value of $1.33 billion, and accrued and unpaid interest on their notes through May 15, 2016;

•

the Convertible Noteholder will receive 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón with a four year term and an exercise price based on an equity value of $1.33 billion;

•

the general unsecured claims are unimpaired;

•

the Preferred Holders will receive their pro rata share of $11.1 million in cash; and

•

the existing common stockholders will receive their pro rata share of 4% of the common stock of reorganized Halcón.

        Each of the foregoing percentages of equity in the reorganized company is subject to dilution from the exercise of the new warrants described above and a management incentive plan.

        The Restructuring Support Agreement contains certain covenants on the part of the Halcón Entities and the Stakeholders, including that the Stakeholders vote in favor of the Plan outlined in the Restructuring Support Agreement and otherwise facilitate and support the restructuring transaction. The Restructuring Support Agreement also provides for termination by each party upon the occurrence of certain events, including without limitation, the failure of the Halcón Entities to achieve certain milestones, including having the Plan confirmed and effective by certain dates, and requires the satisfaction of certain conditions, such as that the Halcón Entities obtain a credit facility pursuant to an amendment or an amendment and restatement of the existing senior secured revolving credit agreement (the Senior Credit Agreement) (or any replacement financing) in an aggregate principal amount of not less than $600.0 million (the Amended Revolving Credit Agreement), which Amended Revolving Credit Agreement shall be (a) in form and substance reasonably satisfactory to the Requisite Unsecured Noteholders (as defined in the Restructuring Support Agreement), and (b) in form and substance satisfactory to the Requisite Third Lien Noteholders (as defined in the Restructuring Support Agreement).

        On June 20, 2016, the Halcón Entities commenced a solicitation for acceptance of the Plan. As a result of the solicitation, 99.997% in aggregate principal amount of the Third Lien Notes that voted, 99.860% in aggregate principal amount of the Unsecured Notes (consisting of our 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020) that voted, 100.000% of the aggregate principal amount of our 8% senior unsecured convertible note due 2020 (the Convertible Note), 99.300% in aggregate amount of the shares of our 5.75% Series A Convertible Perpetual Preferred Stock that voted, voted to support the Plan, which

51

exceeded the voting condition under the Restructuring Support Agreement. In addition, we entered into an agreement dated as of July 22, 2016 with holders of more than 51% in aggregate principal amount of our 8.625% and 12.0% Second Lien Notes due 2020 and 2022 regarding certain amendments to the indentures governing such notes in exchange for the commitment of such holders to support the Plan (the Second Lien Support Agreement). Under the terms of the Second Lien Support Agreement, each holder of the Second Lien Notes that agrees to the proposed amendments and is either party to the Second Lien Support Agreement or otherwise does not object to the Plan will, subject to the occurrence of the effective date of the Plan (and, in the case of the Second Lien Notes, the effectiveness of the proposed amendment) receive a consent fee equal to 1.25% of the aggregate principal amount of such holder's outstanding second lien notes. To effect the treatment of claims set forth above in accordance with the Plan, we withheld the regularly scheduled July 15, 2016 interest payment on our 9.75% senior notes due 2020. We also withheld the regularly scheduled June 30, 2016 interest payment on our Convertible Note, which was waived by the holder of the Convertible Note in the Restructuring Support Agreement. We made the payments set forth above of accrued and unpaid interest through May 15, 2016, prior to our chapter 11 filing. Also, to provide financial flexibility until such time as an Amended Revolving Credit Agreement is finalized and approved, prior to our chapter 11 filing, we drew approximately $338.0 million on July 25, 2016 under our Senior Credit Agreement, bringing our outstanding borrowings up to approximately $444.0 million. We believe that we currently have sufficient funds to meet our liquidity requirements throughout the bankruptcy process.

        Our debt agreements, including our Senior Credit Agreement, provide that the commencement of a voluntary proceeding in bankruptcy is an event of default leading to the automatic acceleration of the associated obligations. Accordingly, the filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code accelerated our obligations under all of the outstanding debt instruments, although any efforts to enforce payment obligations thereunder have been automatically stayed by, and the creditors' rights of enforcement are subject to, the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Waiver and Amendment to the Senior Credit Agreement

        On May 26, 2016, we entered into a waiver to our Senior Credit Agreement (the Waiver Agreement), to temporarily limit the borrowings under our senior credit facility due to our proposed reorganization plans. We agreed that until a specified date, we would not request, nor would we be permitted to request, a borrowing which would result in the aggregate exposure on the Senior Credit Agreement to exceed $450.0 million.

        On March 17, 2016, we entered into the Thirteenth Amendment to our Senior Credit Agreement (the Thirteenth Amendment), which, among other things, reduced the borrowing base to $700.0 million and scheduled our next borrowing base redetermination for September 1, 2016. Additionally, the Thirteenth Amendment provides for amounts under the Senior Credit Agreement to bear interest at specified margins over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% for Eurodollar-based loans, based on utilization of the facility.

        In connection with the chapter 11 proceedings, we entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and a $600.0 million exit senior secured reserve-based revolving credit facility. Proceeds from the DIP Facility will, among other things, be used to refinance borrowings under our current Senior Credit Agreement. Availability under the DIP Facility will be $500.0 million upon interim approval by the Bankruptcy Court, rising to $600.0 million upon entry of a final order. The DIP Facility will be converted into or otherwise refinanced by the exit credit facility following confirmation of the Plan. The DIP Facility will mature in three (3) months, subject to three-month extensions at the request of the borrower, but not

52

beyond twelve (12) months from the commencement of the bankruptcy proceedings or the effective date of a plan of reorganization confirmed by the Bankruptcy Court. Loans under the DIP Facility will bear interest at a rate per annum equal to, as selected by the Company, an alternative base rate plus an applicable margin of 1.75% to 2.75% or adjusted LIBOR plus an applicable margin of 2.75% to 3.75%, in each case based on utilization. The DIP Facility will contain certain customary affirmative and negative covenants, including limitations on indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements and transactions with affiliates, as well as compliance with an approved bi-weekly budget, subject to minor variances. The DIP Facility will also contain specified events of default, including non-payment; non-compliance with covenants or other agreements; default in other material indebtedness; certain adverse judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

Repurchase of Senior Unsecured Notes

        During the first quarter of 2016, we repurchased approximately $91.8 million principal amount of our senior unsecured notes, consisting of $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022 for cash at prevailing market prices at the time of the transactions. The net cash used to make these repurchases was approximately $9.7 million. Upon the settlement of each repurchase, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased.

Capital Resources and Liquidity

        Our near-term capital spending requirements are expected to be funded with cash flows from operations, borrowings under our Senior Credit Agreement, which has been drawn to approximately $444.0 million and our DIP facility, subject to its finalization and bankruptcy court approval. As noted above, the filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code constituted an event of default under the Senior Credit Agreement that accelerated our obligations and terminated the lenders' commitments under the Senior Credit Agreement.

        In connection with the chapter 11 proceedings, we entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and a $600.0 million exit senior secured reserve-based revolving credit facility. Proceeds from the DIP Facility will, among other things, be used to refinance borrowings under our current Senior Credit Agreement. Availability under the DIP Facility will be $500.0 million upon interim approval by the Bankruptcy Court, rising to $600.0 million upon entry of a final order. The DIP Facility will be converted into or otherwise refinanced by the exit credit facility following confirmation of the Plan. The DIP Facility will mature in three (3) months, subject to three-month extensions at the request of the borrower, but not beyond twelve (12) months from the commencement of the bankruptcy proceedings or the effective date of a plan of reorganization confirmed by the Bankruptcy Court. Loans under the DIP Facility will bear interest at a rate per annum equal to, as selected by the Company, an alternative base rate plus an applicable margin of 1.75% to 2.75% or adjusted LIBOR plus an applicable margin of 2.75% to 3.75%, in each case based on utilization. The DIP Facility will contain certain customary affirmative and negative covenants, including limitations on indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements and transactions with affiliates, as well as compliance with an approved bi-weekly budget, subject to minor variances. The DIP Facility will also contain specified events of default, including non-payment; non-compliance with covenants or other agreements; default in other material

53

indebtedness; certain adverse judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

        At June 30, 2016, the Senior Credit Agreement provided for a $1.5 billion facility with a borrowing base of $700.0 million. However, pursuant to the Waiver Agreement, we agreed not to request borrowings in excess of $450.0 million for a specified period of time. On July 25, 2016, we borrowed approximately $338.0 million, resulting in an aggregate $444.0 million of indebtedness outstanding under the Senior Credit Agreement. The borrowing base is redetermined semi-annually, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of our and our restricted subsidiaries' properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on our capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and a ratio of total secured debt (excluding the Third Lien Notes) to EBITDA of no greater than 2.75 to 1.0. At June 30, 2016, in accordance with the Waiver Agreement, discussed above, we had $101.0 million of indebtedness outstanding, $5.2 million of letters of credit outstanding and approximately $343.8 million of borrowing capacity available under our Senior Credit Agreement. At June 30, 2016, we were in compliance with the financial covenants under the Senior Credit Agreement.

        We have in the past obtained amendments to the covenants under our Senior Credit Agreement under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. We requested a reduction in the minimum required interest coverage ratio of 2.0 to 1.0 for 2014 and 2015 and those requests were granted on March 21, 2014 and again on February 25, 2015, respectively. With the Tenth Amendment and the issuance of the 2020 Second Lien Notes, the interest coverage ratio was replaced with a total secured debt to EBITDA ratio and with the Eleventh Amendment, in the calculation of total secured debt to EBITDA ratio the Third Lien Notes are excluded. The basis for these amendment and waiver requests is similar to those described above, i.e., the potential for us to fall out of compliance as a result of our strategic decisions and, in the case of the Eleventh and Twelfth Amendments, our desire to reduce overall debt through the exchanges and repurchases of senior unsecured notes. Declining commodity prices also adversely impacted our ability to comply with these covenants. As part of our plan to manage liquidity risks, we have scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties, entered into a Restructuring Support Agreement to restructure our indebtedness and, on July 27, 2016, filed a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware to pursue a pre-packaged plan of reorganization. However, we may not be able to obtain confirmation of the Plan in the Restructuring Support Agreement because there can be no assurance that the Plan (or any other plan of reorganization) will be approved by the Bankruptcy Court. Additionally, although the Plan is designed to minimize the length of our chapter 11 proceedings, it is impossible to predict the amount of time that we may spend in bankruptcy. If protracted, the chapter 11 proceedings will involve additional expenses, require significant time and effort of management, and may negatively impact our relationships with vendors, suppliers, employees and customers, all of which may adversely affect our liquidity, financial condition and results of operations.

54

        In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to further curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, may be subject to forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and may be forced to sell some of our assets on an untimely or unfavorable basis, each of which could adversely affect our results of operations and financial condition.

        Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. Even if we are otherwise successful in growing our reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted. We therefore continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling success.

        We are exposed to various risks, including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly, as they have since mid-year 2014, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge varies from period to period based on our view of current and future market conditions. Currently, we have approximately 72% of anticipated remaining 2016 oil production hedged at a weighted average price of $81.44 per Bbl. However, beyond 2016, we have currently hedged only a limited amount of our anticipated production. Sustained low commodity prices, after our current hedges expire, may adversely impact our liquidity and cash flows from operations. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivatives contracts for speculative trading purposes.

Cash Flow

        Our primary sources of cash for the six months ended June 30, 2016 and 2015 were from operating and financing activities. In the first six months of 2016, cash generated by operating and financing activities was used to fund our drilling and completion program. See "Results of Operations" for a review of the impact of prices and volumes on sales.

        Net increase (decrease) in cash is summarized as follows:

	Six Months Ended June 30,
	2016			2015
	(In thousands)
Cash flows provided by (used in) operating activities	$	142,743		$	217,530
Cash flows provided by (used in) investing activities		(171,377	)		(412,217	)
Cash flows provided by (used in) financing activities		27,781			160,947
Net increase (decrease) in cash	$	(853	)	$	(33,740	)

        Operating Activities.    Net cash provided by operating activities for the six months ended June 30, 2016 and 2015 was $142.7 million and $217.5 million, respectively. Generally, key drivers of net operating cash flows are commodity prices, production volumes, operating costs and realized settlements on our derivative contracts.

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        The $142.7 million of operating cash flows for the six months ended June 30, 2016 primarily reflect the $188.5 million of realized settlements on our derivative contracts, which continue to mitigate decreases in revenues due to the low commodity price environment.

        The $217.5 million of operating cash flows for the six months ended June 30, 2015 primarily reflect the impact of $195.9 million of realized settlements on our derivative contracts, which largely offset the decrease in revenues due to lower commodity prices, as compared to the prior year period. Cash operating expenses also decreased over the prior year period.

        Investing Activities.    The primary driver of cash used in investing activities is capital spending, specifically on drilling and completions. Net cash used in investing activities was approximately $171.4 million and $412.2 million for the six months ended June 30, 2016 and 2015, respectively.

        During the first six months of 2016, we spent $170.3 million on oil and natural gas capital expenditures, of which $109.4 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, leasing and seismic data. In response to the dramatic decline in crude oil prices since mid-year 2014 and due to the expectation that prices may not recover in the near term, we have budgeted to run an average of 1.3 rigs during 2016, and therefore plan for capital expenditures to be lower than previous years.

        During the first six months of 2015, we spent $407.8 million on oil and natural gas capital expenditures, of which $331.5 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, leasing and seismic data. We significantly decreased our planned capital spending for 2015, as compared to capital expenditure levels in prior years, in response to the significant decrease in crude oil prices since mid-year 2014, and due to the expectation that prices may not recover in the near term. Cash paid for drilling and completion costs during the first six months of 2015 were attributable to both costs incurred before we slowed our drilling and completion program and costs related to wells spud or drilled during the period.

        Financing Activities.    Net cash flows provided by financing activities were $27.8 million and $160.9 million for the six months ended June 30, 2016 and 2015, respectively. The primary drivers of cash provided by financing activities for the six months ended June 30, 2016 and 2015 were net borrowings on our Senior Credit Agreement.

        During the first six months of 2016, we repurchased approximately $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022. The net cash used to make these repurchases was approximately $9.7 million and we recognized an $81.4 million net gain on the extinguishment of debt, as an $82.1 million gain on the repurchase was partially offset by the writedown of $0.7 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the senior unsecured notes repurchased.

        During the first six months of 2015, cash flows from financing activities were modestly impacted by sales of our common stock under the Equity Distribution Agreement. For the six months ended June 30, 2015, we sold approximately 1.9 million shares for net proceeds of approximately $15.1 million.

Contractual Obligations

        We lease corporate office space in Houston, Texas; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $4.3 million for the six months ended June 30, 2016 and 2015. As of June 30, 2016, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2015 disclosed in our Annual Report on

56

Form 10-K for the fiscal year ended December 31, 2015, approximating $46.8 million in the aggregate, and containing various expiration dates through 2024.

        In addition, we have commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2018. In the first quarter of 2016, we entered into an amendment to one of our drilling rig contracts with an original term ending date of August 31, 2016, whereby, as of April 5, 2016, we early terminated the rig contract, incurred a termination fee of approximately $1.2 million and reduced our 2016 drilling commitments by extending part of the contract term on another of our drilling rig contracts out further in 2018. In January 2015, we made the decision to early terminate a drilling rig contract in response to the decline in crude oil prices, and as such, we incurred an early termination fee of $6.0 million, paid over the first half of 2015. If certain requirements are not met by two separate trigger dates, the first being January 1, 2017 and the second being January 12, 2020, we may incur up to an additional $3.0 million in connection with this drilling rig contract. Rig termination fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operation.

        In addition, we have two drilling rig commitments, for which we are incurring a stacking fee of $16,000 and $17,000 per day. The contract terms for these drilling rig commitments extends through the second quarter of 2017 and 2018, respectively. Rig stacking fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations. Early termination of our other drilling rig commitments would result in termination penalties approximating $14.8 million, which would be in lieu of the remaining $20.8 million of drilling rig commitments as of June 30, 2016.

        We have entered into various long-term gathering, transportation and sales contracts with respect to production from the Bakken/Three Forks formations in North Dakota. As of June 30, 2016, we had in place nine long-term crude oil contracts and five long-term natural gas contracts in this area. Under the terms of these contracts, we have committed a substantial portion of our Bakken/Three Forks production for periods ranging from one to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. Historically, we have been able to meet our delivery commitments.

        On June 16, 2014, we entered into a transaction to develop our Tuscaloosa Marine Shale (TMS) assets with funds and accounts managed by affiliates of Apollo Global Management, LLC and on June 1, 2015 amended this agreement. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 9, "Mezzanine Equity," for a discussion of the drilling obligation associated with the transaction.

Critical Accounting Policies and Estimates

        Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

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Results of Operations

Three Months Ended June 30, 2016 and 2015

        We reported a net loss of $374.3 million and $1.1 billion for the three months ended June 30, 2016 and 2015, respectively. The following table summarizes key items of comparison and their related change for the periods indicated.

	Three Months Ended June 30,
In thousands (except per unit and per Boe amounts)	2016			2015			Change
Net income (loss)	$	(374,303	)	$	(1,088,612	)	$	714,309
Operating revenues:
Oil		99,095			158,110			(59,015	)
Natural gas		3,159			5,578			(2,419	)
Natural gas liquids		3,504			3,889			(385	)
Other		389			447			(58	)
Operating expenses:
Production:
Lease operating		16,981			25,233			(8,252	)
Workover and other		7,915			3,731			4,184
Taxes other than income		9,753			12,903			(3,150	)
Gathering and other		10,519			7,746			2,773
Restructuring		189			309			(120	)
General and administrative:
General and administrative		23,201			19,224			3,977
Share-based compensation		1,507			3,438			(1,931	)
Depletion, depreciation and accretion:
Depletion—Full cost		37,719			98,697			(60,978	)
Depreciation—Other		1,434			2,059			(625	)
Accretion expense		518			438			80
Full cost ceiling impairment		257,869			948,633			(690,764	)
Other income (expenses):
Net gain (loss) on derivative contracts		(54,523	)		(87,564	)		33,041
Interest expense and other, net		(58,322	)		(60,922	)		2,600
Gain (loss) on extinguishment of debt		—			22,766			(22,766	)
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			(8,219	)		8,219
Income tax (provision) benefit		—			(286	)		286
Production:
Oil—MBbls		2,498			3,007			(509	)
Natural Gas—Mmcf		2,322			2,509			(187	)
Natural gas liquids—MBbls		380			333			47
Total MBoe(1)		3,265			3,758			(493	)
Average daily production—Boe(1)		35,879			41,297			(5,418	)
Average price per unit(2):
Oil price—Bbl	$	39.67		$	52.58		$	(12.91	)
Natural gas price—Mcf		1.36			2.22			(0.86	)
Natural gas liquids price—Bbl		9.22			11.68			(2.46	)
Total per Boe(1)		32.39			44.59			(12.20	)
Average cost per Boe:
Production:
Lease operating	$	5.20		$	6.71		$	(1.51	)
Workover and other		2.42			0.99			1.43
Taxes other than income		2.99			3.43			(0.44	)
Gathering and other		3.22			2.06			1.16
Restructuring		0.06			0.08			(0.02	)
General and administrative:
General and administrative		7.11			5.12			1.99
Share-based compensation		0.46			0.91			(0.45	)
Depletion		11.55			26.26			(14.71	)

(1)

Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2)

Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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        For the three months ended June 30, 2016, oil, natural gas and natural gas liquids revenues decreased $61.8 million as compared to the same period in 2015 due to lower average realized prices and a decrease in our average daily production. Average realized prices (excluding the effects of hedging arrangements) decreased from $44.59 per Boe to $32.39 per Boe, representing a 27% decrease from the prior year period. Oil and natural gas prices are inherently volatile and have decreased significantly since mid-year 2014. Average daily production decreased 13% from the prior year period, as we have curtailed our drilling in response to the decline in commodity prices.

        Lease operating expenses decreased $8.3 million for the three months ended June 30, 2016. On a per unit basis, lease operating expenses were $5.20 per Boe for the three months ended June 30, 2016, compared to $6.71 per Boe for the same period in 2015. The decrease in lease operating expenses per Boe is primarily due to price decreases from our vendors in light of the current commodity price environment.

        Workover and other expenses increased $4.2 million to $7.9 million for the three months ended June 30, 2016 as compared to the same period in 2015. The increased costs in the current year relate primarily to workovers in our Bakken area, specifically costs spent to restore production on wells with downhole problems and well casing repairs. On a per unit basis, workover and other expenses were $2.42 per Boe for the three months ended June 30, 2016, compared to $0.99 per Boe for the same period in 2015.

        Taxes other than income decreased $3.2 million for the three months ended June 30, 2016 as compared to the same period in 2015 primarily due to lower oil, natural gas and natural gas liquids revenues attributable to lower commodity prices. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.99 per Boe and $3.43 per Boe for the three months ended June 30, 2016 and 2015, respectively.

        Gathering and other expenses for the three months ended June 30, 2016 and 2015 were $10.5 million and $7.7 million, respectively. Approximately $7.1 million and $6.4 million of expenses incurred for the three months ended June 30, 2016 and 2015, respectively, relate to gathering and other fees paid on our oil and natural gas production. Also included are $3.1 million and $1.0 million of rig stacking charges (including any termination penalties) for the three months ended June 30, 2016 and 2015, respectively. We have early terminated two drilling rig contracts and decided to stack two other rigs in response to the decline in commodity prices.

        During the three months ended June 30, 2016 and 2015, we had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the respective years. We incurred approximately $0.2 million and $0.3 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees during the three months ended June 30, 2016 and 2015, respectively.

        General and administrative expense for the three months ended June 30, 2016 increased to $23.2 million from $19.2 million in same period in 2015. The increase in general and administrative expenses results from $7.5 million of fees associated with the efforts to restructure our indebtedness, partially offset by a reduction in our payroll and employee related benefits costs due to a reduction in workforce. On a per unit basis, general and administrative expenses were $7.11 per Boe and $5.12 per Boe, for the three months ended June 30, 2016 and 2015, respectively.

        Share-based compensation expense for the three months ended June 30, 2016 was $1.5 million, a decrease of $1.9 million compared to the same period in 2015. The decrease results from forfeitures since the prior year period and no new grants awarded during 2016.

        Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the

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ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense decreased $61.0 million over the prior year period. On a per unit basis, depletion expense was $11.55 per Boe for the three months ended June 30, 2016 compared to $26.26 per Boe for the three months ended June 30, 2015. The decrease in depletion expense and the depletion rate per Boe is attributable to decreases in the amortizable base due to full cost ceiling test impairments since the prior year period.

        We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling", based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $257.9 million for the three months ended June 30, 2016. The impairment primarily reflects a 7% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $46.26 per barrel at March 31, 2016. We recorded a full cost ceiling test impairment before income taxes of $948.6 million for the three months ended June 30, 2015. The ceiling test impairment in 2015 was driven by a 13% decrease in the first-day-of-the-month average prices for crude oil used in the ceiling test calculation, which was $82.71 per barrel at March 31, 2015. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. See "Overview" for a discussion and quantification of potential future ceiling impairments in an environment of sustained lower commodity prices.

        We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At June 30, 2016, we had a $141.1 million derivative asset, $135.5 million of which was classified as current, and we had a $0.2 million derivative liability, all of which was classified as non-current associated with these contracts. We recorded a net derivative loss of $54.5 million ($135.3 million net unrealized loss and $80.8 million net realized gain on settled contracts) for the three months ended June 30, 2016 compared to a net derivative loss of $87.6 million ($175.7 million net unrealized loss and $88.1 million net realized gain on settled contracts), in the same period in 2015.

        Interest expense and other decreased $2.6 million for the three months ended June 30, 2016 from the same period in 2015. Capitalized interest for the three months ended June 30, 2016 and 2015 was $20.9 million and $26.7 million, respectively. The basis for our capitalized interest calculation is our unevaluated properties, which have decreased since June 30, 2015 due to transfers into the full cost pool and due to exclusion from the calculation as a result of our decreased drilling activities, thus causing a decrease in the amount of interest capitalized in the current year period. Interest expense subject to capitalization decreased to $77.1 million in the three months ended June 30, 2016 from $85.1 million in the comparable prior year period. The decrease in interest subject to capitalization is attributed to the debt exchanges and, to a lesser extent, debt repurchases that have occurred since the prior year period.

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Six Months Ended June 30, 2016 and 2015

        We reported a net loss of $914.3 million and $1.7 billion for the six months ended June 30, 2016 and 2015, respectively. The following table summarizes key items of comparison and their related change for the periods indicated.

	Six Months Ended June 30,
In thousands (except per unit and per Boe amounts)	2016			2015			Change
Net income (loss)	$	(914,302	)	$	(1,676,253	)	$	761,951
Operating revenues:
Oil		174,062			282,523			(108,461	)
Natural gas		6,901			12,537			(5,636	)
Natural gas liquids		5,441			7,957			(2,516	)
Other		1,092			1,201			(109	)
Operating expenses:
Production:
Lease operating		37,559			59,018			(21,459	)
Workover and other		15,706			6,845			8,861
Taxes other than income		17,011			25,144			(8,133	)
Gathering and other		21,903			21,492			411
Restructuring		5,073			2,230			2,843
General and administrative:
General and administrative		62,672			38,861			23,811
Share-based compensation		3,652			8,210			(4,558	)
Depletion, depreciation and accretion:
Depletion—Full cost		90,660			215,308			(124,648	)
Depreciation—Other		3,246			4,152			(906	)
Accretion expense		1,031			878			153
Full cost ceiling impairment		754,769			1,502,636			(747,867	)
Other operating property and equipment impairment		28,056			—			28,056
Other income (expenses):
Net gain (loss) on derivative contracts		(35,781	)		12,184			(47,965	)
Interest expense and other, net		(106,113	)		(122,229	)		16,116
Gain (loss) on extinguishment of debt		81,434			22,766			58,668
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			(8,219	)		8,219
Income tax (provision) benefit		—			(199	)		199
Production:
Oil—MBbls		5,274			6,103			(829	)
Natural Gas—Mmcf		4,842			5,144			(302	)
Natural gas liquids—MBbls		781			675			106
Total MBoe(1)		6,862			7,635			(773	)
Average daily production—Boe(1)		37,703			42,182			(4,479	)
Average price per unit(2):
Oil price—Bbl	$	33.00		$	46.29		$	(13.29	)
Natural gas price—Mcf		1.43			2.44			(1.01	)
Natural gas liquids price—Bbl		6.97			11.79			(4.82	)
Total per Boe(1)		27.16			39.69			(12.53	)
Average cost per Boe:
Production:
Lease operating	$	5.47		$	7.73		$	(2.26	)
Workover and other		2.29			0.90			1.39
Taxes other than income		2.48			3.29			(0.81	)
Gathering and other		3.19			2.81			0.38
Restructuring		0.74			0.29			0.45
General and administrative:
General and administrative		9.13			5.09			4.04
Share-based compensation		0.53			1.08			(0.55	)
Depletion		13.21			28.20			(14.99	)

(1)

Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2)

Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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        For the six months ended June 30, 2016, oil, natural gas and natural gas liquids revenues decreased $116.6 million from the same period in 2015 due to lower average realized prices. Average realized prices (excluding the effects of hedging arrangements) decreased from $39.69 per Boe to $27.16 per Boe, representing a 32% decrease from the prior year period. Oil and natural gas prices are inherently volatile and have decreased significantly since mid-year 2014. Average daily production decreased 11% from the prior year period, as we have curtailed our drilling in response to the decline in commodity prices.

        Lease operating expenses decreased $21.5 million for the six months ended June 30, 2016. On a per unit basis, lease operating expenses were $5.47 per Boe for the six months ended June 30, 2016, compared to $7.73 per Boe for the same period in 2015. The decrease in lease operating expenses per Boe is primarily due to price decreases from our vendors in light of the current commodity price environment.

        Workover and other expenses increased $8.9 million to $15.7 million for the six months ended June 30, 2016 as compared to the same period in 2015. The increased costs in the current year relate to the installation of electric submersible pumps to stimulate production, as well as costs spent to restore production on wells with downhole problems and well casing repairs in our Bakken area. On a per unit basis, workover and other expenses were $2.29 per Boe for the six months ended June 30, 2016, compared to $0.90 per Boe for the same period in 2015.

        Taxes other than income decreased $8.1 million for the six months ended June 30, 2016 as compared to the same period in 2015 primarily due to lower oil, natural gas and natural gas liquids revenues attributable to significantly lower commodity prices. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.48 per Boe and $3.29 per Boe for the six months ended June 30, 2016 and 2015, respectively.

        Gathering and other expenses for the six months ended June 30, 2016 and 2015 were $21.9 million and $21.5 million, respectively. Approximately $14.8 million and $13.8 million of expenses incurred for the six months ended June 30, 2016 and 2015, respectively, relate to gathering and other fees paid on our oil and natural gas production. Also included are $6.3 million and $7.0 million of rig stacking charges (including any termination penalties) for the six months ended June 30, 2016 and 2015, respectively. We have early terminated two drilling rig contracts and decided to stack two other rigs in response to the decline in commodity prices.

        During the six months ended June 30, 2016 and 2015, we had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the respective years. We incurred approximately $5.1 million and $2.2 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees during the period.

        General and administrative expense for the six months ended June 30, 2016 increased to $62.7 million from $38.9 million in same period in 2015. The increase in general and administrative expenses results from key employee retention agreements, settlements of disputes with lease brokers and warrant holders, increases in professional fees, and fees associated with the efforts to restructure our indebtedness totaling $29.5 million, offset by a reduction in our payroll and employee related benefits costs of $6.0 million due to a reduction in workforce. On a per unit basis, general and administrative expenses were $9.13 per Boe and $5.09 per Boe, for the six months ended June 30, 2016 and 2015, respectively.

        Share-based compensation expense for the six months ended June 30, 2016 was $3.7 million, a decrease of $4.6 million compared to the same period in 2015. The decrease results from forfeitures since the prior year period and no new grants awarded during 2016.

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        Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense decreased $124.6 million for the six months ended June 30, 2016 compared to the same period in 2015, primarily attributable to decreases in the amortizable base due to the full cost ceiling impairments since the prior year period. On a per unit basis, depletion expense was $13.21 per Boe for the six months ended June 30, 2016 compared to $28.20 per Boe for the six months ended June 30, 2015.

        We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the net book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling" established by the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded full cost ceiling test impairments before income taxes totaling $754.8 million for the six months ended June 30, 2016, compared to a full cost ceiling test impairment before income taxes of $1.5 billion for the six months ended June 30, 2015. The ceiling test impairments in 2016 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2015, when the first-day-of-the-month average price for crude oil was $50.28 per barrel. Changes in commodity prices, production rates, reserve volumes, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

        We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the six months ended June 30, 2016, we recorded a non-cash impairment charge of $28.1 million. The impairment relates to our gross investments of $32.8 million in gas gathering infrastructure that will not likely be economically recoverable due to our shift in exploration, drilling and developmental plans to our most economic areas as a result of the low commodity price environment.

        We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations. At June 30, 2016, we had a $141.1 million derivative asset, $135.5 million of which was classified as current, and we had a $0.2 million derivative liability, all of which was classified as current. We recorded a net derivative loss of $35.8 million ($224.3 million net unrealized loss and $188.5 million net realized gain on settled contracts) for the six months ended June 30, 2016 compared to a net derivative gain of $12.2 million ($183.7 million net unrealized loss and $195.9 million net realized gain on settled contracts and premium costs), in the same period in 2015.

        Interest expense and other decreased $16.1 million for the six months ended June 30, 2016 from the same period in 2015. Capitalized interest for the six months ended June 30, 2016 and 2015 was $52.9 million and $51.4 million, respectively. Interest expense subject to capitalization decreased to $155.8 million in the six months ended June 30, 2016 from $168.8 million in the comparable prior year period. The decrease in interest subject to capitalization is attributed to the debt exchanges and, to a lesser extent, debt repurchases that have occurred since the prior year period partially offset by our issuance of the Secured Notes on May 1, 2015.

        During the first quarter of 2016, we repurchased approximately $91.8 million principal amount of our senior unsecured notes, consisting of $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal

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amount of our 9.25% senior notes due 2022 for cash at prevailing market prices at the time of the transactions. The net cash used to make these repurchases was approximately $9.7 million. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased and we recorded a net gain on the extinguishment of debt of approximately $81.4 million, which included the writedown of $0.7 million associated with related issuance costs and discounts and premiums for the respective notes. During the three months ended June 30, 2015, we entered into several exchange agreements with existing holders of our senior unsecured notes whereby the holders agreed to exchange an aggregate $258.0 million principal amount of their senior notes for approximately 29.0 million shares of our common stock. We recorded a net gain on the extinguishment of debt of $22.8 million on the exchanges of debt for common stock net of any write-offs associated with the respective debts' discounts and/or premiums and debt issuance costs.

        During the six months ended June 30, 2015, we entered into an amendment to our Convertible Note and to the February 2012 Warrants, in which we recorded a net gain on the extinguishment of the Convertible Notes of $5.9 million and a net loss on the modification of the February 2012 Warrants of $14.1 million.

Recently Issued Accounting Pronouncements

        We discuss recently adopted and issued accounting standards in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, "Financial Statement Presentation."

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments and Hedging Activity

        We are exposed to various risks, including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable; therefore, we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and deferred put options. The total volumes that we hedge through the use of derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our current and anticipated production for the next 18 to 24 months, when derivative contracts are available at terms (or prices) acceptable to us. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change and currently we have hedged only a limited amount of our anticipated production beyond 2016 due to low commodity prices. As a consequence our future performance is subject to increased commodity price risks and our future cash flows from operations may be subject to greater volatility than historically. We do not enter into derivative contracts for speculative trading purposes.

        We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competitive market makers. We did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. The filing of voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code constituted an event of default under our derivative contracts that gives the counterparties the option to terminate such contracts. If terminated, the contracts would be net settled in cash. We obtained a waiver from our hedge counterparties indicating that they will not exercise their option to terminate their contracts so long as the Restructuring Support Agreement is not terminated, our DIP Facility commitment letter is not terminated and we are meeting our various obligations thereunder, among other things. If our hedge

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counterparties were to terminate our derivative contracts our exposure to subsequent downward movements in commodity prices would increase.

        We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, "Derivative and Hedging Activities" for additional information.

Fair Market Value of Financial Instruments

        The estimated fair values for financial instruments under ASC 825, Financial Instruments (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 5, "Fair Value Measurements" for additional information.

Interest Rate Sensitivity

        We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and ABR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

        At June 30, 2016, the principal amount of our debt was approximately $2.9 billion, of which approximately 96.5% bears interest at a weighted average fixed interest rate of 10.5% per year. The remaining 3.5% of our total debt at June 30, 2016 bears interest at floating or market interest rates that, at our option, are tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At June 30, 2016, the weighted average interest rate on our variable rate debt was 3.2% per year. If the balance of our variable rate debt at June 30, 2016 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.3 million per year.

Item 4.    Controls and Procedures

        Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of June 30, 2016. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.

        We did not have any change in our internal controls over financial reporting during the quarter ended June 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.    Legal Proceedings

        From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of our business. While the outcome and impact of currently pending legal proceedings cannot be determined, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on our consolidated operating results, financial position or cash flows.

Item 1A.    Risk Factors

        There have been no changes to the risk factors described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, except as described below.

The Restructuring Support Agreement is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the Restructuring Support Agreement is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.

        The Restructuring Support Agreement sets forth certain conditions we must satisfy, including the timely satisfaction of milestones in the chapter 11 proceeding, such as confirmation of the Plan and effectiveness of the Plan, and obtaining a new or amended revolving credit facility with an aggregate principal amount of not less than $600.0 million, the form and substance of which is reasonably satisfactory to certain of our noteholders. Our ability to timely complete such milestones is subject to risks and uncertainties that may be beyond our control. The Restructuring Support Agreement gives the Requisite Creditors (as defined therein) the ability to terminate the Restructuring Support Agreement under certain circumstances, including the failure of certain conditions to be satisfied. Should a termination event occur, all obligations of the parties to the Restructuring Support Agreement will terminate, except that any party's termination solely with respect to itself will not result in the termination of the Restructuring Support Agreement with respect to any other party. A termination of the Restructuring Support Agreement may result in the loss of support for the Plan, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated, there can be no assurance that any new Plan would be as favorable to holders of claims as the current Plan and our chapter 11 proceedings could become protracted, which could significantly and detrimentally impact our relationships with vendors, suppliers, employees, and customers.

We will be subject to the risks and uncertainties associated with chapter 11 proceedings.

        As a consequence of our filing for relief under chapter 11 of the Bankruptcy Code, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, will be subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

•

our ability to prosecute, confirm and consummate the Plan or another plan of reorganization with respect to the chapter 11 proceedings;

•

the high costs of bankruptcy proceedings and related fees;

•

our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

•

our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;

•

our ability to maintain contracts that are critical to our operations;

•

our ability to execute our business plan in the current depressed commodity price environment;

66

•

the ability to attract, motivate and retain key employees;

•

the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

•

the ability of third parties to seek and obtain court approval to convert the chapter 11 proceedings to chapter 7 proceedings; and

•

the actions and decisions of our creditors and other third parties who have interests in our chapter 11 proceedings that may be inconsistent with our plans.

        Delays in our chapter 11 proceedings increase the risks of our being unable to reorganize our business and emerge from bankruptcy and may increase our costs associated with the bankruptcy process.

        These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that occur during our chapter 11 proceedings that may be inconsistent with our plans.

We may not be able to obtain confirmation of the Plan as outlined in the Restructuring Support Agreement.

        There can be no assurance that the Plan as outlined in the Restructuring Support Agreement (or any other plan of reorganization) will be approved by the Bankruptcy Court, so we urge caution with respect to existing and future investments in our securities.

        The success of any reorganization will depend on approval by the Bankruptcy Court and the willingness of existing debt and security holders to agree to the exchange or modification of their interests as outlined in the Plan, and there can be no guarantee of success with respect to the Plan or any other plan of reorganization. We might receive official objections to confirmation of the Plan from the various bankruptcy committees and stakeholders in the chapter 11 proceedings. We cannot predict the impact that any objection might have on the Plan or on a Bankruptcy Court's decision to confirm the Plan. Any objection may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition and results of operations.

        If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against us, including holders of our secured and unsecured debt and equity, would ultimately receive with respect to their claims. Once commenced, there can be no assurance as to whether we will successfully reorganize and emerge from chapter 11 or, if we do successfully reorganize, as to when we would emerge from chapter 11. If no plan of reorganization can be confirmed, or if the Bankruptcy Court otherwise finds that it would be in the best interest of holders of claims and interests, the chapter 11 cases may be converted to cases under chapter 7 of the Bankruptcy Code, pursuant to which a trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code.

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Upon emergence from bankruptcy, our historical financial information may not be indicative of our future financial performance.

        Our capital structure will be significantly altered under the Plan. Under fresh-start reporting rules that may apply to us upon the effective date of the Plan (or any alternative plan of reorganization), our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

The pursuit of the Restructuring Support Agreement has consumed, and the chapter 11 proceedings will continue to consume, a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

        Although the Plan is designed to minimize the length of our chapter 11 proceedings, it is impossible to predict with certainty the amount of time that we may spend in bankruptcy or to assure parties in interest that the Plan will be confirmed. The chapter 11 proceedings will involve additional expense and our management will be required to spend a significant amount of time and effort focusing on the proceedings. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, on our financial condition and results of operations, particularly if the chapter 11 proceedings are protracted.

        During the pendency of the chapter 11 proceedings, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to effectively, efficiently and safely conduct our business, and could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

Trading in our securities is highly speculative and poses substantial risks. Under the Plan, the holders of our existing common stock will receive their pro rata share of 4% of our common stock following effectiveness of the Plan, which interest could be further diluted by the warrants and management incentive plan contemplated in the Plan.

        The Plan, as contemplated in the Restructuring Support Agreement, provides that our outstanding third lien notes, unsecured notes and convertible note will be converted into common stock of the reorganized Company and that the holders of the existing common stock of the Company will receive their pro rata share of 4% of the common stock of the reorganized Company upon the Company's emergence from chapter 11. If the Plan as contemplated in the Restructuring Support Agreement is confirmed, the holders of the unsecured notes and the convertible note will also collectively receive warrants representing the right to purchase 5% of the common stock in the reorganized Company at an exercise price that equates to a market value of $1.33 billion (which value might not be attained), plus another 10% of the common stock in the reorganized Company will be reserved for issuance as awards under a post-restructuring management incentive plan. Issuances of common stock (or securities convertible into or exercisable for common stock) under the management incentive plan and any exercises of the warrants for shares of common stock will dilute the voting power of the outstanding common stock and may adversely affect the trading price of such common stock.

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Upon our emergence from bankruptcy, the composition of our Board of Directors will change significantly.

        Under the Plan, the composition of our Board of Directors will change significantly. Upon emergence, the Board will be made up of nine directors, of which one will be our Chief Executive Officer and another will be one of our existing directors, who has yet to be designated. Of the remaining seven directors, Franklin Advisors, Inc. and Ares Management LLC will be entitled to designate three directors each and the holders of our unsecured notes will be entitled to designate one director. Accordingly, seven of our nine Board members are expected to be new to the Company. The new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

        Assuming the Plan were effective as of the date hereof, it is estimated that funds advised by Franklin Advisors, Inc. and Ares Management LLC would hold approximately 40% and 19%, respectively, of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

We are currently out of compliance with the New York Stock Exchange's minimum share price requirement and are at risk of the NYSE delisting our common stock, which could materially impair the liquidity and value of our common stock.

        Our common stock is currently listed on the New York Stock Exchange (the NYSE). On May 26, 2016, we were notified by the NYSE that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE. We need to bring our share price and consecutive thirty trading-day average share price, as measured on the last trading day of any calendar month during the sixth month period following receipt of the NYSE notice, above $1.00 per share or the NYSE will commence suspension and delisting procedures. In addition, if our common stock price remains below the $1.00 threshold and falls to the point where the NYSE considers the stock price to be "abnormally low," the NYSE has the discretion to begin delisting procedures immediately. There is no formal definition of "abnormally low" in the NYSE rules but the NYSE has recently delisted shares where the price has fallen to $0.16 or less.

        A delisting of our common stock, either as result of a failure to regain compliance with the NYSE's minimum share price requirement or the Company's failure to satisfy other qualitative or quantitative standards for continued listing on the NYSE, could reduce the liquidity and market price of our common stock. Moreover, a delisting of our common stock could constitute a "fundamental change" under the terms of our 5.75% Series A Cumulative Perpetual Convertible Preferred Stock, which might require us to reserve a significantly greater number of shares of our common stock for issuance upon conversion of the preferred stock and deplete the number of authorized shares of common stock available for issuance for other purposes.

69

Transfers of our equity, or issuances of equity before or in connection with our chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

        Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We had net operating loss carryforwards of approximately $1.5 billion as of December 31, 2015. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an "ownership change", as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an "ownership change" if one or more stockholders owning 5% or more of a corporation's common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an "ownership change", the amount of its net operating losses that may be utilized to offset future table income generally is subject to an annual limitation. Even if the net operating loss carryforwards are subject to limitation under Section 382, the net operating losses can be further reduced by the amount of discharge of indebtedness arising in a chapter 11 case under Section 108 of the Internal Revenue Code.

        We expect to request that the Bankruptcy Court approve restrictions on certain transfers of our stock to limit the risk of an "ownership change" prior to our restructuring in our chapter 11 proceedings. Following the implementation of a plan of reorganization, it is likely that an "ownership change" will be deemed to occur and our net operating losses will nonetheless be subject to annual limitation.

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

        The following table sets forth information regarding our acquisition of shares of common stock for the periods presented.

	Total Number of Shares Purchased(1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 2016		3,893	$	1.13		—		—
May 2016		265		0.69		—		—
June 2016		106		0.45		—		—

(1)

All of the shares were surrendered by employees in satisfaction of tax obligations upon the vesting of restricted stock awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock, nor were they considered as or accounted for as treasury shares.

Item 3.    Defaults Upon Senior Securities

        As of June 30, 2016, cumulative undeclared dividends on the Series A Preferred Stock amounted to approximately $7.5 million.

        See Part I, Item 1, Note 1 to the Company's condensed consolidated financial statements entitled "Financial Statement Presentation" under the heading "Ability to Continue as a Going Concern," which is incorporated in this item by reference.

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Item 4.    Mine Safety Disclosures

        Not applicable.

Item 5.    Other Information

        None.

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Item 6.    Exhibits

        The following documents are included as exhibits to this Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.

3.1	Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated May 6, 2015 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed May 7, 2015).
3.1.1	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, dated December 22, 2015 (Incorporated by reference to Exhibit 3.1.1 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).
3.1.2	Certificate of Designations, Preferences, Rights and Limitations of 5.75% Series A Convertible Perpetual Preferred Stock of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed June 18, 2013).
3.2	Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed May 7, 2015).
10.1	Restructuring Support Agreement by and among Halcón Resources Corporation and certain of its subsidiaries party thereto, certain Third Lien Noteholders, certain Senior Unsecured Noteholders, the Convertible Noteholder and certain Preferred Stockholders dated June 9, 2016 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 13, 2016).
10.2	Term Sheet setting forth principal terms of the Restructuring Support Agreement by and among Halcón Resources Corporation and certain of its subsidiaries party thereto, certain Third Lien Noteholders, certain Senior Unsecured Noteholders, the Convertible Noteholder and certain Preferred Stockholders dated June 9, 2016 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed June 13, 2016).
10.3	Lock Up Agreement entered into by and among Halcón Resources Corporation and certain of its subsidiaries party thereto and certain Second Lien Noteholders, dated as of July 22, 2016 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 25, 2016).
10.4	Consent and Amendment to Restructuring Support Agreement entered into by and among Halcón Resources Corporation and certain of its subsidiaries party thereto, certain Third Lien Noteholders, certain Senior Unsecured Noteholders, the Convertible Noteholder and certain Preferred Stockholders dated July 22, 2016 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed July 25, 2016).
12.1*	Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
31.1*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer
31.2*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer
32*	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document

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101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

*

Attached hereto.

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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 hereunto duly authorized.

	HALCÓN RESOURCES CORPORATION
July 28, 2016	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer
July 28, 2016	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
July 28, 2016	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Senior Vice President, Chief Accounting Officer and Controller

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EX-12.1

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Exhibit 12.1

Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
(In thousands, except ratios)

	Six Months Ended June 30,						Years Ended December 31,
	2016			2015			2015			2014			2013			2012			2011
Earnings:
Income (loss) before income taxes	$	(914,302	)	$	(1,676,054	)	$	(1,913,535	)	$	314,880		$	(1,380,378	)	$	(67,066	)	$	5,399
Adjustments:
Equity investment (income) loss		141			234			171			(617	)		(97	)		(373	)		—
Interest capitalized		(52,944	)		(51,443	)		(113,009	)		(168,897	)		(203,993	)		(53,492	)		—
Income (loss) before income taxes, as adjusted	$	(967,105	)	$	(1,727,263	)	$	(2,026,373	)	$	145,366		$	(1,584,468	)	$	(120,931	)	$	5,399
Fixed charges		157,530			170,253			340,399			320,403			262,046			86,589			17,808
Total earnings	$	(809,575	)	$	(1,557,010	)	$	(1,685,974	)	$	465,769		$	(1,322,422	)	$	(34,342	)	$	23,207
Fixed charges:
Interest expense and amortization of finance costs	$	156,096		$	168,849		$	337,554		$	317,732		$	259,159		$	85,372		$	17,373
Rental expense representative of interest factor		1,434			1,404			2,845			2,671			2,887			1,217			435
Total fixed charges	$	157,530		$	170,253		$	340,399		$	320,403		$	262,046		$	86,589		$	17,808
Ratio of earnings to fixed charges		—	(1)		—	(3)		—	(5)		1.5			—	(7)		—	(8)		1.3
Total fixed charges	$	157,530		$	170,253		$	340,399		$	320,403		$	262,046		$	86,589		$	17,808
Pre-tax preferred dividend requirements		34,913			29,517			83,942			32,902			12,132			110,075			—
Total fixed charges plus preference dividends	$	192,443		$	199,770		$	424,341		$	353,305		$	274,178		$	196,664		$	17,808
Ratio of earnings to combined fixed charges and preference dividends		—	(2)		—	(4)		—	(6)		1.3			—	(7)		—	(9)		1.3

(1)

Due to the Company's "Loss before income taxes, as adjusted" for the six months ended June 30, 2016, the ratio coverage was less than 1:1. The Company must generate additional earnings of $967.1 million to achieve a coverage ratio of 1:1.

(2)

Due to the Company's "Loss before income taxes, as adjusted" for the six months ended June 30, 2016, the ratio coverage was less than 1:1. The Company must generate additional earnings of $1.0 billion to achieve a coverage ratio of 1:1.

(3)

Due to the Company's "Loss before income taxes, as adjusted" for the six months ended June 30, 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $1.7 billion to achieve a coverage ratio of 1:1.

(4)

Due to the Company's "Loss before income taxes, as adjusted" for the six months ended June 30, 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $1.8 billion to achieve a coverage ratio of 1:1.

(5)

Due to the Company's "Loss before income taxes, as adjusted" in 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $2.0 billion to achieve a coverage ratio of 1:1.

(6)

Due to the Company's "Loss before income taxes, as adjusted" in 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $2.1 billion to achieve a coverage ratio of 1:1.

(7)

Due to the Company's "Loss before income taxes, as adjusted" in 2013, the ratio coverage was less than 1:1. The Company must generate additional earnings of $1.6 billion to achieve a coverage ratio of 1:1.

(8)

Due to the Company's "Loss before income taxes, as adjusted" in 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $120.9 million to achieve a coverage ratio of 1:1.

(9)

Due to the Company's "Loss before income taxes, as adjusted" in 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $231.0 million to achieve a coverage ratio of 1:1.

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Exhibit 12.1

Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends (In thousands, except ratios)

EX-31.1

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Exhibit 31.1

CERTIFICATIONS FOR FORM 10-Q

I, Floyd C. Wilson, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Halcón Resources Corporation;

2.

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

3.

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

4.

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

(a)

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

(b)

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

(c)

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

(d)

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

5.

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

(a)

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

(b)

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

	HALCÓN RESOURCES CORPORATION
July 28, 2016	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer

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Exhibit 31.1

CERTIFICATIONS FOR FORM 10-Q

EX-31.2

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Exhibit 31.2

CERTIFICATIONS FOR FORM 10-Q

I, Mark J. Mize, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Halcón Resources Corporation;

2.

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

3.

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

4.

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

(a)

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

(b)

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

(c)

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

(d)

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

5.

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

(a)

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

(b)

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

	HALCÓN RESOURCES CORPORATION
July 28, 2016	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer

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Exhibit 31.2

CERTIFICATIONS FOR FORM 10-Q

EX-32

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Exhibit 32

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

        Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), Floyd C. Wilson, Chairman of the Board and Chief Executive Officer, and Mark J. Mize, Executive Vice President, Chief Financial Officer and Treasurer, of Halcón Resources Corporation (the "Company"), each hereby certifies that, to the best of his knowledge:

(1)

The Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

July 28, 2016	/s/ FLOYD C. WILSON Floyd C. Wilson Chairman of the Board and Chief Executive Officer
July 28, 2016	/s/ MARK J. MIZE Mark J. Mize Executive Vice President, Chief Financial Officer and Treasurer

        This certification accompanies this Form 10-Q and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that Section.

        A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

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Exhibit 32

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 22, 2016
Document and Entity Information
Entity Registrant Name	HALCON RESOURCES CORP
Entity Central Index Key	0001282648
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		122,639,612
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Oil, natural gas and natural gas liquids sales:
Oil	$ 99,095		$ 158,110		$ 174,062	$ 282,523
Natural gas	3,159		5,578		6,901	12,537
Natural gas liquids	3,504		3,889		5,441	7,957
Total oil, natural gas and natural gas liquids sales	105,758		167,577		186,404	303,017
Other	389		447		1,092	1,201
Total operating revenues	106,147		168,024		187,496	304,218
Production:
Lease operating	16,981		25,233		37,559	59,018
Workover and other	7,915		3,731		15,706	6,845
Taxes other than income	9,753		12,903		17,011	25,144
Gathering and other	10,519		7,746		21,903	21,492
Restructuring	189		309		5,073	2,230
General and administrative	24,708		22,662		66,324	47,071
Depletion, depreciation and accretion	39,671		101,194		94,937	220,338
Full cost ceiling impairment	257,869	$ 496,900	948,633	$ 554,000	754,769	1,502,636
Other operating property and equipment impairment		$ 28,100			28,056
Total operating expenses	367,605		1,122,411		1,041,338	1,884,774
Income (loss) from operations	(261,458)		(954,387)		(853,842)	(1,580,556)
Other income (expenses):
Net gain (loss) on derivative contracts	(54,523)		(87,564)		(35,781)	12,184
Interest expense and other, net	(58,322)		(60,922)		(106,113)	(122,229)
Gain (loss) on extinguishment of debt			22,766		81,434	22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants			(8,219)			(8,219)
Total other income (expenses)	(112,845)		(133,939)		(60,460)	(95,498)
Income (loss) before income taxes	(374,303)		(1,088,326)		(914,302)	(1,676,054)
Income tax benefit (provision)			(286)			(199)
Net income (loss)	(374,303)		(1,088,612)		(914,302)	(1,676,253)	$ (1,922,621)
Series A preferred dividends	(3,198)		(4,902)		(6,396)	(9,803)
Preferred dividends and accretion on redeemable noncontrolling interest	(4,852)		(11,067)		(28,517)	(19,718)
Net income (loss) available to common stockholders	$ (382,353)		$ (1,104,581)		$ (949,215)	$ (1,705,774)
Net income (loss) per share of common stock:
Basic (in dollars per share)	$ (3.17)		$ (10.13)		$ (7.89)	$ (17.66)
Diluted (in dollars per share)	$ (3.17)		$ (10.13)		$ (7.89)	$ (17.66)
Weighted average common shares outstanding:
Basic (in shares)	120,708		109,063		120,360	96,569
Diluted (in shares)	120,708		109,063		120,360	96,569

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CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash	$ 7,173	$ 8,026
Accounts receivable	112,855	173,624
Receivables from derivative contracts	135,455	348,861
Restricted cash	17,164	16,812
Inventory	1,498	4,635
Debt issuance costs, net	5,557
Prepaids and other	8,694	4,635
Total current assets	288,396	556,593
Oil and natural gas properties (full cost method):
Evaluated	7,679,917	7,060,721
Unevaluated	1,180,148	1,641,356
Gross oil and natural gas properties	8,860,065	8,702,077
Less - accumulated depletion	(6,779,116)	(5,933,688)
Net oil and natural gas properties	2,080,949	2,768,389
Other operating property and equipment:
Gas gathering and other operating assets	100,355	130,090
Less - accumulated depreciation	(23,155)	(22,435)
Net other operating property and equipment	77,200	107,655
Other noncurrent assets:
Receivables from derivative contracts	5,642	16,614
Debt issuance costs, net		7,633
Equity in oil and natural gas partnership	11	209
Funds in escrow and other	1,613	1,599
Total assets	2,453,811	3,458,692
Current liabilities:
Accounts payable and accrued liabilities	242,189	295,085
Asset retirement obligations	412	163
Current portion of long-term debt, net	2,825,807
Total current liabilities	3,068,408	295,248
Long -term debt, net		2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts	194	290
Asset retirement obligations	48,554	46,853
Other	9,283	6,264
Commitments and contingencies (Note 8)
Mezzanine equity:
Redeemable noncontrolling interest	212,503	183,986
Stockholders' equity (deficit):
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 222,454 and 244,724 shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding at June 30, 2016 and December 31, 2015, respectively
Common stock: 1,340,000,000 shares of $0.0001 par value authorized; 122,647,511 and 122,523,559 shares issued and outstanding at June 30, 2016 and December 31, 2015, respectively	12	12
Additional paid-in capital	3,288,371	3,283,097
Accumulated deficit	(4,173,514)	(3,230,695)
Total stockholders' equity (deficit)	(885,131)	52,414	$ 1,772,169
Total liabilities and stockholders' equity (deficit)	$ 2,453,811	$ 3,458,692

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Stockholders' equity:
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Preferred stock, shares issued	222,454	244,724
Preferred stock, shares outstanding	222,454	244,724
Cumulative Perpetual Convertible Series A (as a percent)	5.75%	5.75%
Common stock, shares authorized	1,340,000,000	1,340,000,000
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares issued	122,647,511	122,523,559
Common stock, shares outstanding	122,647,511	122,523,559

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Preferred Stock	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Balances at Dec. 31, 2014		$ 8	$ 2,995,436	$ (1,223,275)	$ 1,772,169
Balances (in shares) at Dec. 31, 2014	345	85,562
Increase (Decrease) in Stockholders' Equity
Net income (loss)				(1,922,621)	(1,922,621)
Dividends on Series A preferred stock		$ 1	9,801	(17,979)	(8,177)
Dividends on Series A preferred stock (in shares)		1,354
Conversion of Series A preferred stock (in shares)	(100)	3,258
Preferred dividends of redeemable noncontrolling interest				(12,614)	(12,614)
Accretion of redeemable noncontrolling interest				(53,561)	(53,561)
Change in fair value of redeemable noncontrolling interest				(645)	(645)
Common stock issuance			15,356		15,356
Common stock issuance (in shares)		1,888
Common stock issuance on conversion of senior notes		$ 3	231,380		231,383
Common stock issuance on conversion of senior notes (in shares)		28,955
Modification of February 2012 Warrants			14,129		14,129
Offering costs			(1,871)		(1,871)
Long-term incentive plan grants (in shares)		2,048
Long-term incentive plan forfeitures (in shares)		(388)
Reduction in shares to cover individuals' tax withholding			(947)		(947)
Reduction in shares to cover individuals' tax withholding (in shares)		(153)
Share-based compensation			19,813		19,813
Balances at Dec. 31, 2015		$ 12	3,283,097	(3,230,695)	52,414
Balances (in shares) at Dec. 31, 2015	245	122,524
Increase (Decrease) in Stockholders' Equity
Net income (loss)				(914,302)	(914,302)
Conversion of Series A preferred stock (in shares)	(23)	724
Preferred dividends of redeemable noncontrolling interest				(6,655)	(6,655)
Accretion of redeemable noncontrolling interest				(21,862)	(21,862)
Offering costs			(10)		(10)
Long-term incentive plan forfeitures (in shares)		(499)
Reduction in shares to cover individuals' tax withholding			(50)		(50)
Reduction in shares to cover individuals' tax withholding (in shares)		(106)
Share-based compensation			5,334		5,334
Reverse stock split rounding (in shares)		5
Balances at Jun. 30, 2016		$ 12	$ 3,288,371	$ (4,173,514)	$ (885,131)
Balances (in shares) at Jun. 30, 2016	222	122,648

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ (914,302)	$ (1,676,253)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	94,937	220,338
Full cost ceiling impairment	754,769	1,502,636
Other operating property and equipment impairment	28,056
Share-based compensation, net	3,652	8,210
Unrealized loss (gain) on derivative contracts	224,281	183,713
Amortization and write-off of deferred loan costs	3,024	4,092
Non-cash interest and amortization of discount and premium	1,269	1,709
Loss (gain) on extinguishment of debt	(81,434)	(22,766)
Loss (gain) on extinguishment of Convertible Note and modification of February 2012 Warrants		8,219
Accrued settlements on derivative contracts	(23,072)	(26,781)
Other income (expense)	3,973	5,008
Change in assets and liabilities:
Accounts receivable	72,286	45,320
Inventory	(449)	(5)
Prepaids and other	(4,086)	1,037
Accounts payable and accrued liabilities	(20,161)	(36,947)
Net cash provided by (used in) operating activities	142,743	217,530
Cash flows from investing activities:
Oil and natural gas capital expenditures	(170,258)	(407,751)
Other operating property and equipment capital expenditures	(886)	(7,478)
Funds held in escrow and other	(233)	3,012
Net cash provided by (used in) investing activities	(171,377)	(412,217)
Cash flows from financing activities:
Proceeds from borrowings	425,000	1,296,000
Repayments of borrowings	(395,648)	(1,129,000)
Debt issuance costs	(1,186)	(18,612)
Common stock issued		15,354
Restricted cash	(325)	(352)
Offering costs and other	(60)	(2,443)
Net cash provided by (used in) financing activities	27,781	160,947
Net increase (decrease) in cash	(853)	(33,740)
Cash at beginning of period	8,026	43,713
Cash at end of period	7,173	9,973
Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	(2,387)	(2,614)
Asset retirement obligations	919	1,754
Series A preferred dividends paid in common stock		9,803
Preferred dividends on redeemable noncontrolling interest paid-in-kind	6,655	6,131
Accretion of redeemable noncontrolling interest	21,862	12,942
Change in fair value of redeemable noncontrolling interest		645
Common stock issued on conversion of senior notes		$ 231,383
Accrued debt issuance costs	$ 904

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FINANCIAL STATEMENT PRESENTATION

6 Months Ended

Jun. 30, 2016

FINANCIAL STATEMENT PRESENTATION

FINANCIAL STATEMENT PRESENTATION

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

        Halcón Resources Corporation (Halcón or the Company) is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries and an equity method investment. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. The Company's oil and natural gas properties are managed as a whole rather than through discrete operating areas. Operational information is tracked by operating area; however, financial performance is assessed as a whole. Allocation of capital is made across the Company's entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company's management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its 2015 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on February 26, 2016. Please refer to the notes in the 2015 Annual Report on Form 10-K when reviewing interim financial results.

        On December 28, 2015, the Company completed a one-for-five reverse stock split. As a result, all share and per share information included for all periods presented in these unaudited condensed consolidated financial statements reflect the reverse stock split.

Ability to Continue as a Going Concern

        On July 27, 2016, the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a pre-packaged plan of reorganization. The Company expects to continue operations in the normal course during the pendency of the chapter 11 proceedings. Prior to filing the bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company's 13% senior secured notes due 2022 (the Third Lien Holders), the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of the Company's 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of the Company's 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders and together with the Third Lien Holders, Unsecured Noteholders and Convertible Noteholder, referred to collectively herein as, the Stakeholders). See Note 2,"Restructuring Support Agreement, "for more information. On June 20, 2016, the Halcón Entities commenced a solicitation for acceptance of the plan of reorganization (the Plan) contemplated in the Restructuring Support Agreement from the holders of impaired claims and interests entitled to vote under the Plan. At the conclusion of the Company's thirty day solicitation period, the Plan received sufficient votes to satisfy the voting conditions set forth in Section 1126(c) of the Bankruptcy Code. The Restructuring Support Agreement contains certain covenants on the part of the Halcón Entities and the Stakeholders, including that the Stakeholders vote in favor of the Plan contemplated in the Restructuring Support Agreement and otherwise facilitate and support the restructuring transaction, subject to the achievement of certain milestones and various conditions.

        The Company's debt agreements provide that the commencement of a voluntary proceeding in bankruptcy is an event of default leading to the automatic acceleration of the associated obligations. Accordingly, the filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code accelerated the Company's obligations under all of its outstanding debt instruments, although any efforts to enforce payment obligations thereunder have been automatically stayed by, and the creditors' rights of enforcement are subject to, the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Accordingly, the Company classified all of its outstanding debt as a current liability on its unaudited condensed consolidated balance sheet as of June 30, 2016.

        The significant risks and uncertainties related to the Halcón Entities' chapter 11 proceeding raise substantial doubt about the Company's ability to continue as a going concern. The unaudited condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Use of Estimates

        The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's unaudited condensed consolidated financial statements.

        Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Accounts Receivable and Allowance for Doubtful Accounts

        The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. There were no material allowances for doubtful accounts as of June 30, 2016 or December 31, 2015.

Other Operating Property and Equipment

        Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year or 10-year estimated useful life applicable to gas gathering systems and a compressed natural gas facility, respectively. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company capitalized $57.8 million and $87.2 million as of June 30, 2016 and December 31, 2015, respectively, related to the construction of its gas gathering systems, after any amounts impaired.

        Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years or the lesser of the lease term; trailers, seven years; heavy equipment, ten years; buildings, twenty years and leasehold improvements, lease term. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

        The Company reviews its gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360,Property, Plant, and Equipment(ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from an asset's undiscounted cash flows, then the Company recognizes an impairment loss for the difference between the carrying amount and the current fair value. The Company also evaluates the remaining useful lives of its gas gathering systems and other operating assets at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. For the three months ended March 31, 2016, the Company recorded a non-cash impairment charge of $28.1 million in"Other operating property and equipment impairment"in the Company's unaudited condensed consolidated statements of operations and in"Gas gathering and other operating assets"in the Company's unaudited condensed consolidated balance sheets. The impairment primarily relates to the Company's gross investments of $32.8 million in gas gathering infrastructure that will not likely be economically recoverable due to its shift in exploration, drilling and developmental plans to its most economic areas as a result of the low commodity price environment.

        In accordance with ASC 820,Fair Value Measurements and Disclosures(ASC 820), a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The estimate of the fair value of the Company's gas gathering systems was based on an income approach that estimated future cash flows associated with those assets, which resulted in negative net cash flows due to insufficient throughput of natural gas volumes and certain fixed costs necessary to operate and maintain the assets. This estimation includes the use of unobservable inputs, such as estimated future production, and gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company's gas gathering systems being classified as Level 3.

Recently Issued Accounting Pronouncements

        In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09,Compensation—Stock Compensation(ASU 2016-09). For public business entities, ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. The areas for simplification in this ASU 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. Some of the areas for simplification apply only to nonpublic entities. As there are multiple amendments in this ASU, the FASB has issued guidance on how an entity should apply each amendment, either prospectively or retrospectively. The Company is in the process of assessing the effects of the application of the new guidance.

        In March 2016, the FASB issued ASU No. 2016-06,Contingent Put and Call Options in Debt Instruments(ASU 2016-06). For public business entities, ASU 2016-06 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. ASU 2016-06 provides new guidance that simplifies the analysis of whether a contingent put or call option in a debt instrument qualifies as a separate derivative. An entity should apply the amendments in this ASU on a modified retrospective basis to existing debt instruments as of the beginning of the fiscal year for which the amendments are effective. The Company is in the process of assessing the effects of the application of the new guidance.

        In February 2016, the FASB issued ASU No. 2016-02,Leases (Topic 842)(ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and early adoption is permitted. The FASB issued ASU 2016-02 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. An entity should apply the amendments in this ASU on a modified retrospective basis. The transition will require application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the effects of the application of the new guidance.

        In November 2015, the FASB issued ASU No. 2015-17,Balance Sheet Classification of Deferred Taxes(ASU 2015-17) to simplify the presentation of deferred income taxes. Under ASU 2015-17, all deferred tax assets and liabilities, along with any related valuation allowance, are required to be classified as noncurrent on the balance sheet. Effective December 31, 2015, the Company early adopted ASU 2015-17, on a prospective basis, which resulted in the reclassification of its current deferred tax assets and liabilities as a non-current deferred tax asset and liability, net of the valuation allowance, in the accompanying unaudited condensed consolidated balance sheets. No prior periods were retrospectively adjusted.

        In September 2015, the FASB issued ASU No. 2015-16,Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments(ASU 2015-16). For public business entities, ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and early adoption is permitted. The amendments in this ASU require that an acquirer, in a business combination, recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. To simplify the accounting for adjustments made to provisional amounts recognized in a business combination, the amendments in this ASU eliminate the requirement to retrospectively account for those adjustments, and instead present separately on the face of the income statement or disclose in the footnotes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods. The adoption of ASU 2015-16 did not have an impact to the Company's financial statements or disclosures.

        In July 2015, the FASB issued ASU No. 2015-11,Simplifying the Measurement of Inventory(ASU 2015-11). ASU 2015-11 states that an entity should measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments in this update should be applied prospectively and early application is permitted. The Company does not expect the adoption of ASU 2015-11 to have a material impact to its financial statements or disclosures.

        In April 2015, the FASB issued ASU No. 2015-05,Intangibles—Goodwill and Other—Internal-Use Software(ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. For public business entities, the guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. An entity can elect to adopt the guidance either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. Early adoption is permitted. The Company adopted prospectively and it did not have a material impact to the Company's financial statements or disclosures.

        In February 2015, the FASB issued ASU No. 2015-02,Amendments to the Consolidation Analysis(ASU 2015-02). The amendments in ASU 2015-02 eliminate the previous presumption that a general partner controls a limited partner. ASU 2015-02 may impact the Company's accounting for its general partner interest in SBE Partners LP (SBE Partners), which is currently accounted for as an equity method investment. ASU 2015-02 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Entities may apply the guidance using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the first fiscal year adopted or it may apply the amendment retrospectively. The adoption of ASU 2015-02 did not have an impact on the Company's accounting for its general partner interest in SBE Partners, LP.

        In August 2014, the FASB issued ASU No. 2014-15,Presentation of Financial Statements—Going Concern(ASU 2014-15). ASU 2014-15 is effective for annual reporting periods (including interim periods within those periods) ending after December 15, 2016. Early application is permitted with companies applying the guidance prospectively. The amendments in ASU 2014-15 create a new ASC Sub-topic 205-40,Presentation of Financial Statements—Going Concernand require management to assess for each annual and interim reporting period if conditions exist that raise substantial doubt about an entity's ability to continue as a going concern. The rule requires various disclosures depending on the facts and circumstances surrounding an entity's ability to continue as a going concern. Effective June 30, 2016, the Company early adopted ASU 2014-15, on a prospective basis, which resulted in additional disclosures as discussed above.

        In May 2014, the FASB issued ASU No. 2014-09,Revenue from Contracts with Customers(ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08,Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)(ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2016, or after December 2017, if companies choose to elect the deferred adoption date approved by the FASB. Early adoption is not permitted. The Company is in the process of assessing the effects of the application of the new guidance.

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RESTRUCTURING SUPPORT AGREEMENT

6 Months Ended

Jun. 30, 2016

RESTRUCTURING SUPPORT AGREEMENT

RESTRUCTURING SUPPORT AGREEMENT

2. RESTRUCTURING SUPPORT AGREEMENT

        On June 9, 2016, the Halcón Entities entered into a Restructuring Support Agreement with the Stakeholders. On July 27, 2016, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware to effect an accelerated pre-packaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement.

        Pursuant to the terms of the Plan contemplated by the Restructuring Support Agreement, Stakeholders and other claim and interest holders will receive the following treatment in full and final satisfaction of their claims and interests:

•           the Halcón Entities' Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) shall be unimpaired and reinstated;

•           the Third Lien Holders will receive their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016;

•           the Unsecured Noteholders will receive their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón with a four year term and an exercise price based on an equity value of $1.33 billion, and accrued and unpaid interest on their notes through May 15, 2016;

•           the Convertible Noteholder will receive 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón with a four year term and an exercise price based on an equity value of $1.33 billion;

•           the general unsecured claims are unimpaired;

•           the Preferred Holders will receive their pro rata share of $11.1 million in cash; and

•           the existing common stockholders will receive their pro rata share of 4% of the common stock of reorganized Halcón.

        Each of the foregoing percentages of equity in the reorganized company is subject to dilution from the exercise of the new warrants described above and a management incentive plan.

        The Restructuring Support Agreement contains certain covenants on the part of the Halcón Entities and the Stakeholders, including that the Stakeholders vote in favor of the Plan contemplated in the Restructuring Support Agreement and otherwise facilitate and support the restructuring transaction. The Restructuring Support Agreement also provides for termination by each party upon the occurrence of certain events, including without limitation, the failure of the Halcón Entities to achieve certain milestones, including having the Plan confirmed and effective by certain dates, and requires the satisfaction of certain conditions, such as that the Halcón Entities obtain a credit facility pursuant to an amendment or an amendment and restatement of its existing Senior Credit Agreement, defined below, (or any replacement financing) in an aggregate principal amount of not less than $600.0 million (the Amended Revolving Credit Agreement), which Amended Revolving Credit Agreement shall be (a) in form and substance reasonably satisfactory to the Requisite Unsecured Noteholders (as defined in the Restructuring Support Agreement), and (b) in form and substance satisfactory to the Requisite Third Lien Noteholders (as defined in the Restructuring Support Agreement).

        On June 20, 2016, the Halcón Entities commenced a solicitation for acceptance of the Plan. As a result of the solicitation, 99.997% in aggregate principal amount of the Third Lien Notes (defined below), that voted, 99.860% in aggregate principal amount of the Unsecured Notes (consisting of the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020) that voted, 100.000% of the aggregate principal amount of the Convertible Note (defined below), and 99.300% in aggregate amount of the shares of the Series A Preferred Stock (defined below) that voted, voted to support the Plan, which exceeded the voting condition under the Restructuring Support Agreement. In addition, the Company entered into an agreement dated as of July 22, 2016 with holders of more than 51% in aggregate principal amount of its 8.625% and 12.0% Second Lien Notes due 2020 and 2022 regarding certain amendments to the indentures governing such notes in exchange for the commitment of such holders to support the Plan (the Second Lien Support Agreement). Under the terms of the Second Lien Support Agreement, each holder of the Second Lien Notes that agrees to the proposed amendments and is either party to the Second Lien Support Agreement or otherwise does not object to the Plan will, subject to the occurrence of the effective date of the Plan (and, in the case of the Second Lien Notes, the effectiveness of the proposed amendment) receive a consent fee equal to 1.25% of the aggregate principal amount of such holder's outstanding second lien notes. To effect the treatment of claims and interests set forth above in accordance with the Plan, the Company withheld the regularly scheduled July 15, 2016 interest payment on its 2020 Notes, defined below. The Company also withheld the regularly scheduled June 30, 2016 interest payment on its Convertible Note, defined below, which was waived by the holder of the Convertible Note in the Restructuring Support Agreement. The Company made the payments of accrued and unpaid interest through May 15, 2016 on the Third Lien Notes and Unsecured Notes prior to its chapter 11 filing. Also, to provide financial flexibility until such time as an Amended Revolving Credit Agreement is finalized and approved, prior to its chapter 11 filing, the Company drew approximately $338.0 million on July 25, 2016 under its Senior Credit Agreement, bringing its outstanding borrowings up to approximately $444.0 million.

        See Note 4, "Debt," and Note 10, "Stockholders' Equity," for information regarding the Company's debt and equity instruments.

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OIL AND NATURAL GAS PROPERTIES

6 Months Ended

Jun. 30, 2016

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES

3. OIL AND NATURAL GAS PROPERTIES

        The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

        The Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

        Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that are excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the unaudited condensed consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. For the six months ended June 30, 2016 and 2015, the Company capitalized interest costs of $52.9 million and $51.2 million, respectively.

        At June 30, 2016, the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2016 of the West Texas Intermediate (WTI) crude oil spot price of $43.12 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2016 of the Henry Hub natural gas price of $2.24 per million British thermal units (MMBtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2016 exceeded the ceiling amount by $257.9 million ($163.1 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. The impairment at June 30, 2016 primarily reflects a 7% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $46.26 per barrel at March 31, 2016. At March 31, 2016, the Company recorded a full cost ceiling impairment before income taxes of $496.9 million ($315.1 million after taxes, before valuation allowance). The impairment at March 31, 2016 reflects additional transfers of the remaining unevaluated Utica / Point Pleasant (Utica) and Tuscaloosa Marine Shale (TMS) properties of approximately $330.4 million and $74.8 million, respectively, to the full cost pool and, to a lesser extent, an 8% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $50.28 per barrel at December 31, 2015. As discussed above, the Company considers the facts and circumstances around its unevaluated properties that may indicate impairment on a quarterly basis. Management concluded that it is no longer probable that capital will be available or approved to continue exploratory drilling activities in the Company's Utica or TMS acreage positions in advance of the related lease expirations due to the Company's evaluation of strategic alternatives to reduce its debt while preserving liquidity in light of continued low commodity prices, together with a reduction of the Company's exploration department and the Company's intent to expend capital only on its most economical and proven areas.

        At June 30, 2015, the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2015 of the WTI spot price of $71.68 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2015 of the Henry Hub price of $3.39 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2015 exceeded the ceiling amount by $948.6 million ($597.3 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. At March 31, 2015, the Company recorded a full cost ceiling impairment before income taxes of $554.0 million ($348.8 million after taxes, before valuation allowance). The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014, when the first-day-of-the-month average price for crude oil was $94.99 per barrel and $82.71 per barrel at March 31, 2015.

        The Company recorded the full cost ceiling test impairments in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

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DEBT

6 Months Ended

Jun. 30, 2016

DEBT

DEBT

4. DEBT

        As of June 30, 2016 and December 31, 2015, the Company's current and long-term debt, respectively, consisted of the following:

	June 30, 2016(1)		December 31, 2015
	(In thousands)
Senior revolving credit facility	$	101,000	$	62,000
8.625% senior secured second lien notes due 2020(2)		689,064		687,797
12.0% senior secured second lien notes due 2022(3)		111,408		111,598
13.0% senior secured third lien notes due 2022(4)		1,010,048		1,009,585
9.25% senior notes due 2022(5)		36,660		51,887
8.875% senior notes due 2021(6)		296,184		347,671
9.75% senior notes due 2020(7)		312,522		336,470
8.0% convertible note due 2020(8)		268,921		266,629
	$	2,825,807	$	2,873,637

(1)	The Company's debt balance as of June 30, 2016 was classified as current. See "Senior Revolving Credit Facility" below for more details.
(2)	Amounts are net of $10.9 million and $12.2 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(3)	Amounts are net of $1.4 million and $1.2 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(4)	Amounts are net of $7.9 million and $8.4 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(5)	Amounts are net of $0.5 million and $0.8 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(6)	Amounts are net of a $0.8 million and a $1.0 million unamortized discount at June 30, 2016 and December 31, 2015, respectively, related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $4.3 million and $5.5 million at June 30, 2016 and December 31, 2015, respectively. Amounts are net of $4.5 million and $5.8 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively. See "8.875% Senior Notes" below for more details.
(7)	Amounts are net of a $1.6 million and a $1.9 million unamortized discount at June 30, 2016 and December 31, 2015, respectively, related to the issuance of the original 2020 Notes. The unamortized premium related to the additional 2020 Notes was approximately $2.2 million and $2.6 million at June 30, 2016 and December 31, 2015, respectively. Amounts are net of $3.6 million and $4.3 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively. See "9.75% Senior Notes" below for more details.
(8)	Amounts are net of a $20.7 million and a $23.0 million unamortized discount at June 30, 2016 and December 31, 2015, respectively. See "8.0% Convertible Note" below for more details.

Senior Revolving Credit Facility

        On February 8, 2012, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Senior Credit Agreement provides for a $1.5 billion facility with a borrowing base of $700.0 million. However, pursuant to the Waiver Agreement, defined below, the Company agreed not to request borrowings in excess of $450.0 million for a specified period of time. On July 25, 2016, the Company borrowed approximately $338.0 million, resulting in the Company having an aggregate $444.0 million of indebtedness outstanding under the Senior Credit Agreement. The borrowing base is redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. At June 30, 2016, the weighted average interest rate on the Company's variable rate debt was 3.2% per year. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's and its restricted subsidiaries' properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on the Company's capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and a ratio of total secured debt (excluding the Third Lien Notes) to EBITDA of no greater than 2.75 to 1.0.

        On May 26, 2016, the Company entered into a waiver to its Senior Credit Agreement (the Waiver Agreement), which, among other things, temporarily limited the borrowings under its senior credit facility in connection with the Company's chapter 11 reorganization plans. The Company agreed that for a specified period of time it would not request, nor will it be permitted to request, a borrowing which would result in the aggregate exposure on the Senior Credit Agreement to exceed $450.0 million. Refer to Note 2,"Restructuring Support Agreement,"for further details regarding the Company's chapter 11 reorganization plans.

        On March 17, 2016, the Company entered into the Thirteenth Amendment to its Senior Credit Agreement (the Thirteenth Amendment), which, among other things, reduced the borrowing base to $700.0 million and scheduled the Company's next borrowing base redetermination for September 1, 2016. Additionally, the Thirteenth Amendment changed the Company's interest margins under the facility to those described above.

        At June 30, 2016, the Company had $101.0 million of indebtedness outstanding, $5.2 million letters of credit outstanding and was in compliance with the financial covenants under the Senior Credit Agreement.

        The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 1, "Financial Statement Presentation," constituted an event of default under the Senior Credit Agreement that accelerated the Company's obligations and terminated the lenders' commitments under the Senior Credit Agreement.

        In connection with the chapter 11 proceedings, the Company entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and a $600.0 million exit senior secured reserve-based revolving credit facility. Proceeds from the DIP Facility will, among other things, be used to refinance borrowings under the Company's current Senior Credit Agreement. Availability under the DIP Facility will be $500.0 million upon interim approval by the Bankruptcy Court, rising to $600.0 million upon entry of a final order. The DIP Facility will be converted into or otherwise refinanced by the exit credit facility following confirmation of the Plan. The DIP Facility will mature in three (3) months, subject to three-month extensions at the request of the borrower, but not beyond twelve (12) months from the commencement of the bankruptcy proceedings or the effective date of a plan of reorganization confirmed by the Bankruptcy Court. Loans under the DIP Facility will bear interest at a rate per annum equal to, as selected by the Company, an alternative base rate plus an applicable margin of 1.75% to 2.75% or adjusted LIBOR plus an applicable margin of 2.75% to 3.75%, in each case based on utilization. The DIP Facility will contain certain customary affirmative and negative covenants, including limitations on indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements and transactions with affiliates, as well as compliance with an approved bi-weekly budget, subject to minor variances. The DIP Facility will also contain specified events of default, including non-payment; non-compliance with covenants or other agreements; default in other material indebtedness; certain adverse judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

8.625% Senior Secured Second Lien Notes

        On May 1, 2015, the Company issued $700.0 million aggregate principal amount of its 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes) in a private placement. The 2020 Second Lien Notes were issued at par. The net proceeds from the sale of the 2020 Second Lien Notes were approximately $686.2 million (after deducting offering fees and expenses). The Company used the net proceeds from the offering to repay the majority of the then outstanding borrowings under its Senior Credit Agreement.

        The 2020 Second Lien Notes bear interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2020 Second Lien Notes will mature on February 1, 2020. The 2020 Second Lien Notes are secured by second-priority liens on substantially all of the Company's and its guarantors' assets to the extent such assets secure the Company's Senior Credit Agreement, its 2022 Second Lien Notes (defined below) and its Third Lien Notes (defined below) (the Collateral). Pursuant to the terms of an Intercreditor Agreement, dated May 1, 2015, as amended by those certain Priority Confirmation Joinders, dated September 10, 2015 and December 21, 2015, in connection with the issuance of the Third Lien Notes and the 2022 Second Lien Notes, respectively (the Intercreditor Agreement), the security interest in those assets that secure the 2020 Second Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2020 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness to the extent of the value of such assets. The Collateral does not include any of the assets of HK TMS, LLC, a wholly owned subsidiary of the Company, or any of the Company's future unrestricted subsidiaries.

12.0% Senior Secured Second Lien Notes

        On December 21, 2015, the Company completed the issuance in a private placement of approximately $112.8 million aggregate principal amount of new 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes) in exchange for approximately $289.6 million principal amount of its senior unsecured notes, consisting of $116.6 million principal amount of 9.75% senior notes due 2020, $137.7 million principal amount of 8.875% senior notes due 2021 and $35.3 million principal amount of 9.25% senior notes due 2022. At closing, the Company paid all accrued and unpaid interest since the respective interest payment dates of the unsecured notes surrendered in the exchange. The Company recorded the issuance of the 2022 Second Lien Notes at par.

        Interest on the 2022 Second Lien Notes accrues at a rate of 12.0% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2016. The 2022 Second Lien Notes will mature on February 15, 2022. The 2022 Second Lien Notes are secured by second-priority liens on the Collateral. Pursuant to the terms of the Intercreditor Agreement, dated December 21, 2015, the security interest in the Collateral securing the 2022 Second Lien Notes and the guarantees are contractually equal with the liens that secure the 2020 Second Lien Notes and contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2022 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness and effectively equal to the 2020 Second Lien Notes, in each case to the extent of the value of the Collateral.

13.0% Senior Secured Third Lien Notes

        On September 10, 2015, the Company issued approximately $1.02 billion aggregate principal amount of new 13.0% senior secured third lien notes due 2022 (the Third Lien Notes) in a private placement in exchange for approximately $497.2 million principal amount of its 9.75% senior notes due 2020, $774.7 million principal amount of its 8.875% senior notes due 2021 and $294.4 million principal amount of its 9.25% senior notes due 2022 in privately negotiated transactions with certain holders of its outstanding senior unsecured notes. At closing, the Company paid all accrued and unpaid interest since the respective interest payment dates of the notes surrendered in the exchange. The Company recorded the issuance of the Third Lien Notes at par.

        The Third Lien Notes bear interest at a rate of 13.0% per annum, payable semi-annually on February 15 and August 15, commencing on February 15, 2016. The Third Lien Notes mature on February 15, 2022. The Third Lien Notes are secured by third-priority liens on the Collateral. The Third Lien Notes are governed by an Indenture dated September 10, 2015, which contains affirmative and negative covenants substantially similar to those governing the Company's outstanding 2020 Second Lien Notes and the 2022 Second Lien Notes. Pursuant to the terms of the Intercreditor Agreement, the security interest in those assets that secure the Third Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and certain other permitted indebtedness. Consequently, the Third Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and such other indebtedness to the extent of the value of the Collateral.

9.25% Senior Notes

        On August 13, 2013, the Company issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting offering fees and expenses) were used to repay a portion of the then outstanding borrowings under the Company's Senior Credit Agreement.

        The 2022 Notes bear interest at a rate of 9.25% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2014. The 2022 Notes will mature on February 15, 2022. The 2022 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2022 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2022 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        During the first quarter of 2016, the Company repurchased $15.5 million principal amount of 2022 Notes for cash at prevailing market prices at the time of the transactions and recognized an $11.1 million net gain on the extinguishment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2022 Notes. As of June 30, 2016, $37.2 million principal amount of the Company's 2022 Notes remained outstanding.

8.875% Senior Notes

        On November 6, 2012, the Company issued $750.0 million aggregate principal amount of its 8.875% senior notes due 2021 (the 2021 Notes), at a price to the initial purchasers of 99.247% of par. The net proceeds from the offering of approximately $725.6 million (after deducting offering fees and expenses) and were used to fund a portion of the cash consideration paid in the Williston Basin Acquisition.

        On January 14, 2013, the Company issued an additional $600.0 million aggregate principal amount of the 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes of approximately $619.5 million (after offering fees and expenses) were used to repay all of the then outstanding borrowings under the Senior Credit Agreement and for general corporate purposes, including funding a portion of the Company's 2013 capital expenditures program. These notes were issued as "additional notes" under the indenture governing the 2021 Notes and under the indenture are treated as a single series with substantially identical terms as the 2021 Notes previously issued.

        The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The 2021 Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2021 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        In conjunction with the issuance of the 2021 Notes, the Company recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $0.8 million at June 30, 2016. In conjunction with the issuance of the additional 2021 Notes, the Company recorded a premium of approximately $30.0 million to be amortized over the remaining life of the additional 2021 Notes using the effective interest method. The remaining unamortized premium was $4.3 million at June 30, 2016.

        During the first quarter of 2016, the Company repurchased $51.8 million principal amount of the 2021 Notes for cash at prevailing market prices at the time of the transactions and recognized a $47.5 million net gain on the extinguishment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2021 Notes. As of June 30, 2016, $297.2 million principal amount of the Company's 2021 Notes remained outstanding.

9.75% Senior Notes

        On July 16, 2012, the Company issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million (after deducting offering fees and expenses) and were used to fund a portion of the cash consideration paid in the merger with GeoResources, Inc., and the acquisition of certain oil and gas leaseholds located in East Texas.

        On December 19, 2013, the Company issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.3 million (after deducting offering fees and expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

        The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of the Company and are effectively subordinate to its secured debt, including secured debt under the Senior Credit Agreement, the 2020 Second Lien Notes, the 2022 Second Lien Notes and the Third Lien Notes and rank equally with all of its current and future senior indebtedness. The 2020 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for the subsidiary, HK TMS, LLC. Halcón, the issuer of the 2020 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        In conjunction with the issuance of the 2020 Notes, the Company recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $1.6 million at June 30, 2016. In conjunction with the issuance of the additional 2020 Notes, the Company recorded a premium of approximately $11.0 million to be amortized over the remaining life of the additional 2020 Notes using the effective interest method. The remaining unamortized premium was approximately $2.2 million at June 30, 2016.

        During the first quarter of 2016, the Company repurchased $24.5 million principal amount of the 2020 Notes for cash at prevailing market prices at the time of the transactions and recognized a $22.8 million net gain on the extinguishment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2020 Notes. As of June 30, 2016, $315.5 million principal amount of the Company's 2020 Notes remained outstanding.

8.0% Convertible Note

        On February 8, 2012, the Company issued to HALRES, LLC (HALRES), a note in the principal amount of $275.0 million due 2017 (the Convertible Note) together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. The Convertible Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year. Through the March 31, 2014 interest payment date, the Company was permitted to elect to pay the interest in kind, by adding to the principal of the Convertible Note, all or any portion of the interest due on the Convertible Note. The Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and added $3.2 million, $5.7 million and $5.8 million of interest incurred, respectively, to the Convertible Note, increasing the principal amount to $289.7 million. The Company did not elect to pay-in-kind interest for the subsequent quarterly payments. The Convertible Note is a senior unsecured obligation of the Company.

        On March 9, 2015, the Company entered into an amendment (the HALRES Note Amendment) to its Convertible Note. The HALRES Note Amendment extended the maturity date of the Convertible Note by three years, from February 8, 2017 to February 8, 2020. The Convertible Note originally provided for prepayment without premium or penalty at any time after February 8, 2014, at which time it also became convertible into shares of the Company's common stock at a conversion price of $22.50 per share. These dates have been extended pursuant to the HALRES Note Amendment and the conversion price has been adjusted, such that at any time after March 9, 2017, the Company may prepay the Convertible Note without premium or penalty, and HALRES may elect to convert all or any portion of unpaid principal and interest outstanding under the Convertible Note to shares of the Company's common stock at a conversion price of $12.20 per share, subject to adjustments for stock splits and other customary anti-dilution provisions as set forth in the Convertible Note. At the same time, the Company also entered into an amendment to the February 2012 Warrants (the Warrant Amendment) which extended the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusted the exercise price of the February 2012 Warrants from $22.50 to $12.20 per share. The HALRES Note Amendment and the Warrant Amendment were approved by the Company's stockholders on May 6, 2015, in accordance with the rules of the New York Stock Exchange. In conjunction with the HALRES Note Amendment, the Company recorded a discount of $25.9 million to be amortized over the remaining life of the Convertible Note using the effective interest method. As of June 30, 2016, the remaining unamortized discount was $20.7 million.

Debt Issuance Costs

        The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. For the six months ended June 30, 2016, the Company expensed $2.5 million of debt issuance costs in conjunction with the debt repurchases and a decrease in the borrowing base under the Senior Credit Agreement. At June 30, 2016 and December 31, 2015, the Company had approximately $34.5 million and $40.3 million, respectively, of unamortized debt issuance costs. The debt issuance costs for the Company's Senior Credit Agreement are presented in"Debt issuance costs, net"within total assets on the unaudited condensed consolidated balance sheets, and the debt issuance costs for the Company's senior secured and unsecured debt are presented in"Current portion of long-term debt, net"and"Long-term debt, net"within total liabilities on the unaudited condensed consolidated balance sheets.

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FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 2016

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

5. FAIR VALUE MEASUREMENTS

        Pursuant to ASC 820,Fair Value Measurements(ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's unaudited condensed consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value 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). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

        The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of June 30, 2016 and December 31, 2015. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the six months ended June 30, 2016 or the year ended December 31, 2015.

	June 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	141,097	$	—	$	141,097
Liabilities
Liabilities from derivative contracts	$	—	$	42	$	152	$	194

	December 31, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	365,475	$	—	$	365,475
Liabilities
Liabilities from derivative contracts	$	—	$	105	$	185	$	290

        Derivative contracts listed above as Level 2 include collars, swaps and swaptions that are carried at fair value. The Company records the net change in the fair value of these positions in"Net gain (loss) on derivative contracts"in the Company's unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 6,"Derivative and Hedging Activities"for additional discussion of derivatives.

        Derivative contracts listed above as Level 3 include extendable collars that are carried at fair value. The significant unobservable inputs for these Level 3 contracts include unpublished forward strip prices and market volatilities. The following table sets forth a reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy:

	Significant Unobservable Inputs (Level 3)
	June 30, 2016			December 31, 2015
	(In thousands)
Beginning Balance	$	(185	)	$	(1,319	)
Net gain (loss) on derivative contracts		33			1,134
Ending Balance	$	(152	)	$	(185	)
Change in unrealized gains (losses) included in earnings related to derivatives still held at June 30, 2016 and December 31, 2015	$	33		$	(185	)

        The Company's derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.

        The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825,Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivables and accounts payables approximate their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair values of the Company's fixed interest rate debt instruments as of June 30, 2016 and December 31, 2015 (excluding discounts, premiums and debt issuance costs):

	June 30, 2016				December 31, 2015
Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
	(In thousands)
8.625% senior secured second lien notes	$	700,000	$	659,120	$	700,000	$	479,500
12.0% senior secured second lien notes		112,826		106,237		112,826		77,286
13.0% senior secured third lien notes		1,017,970		539,524		1,017,970		333,385
9.25% senior notes		37,194		8,276		52,694		14,422
8.875% senior notes		297,193		66,125		348,944		95,506
9.75% senior notes		315,535		70,207		340,035		93,068
8.0% convertible note		289,669		69,926		289,669		87,393
	$	2,770,387	$	1,519,415	$	2,862,138	$	1,180,560

        The fair value of the Company's fixed interest rate debt instruments was calculated using Level 2 criteria. The fair value of the Company's senior notes is based on quoted market prices from trades of such debt. The fair value of the Company's Convertible Note is based on published market prices and risk-free rates.

        During the three months ended March 31, 2016, the Company recorded a non-cash impairment charge of $28.1 million related to its gas gathering systems. See Note 1,"Financial Statement Presentation,"for a discussion of the valuation approach used and the classification of the estimate within the fair value hierarchy.

        As discussed in Note 4, "Debt" and in Note 10, "Stockholders' Equity," on May 6, 2015, the HALRES Note Amendment and the Warrant Amendment became effective. The fair value estimates for the Convertible Note and the February 2012 Warrants include the use of observable inputs such as the Company's stock price, expected volatility, and credit spread and the risk-free rate. The use of these observable inputs results in the fair value estimates being classified as Level 2.

        The Company follows the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company's initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management's expectation of future cost environments; consequently, the Company has designated these liabilities as Level 3. See Note 7, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

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DERIVATIVE AND HEDGING ACTIVITIES

6 Months Ended

Jun. 30, 2016

DERIVATIVE AND HEDGING ACTIVITIES

DERIVATIVE AND HEDGING ACTIVITIES

6. DERIVATIVE AND HEDGING ACTIVITIES

        The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to economically hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. When derivative contracts are available at terms (or prices) acceptable to the Company, it generally hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company's hedge policies and objectives may change significantly as its operational profile changes and/or commodities prices change. The Company does not enter into derivative contracts for speculative trading purposes.

        It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company did not post collateral under any of its derivative contracts as they are secured under the Company's Senior Credit Agreement or are uncollateralized trades.

        At June 30, 2016 and December 31, 2015, the Company's crude oil and natural gas derivative positions consisted of swaps, swaptions, costless put/call "collars," and extendable costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. Extendable collars are costless put/call contracts that may be extended annually at the option of the counterparty on a designated date. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in"Net gain (loss) on derivative contracts"on the unaudited condensed consolidated statements of operations.

        At June 30, 2016, the Company had 34 open commodity derivative contracts summarized in the following tables: one natural gas collar arrangement, 14 crude oil collar arrangements, 13 crude oil swaps, five crude oil swaptions and one crude oil extendable collar.

        At December 31, 2015, the Company had 36 open commodity derivative contracts summarized in the following tables: one natural gas collar arrangement, 16 crude oil collar arrangements, 13 crude oil swaps, five crude oil swaptions and one crude oil extendable collar.

        All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2016 and December 31, 2015:

		Asset derivative contracts					Liability derivative contracts
Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	June 30, 2016		December 31, 2015		Balance sheet location	June 30, 2016			December 31, 2015
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	135,455	$	348,861	Current liabilities—liabilities from derivative contracts	$	—		$	—
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		5,642		16,614	Other noncurrent liabilities—liabilities from derivative contracts		(194	)		(290	)
Total derivatives not designated as hedging contracts under ASC 815		$	141,097	$	365,475		$	(194	)	$	(290	)

        The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's unaudited condensed consolidated statements of operations:

		Amount of gain or (loss) recognized in income on derivative contracts for the Three Months Ended June 30,						Amount of gain or (loss) recognized in income on derivative contracts for the Six Months Ended June 30,
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2016			2015			2016			2015
		(In thousands)						(In thousands)
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(135,303	)	$	(175,712	)	$	(224,281	)	$	(183,713	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		80,780			88,148			188,500			195,897
Total net gain (loss) on derivative contracts		$	(54,523	)	$	(87,564	)	$	(35,781	)	$	12,184

        At June 30, 2016 and December 31, 2015, the Company had the following open crude oil and natural gas derivative contracts:

			June 30, 2016
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
July 2016 - December 2016	Collars	Natural Gas		368,000	$4.00	$	4.00	$4.22	$	4.22
July 2016 - December 2016(1)(3)	Collars	Crude Oil		2,024,000	60.00 - 90.00		73.00	64.00 - 95.10		78.87
July 2016 - December 2016(2)(3)	Swaps	Crude Oil		2,392,000	62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750	50.00 - 60.00		57.33	70.00 - 76.84		74.16

			December 31, 2015
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
January 2016 - June 2016	Collars	Crude Oil		182,000	$90.00	$	90.00	$96.85	$	96.85
January 2016 - December 2016	Collars	Natural Gas		732,000	4.00		4.00	4.22		4.22
January 2016 - December 2016(1)	Collars	Crude Oil		4,392,000	60.00 - 90.00		71.91	64.00 - 95.10		77.71
January 2016 - December 2016(2)	Swaps	Crude Oil		4,758,000	62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750	50.00 - 60.00		57.33	70.00 - 76.84		74.16

(1)	Includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $60.00 per Bbl and a ceiling of $75.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2017.
(2)	Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended by the counterparty at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.
(3)	Subsequent to June 30, 2016, crude oil collars totaling 184,000 Bbls and crude oil swaps totaling 184,000 Bbls for the remainder of 2016 were terminated resulting in proceeds of $9.6 million to the Company.

        The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at June 30, 2016 and December 31, 2015:

	Derivative Assets						Derivative Liabilities
Offsetting of Derivative Assets and Liabilities	June 30, 2016			December 31, 2015			June 30, 2016			December 31, 2015
	(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	141,097		$	365,475		$	(194	)	$	(290	)
Amounts Not Offset in the Consolidated Balance Sheet		(21	)		(53	)		20			52
Net Amount	$	141,076		$	365,422		$	(174	)	$	(238	)

        The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

        The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 1, "Financial Statement Presentation," constituted an event of default under the Company's derivatives contracts that gives the counterparties the option to terminate such contracts. If terminated, the contracts would be net settled in cash. The Company obtained a waiver from its hedge counterparties indicating that they will not exercise their option to terminate their contracts so long as the Restructuring Support Agreement is not terminated, the DIP Facility commitment letter is not terminated and the Company meet its various obligations thereunder, among other things.

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ASSET RETIREMENT OBLIGATIONS

6 Months Ended

Jun. 30, 2016

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

7. ASSET RETIREMENT OBLIGATIONS

        The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For gas gathering systems and equipment, the Company records an ARO when the system is placed in service and it can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work when it is required. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes a portion of the cost in "Oil and natural gas properties" or "Other operating property and equipment" during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in "Depletion, depreciation and accretion" expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

        The Company recorded the following activity related to its ARO liability for the six months ended June 30, 2016 (in thousands, inclusive of the current portion):

Liability for asset retirement obligations as of December 31, 2015	$	47,016
Liabilities settled and divested		(180	)
Additions		1,024
Acquisitions		75
Accretion expense		1,031
Liability for asset retirement obligations as of June 30, 2016	$	48,966

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COMMITMENTS AND CONTINGENCIES

6 Months Ended

Jun. 30, 2016

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

8. COMMITMENTS AND CONTINGENCIES

Commitments

        The Company leases corporate office space in Houston, Texas; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $4.3 million for the six months ended June 30, 2016 and 2015. As of June 30, 2016, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2015, as disclosed in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, approximating $46.8 million in the aggregate, and containing various expiration dates through 2024.

        In addition, the Company has commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2018. In the first quarter of 2016, the Company entered into an amendment to one of its drilling rig contracts with an original term ending date of August 31, 2016, whereby, as of April 5, 2016, the Company early terminated the rig contract, incurred a termination fee of approximately $1.2 million and reduced its 2016 drilling commitments by extending part of the contract term on another of its drilling rig contracts out further in 2018. In January 2015, the Company made the decision to early terminate a drilling rig contract in response to the decline in crude oil prices, and the Company incurred an early termination fee of $6.0 million, paid over the first half of 2015. If certain requirements are not met by two separate trigger dates, the first being January 1, 2017 and the second being January 12, 2020, the Company may incur up to an additional $3.0 million in connection with this drilling rig contract. Rig termination fees are expensed as incurred within"Gathering and other"on the unaudited condensed consolidated statements of operations.

        In addition, the Company has two drilling rig commitments, for which the Company is incurring a stacking fee of $16,000 and $17,000 per day. The contract terms for these drilling rig commitments extends through the second quarter of 2017 and 2018, respectively. Rig stacking fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations. Early termination of the Company's additional drilling rig commitments would result in termination penalties approximating $14.8 million, which would be in lieu of the remaining $20.8 million of drilling rig commitments as of June 30, 2016.

        The Company has entered into various long-term gathering, transportation and sales contracts with respect to production from the Bakken/Three Forks formations in North Dakota. As of June 30, 2016, the Company had in place nine long-term crude oil contracts and five long-term natural gas contracts in this area. Under the terms of these contracts, the Company has committed a substantial portion of its Bakken/Three Forks production for periods ranging from one to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. Historically, the Company has been able to meet its delivery commitments.

        On June 16, 2014, the Company entered into a transaction to develop its TMS assets with funds and accounts managed by affiliates of Apollo Global Management, LLC and on June 1, 2015 amended this agreement. See Note 9, "Mezzanine Equity," for a discussion of the drilling obligation associated with the transaction.

Contingencies

        From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company's management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company's unaudited condensed consolidated operating results, financial position or cash flows.

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MEZZANINE EQUITY

6 Months Ended

Jun. 30, 2016

MEZZANINE EQUITY

MEZZANINE EQUITY

9. MEZZANINE EQUITY

        On June 16, 2014, funds and accounts managed by affiliates of Apollo Global Management, LLC (Apollo) contributed $150 million in cash to HK TMS, LLC, a Delaware limited liability company (HK TMS), wholly owned by the Company that, as of June 16, 2014 held all of the Company's undeveloped acreage in the TMS formation, located in Mississippi and Louisiana, in exchange for the issuance by HK TMS of 150,000 preferred shares. At the closing, the Company also contributed $50 million in cash to HK TMS. Holders of the HK TMS preferred shares will receive quarterly cash dividends of 8% cumulative perpetual per annum, subject to HK TMS' option to pay such dividends "in-kind" through the issuance of additional preferred shares. The preferred shares will be automatically redeemed and cancelled when the holders receive cash dividends and distributions on the preferred shares equating to the greater of a 12% annual rate of return plus principal and 1.25 times their investment plus applicable fees (the Redemption Price), subject to adjustment under certain circumstances. The preferred shares have a liquidation preference in the event of dissolution in an amount equal to the Redemption Price plus any unpaid dividends not otherwise included in the calculation of the Redemption Price through the date of liquidation payment. HK TMS may also redeem the preferred shares at any time after December 31, 2016 by paying the Redemption Price, or may be required to redeem the preferred shares for the Redemption Price plus certain fees under certain circumstances.

        On June 1, 2015, HK TMS and Apollo entered into an amendment to the original agreement (the HK TMS Amendment) which, among other things, i) commits HK TMS to drill a minimum of 6.5 net wells in each of the five consecutive twelve month periods beginning December 31, 2015 and ii) allows for the redemption of preferred shares at the Redemption Price between March 1, 2016 and June 30, 2016 at the election of Apollo to the extent there is available cash above the minimum cash balance, which is discussed further below. For any commitment period in which HK TMS does not meet its drilling obligation, HK TMS must use available cash, above the minimum cash balance, to redeem preferred shares at the Redemption Price.

        The preferred shares have been classified as "Redeemable noncontrolling interest" and included in "Mezzanine equity" between total liabilities and stockholders' equity on the unaudited condensed consolidated balance sheets pursuant to ASC 480-10-S99-3A. The preferred shares are considered probable of becoming redeemable and therefore were accreted up to the estimated required redemption value through June 30, 2016. The accretion is presented as a deemed dividend and recorded in "Redeemable noncontrolling interest" on the unaudited condensed consolidated balance sheets and within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. In accordance with ASC 480-10-S99-3A, an adjustment to the carrying amount presented in "Mezzanine equity" will be recognized as charges against retained earnings and will reduce income available to common shareholders in the calculation of earnings per share. Adjustments to the carrying amount may not be necessary if the application of ASC No. 810,Consolidation(ASC 810) results in a noncontrolling interest balance in excess of what is required pursuant to ASC 480-10-S99-3A.

        In March 2015, Apollo delivered a withdrawal notice to HK TMS indicating their election not to acquire additional preferred shares in HK TMS (the Withdrawal Notice). Upon issuance of the Withdrawal Notice, HK TMS incurs a fee escalating from $2.50 per share to $20.00 per share for the next eight full fiscal quarters for any preferred shares then outstanding, which began in the quarter ended June 30, 2015 (the Withdrawal Exit Fee). The Withdrawal Exit Fee is payable upon redemption of the preferred shares. As of June 30, 2016, HK TMS incurred Withdrawal Exit Fees of $6.2 million. The Withdrawal Exit Fees were recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

        As part of the transaction, there are certain restrictions on the transfer of assets, including cash, to the Company from HK TMS. HK TMS is required to maintain a minimum cash balance equal to two quarterly dividend payments, of approximately $3.5 million each, plus $10.0 million, which is presented on the unaudited condensed consolidated balance sheets in "Restricted cash." Additionally, the quarterly 8% dividends paid to holders of the HK TMS preferred shares have priority over other cash distributions. No dividends are permitted to be paid to the Company from HK TMS prior to December 31, 2016. HK TMS is restricted from transferring more than 20% of its maximum net acres and from transferring any assets exceeding 20% of HK TMS's proved reserves at any one time without approval from the Company and Apollo. Finally, proceeds from any such transfers of acres or other assets must be used for HK TMS's capital or operating expenditures, or to redeem preferred shares.

        The following table sets forth a reconciliation of the changes in fair value of the embedded derivative associated with the amended transaction, which is classified as Level 3 in the fair value hierarchy (in thousands):

	Embedded derivative
Balance at December 31, 2015	$	6,100
Change in fair value		3,020
Balance at June 30, 2016	$	9,120

        The Company recorded the following activity related to the preferred shares recorded in"Mezzanine equity"on the unaudited condensed consolidated balance sheets for the period presented (in thousands, except share amounts):

	Redeemable noncontrolling interest
	Shares		Amount
Balances at December 31, 2015		165,639	$	183,986
Dividends paid in-kind		6,655		6,655
Accretion of redeemable noncontrolling interest		—		21,862
Balances at June 30, 2016		172,294	$	212,503

        For the six months ended June 30, 2016 and 2015, HK TMS issued 6,655 and 6,131 additional preferred shares to Apollo for dividends paid-in-kind, respectively. These dividends are presented within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. Upon the election of in-kind dividends, HK TMS must pay a fee of $5.00 per preferred share then outstanding (PIK Exit Fee). Such fees will be due upon redemption of the preferred shares. As of June 30, 2016, HK TMS incurred PIK Exit Fees totaling $5.6 million, which were recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

        HK TMS was not included in the chapter 11 filings or the Restructuring Support Agreement discussed in Note 1, "Financial Statement Presentation" and Note 2, "Restructuring Support Agreement," respectively.

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STOCKHOLDERS' EQUITY

6 Months Ended

Jun. 30, 2016

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

10. STOCKHOLDERS' EQUITY

5.75% Series A Convertible Perpetual Preferred Stock

        On June 18, 2013, the Company completed its offering of 345,000 shares of its 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred Stock) at a public offering price of $1,000 per share (the Liquidation Preference). The net proceeds to the Company were approximately $335.2 million, after deducting the underwriting discount and offering expenses. The Company used the net proceeds to repay a portion of the then outstanding borrowings under its Senior Credit Agreement.

        Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Company's Board of Directors, cumulative dividends at the rate of 5.75% per annum (the Dividend Rate) on the Liquidation Preference per share of the Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, in common stock of the Company, or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year. In January 2016, the Company announced that future quarterly dividends on the Series A Preferred Stock will be suspended due to the weakened market conditions as a result of low commodity prices. As of June 30, 2016, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $7.5 million.

        The Series A Preferred Stock has no maturity date, is not redeemable by the Company at any time, and will remain outstanding unless converted by the holders or mandatorily converted by the Company. Each share of Series A Preferred Stock is convertible, at the holder's option at any time, into approximately 32.49 shares of common stock of the Company (which is equivalent to a conversion price of approximately $30.80 per share), subject to certain adjustments. Based on the initial conversion rate and Series A Preferred Stock outstanding, approximately 11.2 million shares of common stock of the Company are issuable upon conversion of all the shares of Series A Preferred Stock. On or after June 6, 2018, the Company may, at its option, give notice of its election to cause all outstanding shares of the Series A Preferred Stock to be automatically converted into shares of common stock of the Company at the conversion rate (as defined in the Series A Designation), if the closing sale price of the Company's common stock equals or exceeds 150% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days. As of June 30, 2016, 122,546 shares of Series A Preferred Stock have been converted into approximately 4.0 million shares of common stock and 222,454 shares of Series A Preferred Stock remained outstanding.

        If the Company undergoes certain fundamental changes, including failure of the Company's common stock to be listed on the NYSE, NASDAQ Global Select or NASDAQ Global Market, and a holder converts its shares of the Series A Preferred Stock at any time beginning at the opening of business on the trading day immediately following the effective date of such fundamental change and ending at the close of business on the 30th trading day immediately following such effective date, the holder will receive, for each share of the Series A Preferred Stock surrendered for conversion, a number of shares of common stock of the Company equal to the greater of: (1) the sum of (i) the conversion rate and (ii) the make-whole premium, if any, as described in the Series A Designation; and (2) the conversion rate which will be increased to equal (i) the sum of the $1,000 liquidation preference plus all accumulated and unpaid dividends to, but excluding, the settlement date for such conversion, divided by (ii) the average of the closing sale prices of the Company's common stock for the five consecutive trading days ending on the third business day prior to such settlement date; provided that the prevailing conversion rate as adjusted pursuant to this will not exceed 58.48 shares of common stock of the Company per share of the Series A Preferred Stock (subject to adjustment in the same manner as the conversion rate).

        Except as required by Delaware law, holders of the Series A Preferred Stock will have no voting rights unless dividends are in arrears and unpaid for six or more quarterly periods. Until such arrearage is paid in full, the holders (voting as a single class with the holders of any other preferred shares having similar voting rights) will be entitled to elect two additional directors and the number of directors on the Company's board of directors will increase by that same number.

Common Stock

        On December 28, 2015, the Company completed a one-for-five reverse stock split. Retroactive application of the reverse stock split is required and all share and per share information included for all periods presented in these unaudited condensed consolidating financial statements reflects the reverse stock split.

        On March 18, 2015, the Company entered into an Equity Distribution Agreement (the Equity Distribution Agreement) with BMO Capital Markets Corp., Jefferies LLC and MLV & Co. LLC (collectively, the Managers), pursuant to which, during 2015, the Company publicly sold approximately 1.9 million shares for net proceeds of approximately $15.0 million, after deducting offering expenses. The shares sold were registered under the Securities Act pursuant to a Registration Statement on Form S-3 (No. 333-188640), which was filed with the SEC and became effective March 13, 2015. The Company used the net proceeds from the offering to repay a portion of outstanding borrowings under its Senior Credit Agreement and for general corporate purposes.

        On May 22, 2014, with stockholder approval, the Company filed a Certificate of Amendment to its Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to increase its authorized common stock by approximately 670.0 million shares for a total of 1.34 billion authorized shares of common stock.

Warrants

        In February 2012, in conjunction with the issuance of the Convertible Note, the Company issued warrants to purchase 7.3 million shares of the Company's common stock at an exercise price of $22.50 per share of common stock, which the Company refers to as the February 2012 Warrants. The Company allocated $43.6 million to the February 2012 Warrants which is reflected in additional paid-in capital in stockholders' equity, net of $0.6 million in issuance costs. The February 2012 Warrants entitled the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

        On March 9, 2015, in conjunction with the HALRES Note Amendment, the Company entered into an amendment to the February 2012 Warrants, the Warrant Amendment, which extended the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusted the exercise price from $22.50 to $12.20 per share. The HALRES Note Amendment and the Warrant Amendment (the Amendments) were approved by the Company's stockholders on May 6, 2015, in accordance with the rules of the New York Stock Exchange. See Note 4, "Debt," for further discussion of the Amendments.

Incentive Plan

        On May 8, 2006, the Company's stockholders first approved the 2006 Long-Term Incentive Plan (the Plan). On May 6, 2015, the Company's stockholders last approved an increase in authorized shares under the Plan from 8.3 million to 16.3 million. As of June 30, 2016 and December 31, 2015, a maximum of 7.4 million and 6.3 million shares of common stock, respectively, remained reserved for issuance under the Plan.

        The Company accounts for share-based payment accruals under authoritative guidance on stock compensation, as set forth in ASC 718. The guidance requires all share-based payments to employees and directors, including grants of performance units, stock options, and restricted stock, to be recognized in the financial statements based on their fair values.

        For the three and six months ended June 30, 2016, the Company recognized $1.5 million and $3.7 million, respectively, of share-based compensation expense. For the three and six months ended June 30, 2015, the Company recognized $3.4 million and $8.2 million, respectively, of share-based compensation expense. These were recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

Performance Share Units

        As of June 30, 2016 and 2015, the Company had outstanding performance share units (PSU) under the Plan covering 0.3 million shares of common stock, respectively, granted to senior management of the Company in 2014. The PSU provides that the number of shares of common stock received upon vesting will vary if the market price of the Company's common stock exceeds certain pre-established target thresholds as measured by the average of the adjusted closing price of a share of the Company's common stock during the sixty trading days preceding the third anniversary of issuance, or the measurement date. The PSU utilizes $20.00 as the floor price, below which the PSU will not vest and will expire. If the average market price at the measurement date is equal to $20.00, the PSU will vest and represent the right to receive 50% of the number of shares of common stock underlying the PSU. At $35.00, the PSU will vest and represent the right to receive the full number of shares of common stock underlying the PSU; and at $50.00, the PSU will vest and represent the right to receive 200% of the number of shares of common stock underlying the PSU. All stock price targets are subject to customary adjustments based upon changes in the Company's capital structure. In the event the average market price falls between targeted price thresholds, the PSU will represent the right to receive a proportionate number of shares. The Company has reserved for issuance under the Plan the maximum number of shares that participants might have the right to receive upon vesting of the PSU, or 0.6 million shares of common stock.

        At June 30, 2016, the Company had $1.1 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 0.7 years. At June 30, 2015, the Company had $2.7 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 1.7 years.

Stock Options

        At June 30, 2016, the Company had $2.8 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.2 years.

        During the six months ended June 30, 2015, the Company granted stock options under the Plan covering 0.7 million shares of common stock to employees of the Company. These stock options have exercise prices ranging from $7.85 to $9.85 with a weighted average exercise price of $9.60. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. At June 30, 2015, the Company had $9.0 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.3 years.

Restricted Stock

        At June 30, 2016, the Company had $5.2 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

        During the six months ended June 30, 2015, the Company granted 0.5 million shares of restricted stock under the Plan to non-employee directors and employees of the Company. These restricted shares were granted at prices ranging from $6.10 to $9.85 with a weighted average price of $8.70. Employee shares vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six-months from the date of grant. At June 30, 2015, the Company had $13.4 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

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EARNINGS PER COMMON SHARE

6 Months Ended

Jun. 30, 2016

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE

11. EARNINGS PER COMMON SHARE

        The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Basic:
Net income (loss) available to common stockholders	$	(382,353	)	$	(1,104,581	)	$	(949,215	)	$	(1,705,774	)
Weighted average basic number of common shares outstanding		120,708			109,063			120,360			96,569
Basic net income (loss) per share of common stock	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)
Diluted:
Net income (loss) available to common stockholders	$	(382,353	)	$	(1,104,581	)	$	(949,215	)	$	(1,705,774	)
Weighted average basic number of common shares outstanding		120,708			109,063			120,360			96,569
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of performance units		—			—			—			—
Conversion of Convertible Note		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Conversion of Series A Preferred Stock		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Weighted average diluted number of common shares outstanding		120,708			109,063			120,360			96,569
Diluted net income (loss) per share of common stock	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)

        Common stock equivalents, including stock options, warrants, restricted shares, convertible debt and preferred stock totaling 44.6 million and 45.2 million shares for the three and six months ended June 30, 2016 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses. Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock totaling 48.3 million and 48.2 million shares for the three and six months ended June 30, 2015 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

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ADDITIONAL FINANCIAL STATEMENT INFORMATION

6 Months Ended

Jun. 30, 2016

ADDITIONAL FINANCIAL STATEMENT INFORMATION

ADDITIONAL FINANCIAL STATEMENT INFORMATION

12. ADDITIONAL FINANCIAL STATEMENT INFORMATION

        Certain balance sheet amounts are comprised of the following:

	June 30, 2016		December 31, 2015
	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	55,250	$	55,129
Joint interest accounts		32,685		67,626
Accrued settlements on derivative contracts		23,072		47,011
Affiliated partnership		123		176
Other		1,725		3,682
	$	112,855	$	173,624
Prepaids and other:
Prepaids	$	8,643	$	4,585
Other		51		50
	$	8,694	$	4,635
Accounts payable and accrued liabilities:
Trade payables	$	23,357	$	47,261
Accrued oil and natural gas capital costs		25,356		54,651
Revenues and royalties payable		56,296		64,002
Accrued interest expense		105,782		88,499
Accrued employee compensation		4,954		2,829
Accrued lease operating expenses		16,435		20,036
Drilling advances from partners		223		7,964
Income taxes payable		9,172		9,172
Affiliated partnership		241		365
Other		373		306
	$	242,189	$	295,085

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION

6 Months Ended

Jun. 30, 2016

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

        The Company's obligations under its Senior Credit Agreement, 2020 Second Lien Notes, 2022 Second Lien Notes, Third Lien Notes and senior unsecured notes are fully and unconditionally guaranteed, jointly and severally, by all of the Company's existing 100% owned subsidiaries, other than HK TMS. See Note 4, "Debt," for information regarding the Company's Senior Credit Agreement, 2020 Second Lien Notes, 2022 Second Lien Notes, Third Lien Notes and senior unsecured notes. On June 16, 2014, the Company contributed its TMS undeveloped acreage located in Mississippi and Louisiana to HK TMS. See Note 9, "Mezzanine Equity," for a discussion of the restrictions on the transfer of assets between the Company and HK TMS.

        The following condensed consolidating balance sheets, condensed consolidating statements of operations, and condensed consolidating statements of cash flows for the parent company, subsidiary guarantors on a combined basis, the non-guarantor subsidiary, the consolidating adjustments and the total consolidated amounts are presented as of June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015. Investments in the subsidiaries are accounted for under the equity method. Such condensed consolidating financial information may not necessarily be indicative of the financial position, results of operations or cash flows had these subsidiaries operated as independent entities.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

	Three Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	96,995		$	2,100		$	—		$	99,095
Natural gas		—			3,159			—			—			3,159
Natural gas liquids		—			3,504			—			—			3,504
Total oil, natural gas and natural gas liquids sales		—			103,658			2,100			—			105,758
Other		—			388			1			—			389
Total operating revenues		—			104,046			2,101			—			106,147
Operating expenses:
Production:
Lease operating		—			16,667			314			—			16,981
Workover and other		—			7,896			19			—			7,915
Taxes other than income		—			9,565			188			—			9,753
Gathering and other		—			10,516			3			—			10,519
Restructuring		—			189			—			—			189
General and administrative		20,243			4,453			237			(225	)		24,708
Depletion, depreciation and accretion		367			38,397			1,188			(281	)		39,671
Full cost ceiling impairment		—			250,753			6,835			281			257,869
Total operating expenses		20,610			338,436			8,784			(225	)		367,605
Income (loss) from operations		(20,610	)		(234,390	)		(6,683	)		225			(261,458	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(54,523	)		—			—			(54,523	)
Interest expense and other, net		(77,069	)		20,786			(2,039	)		—			(58,322	)
Total other income (expenses)		(77,069	)		(33,737	)		(2,039	)		—			(112,845	)
Income (loss) before income taxes		(97,679	)		(268,127	)		(8,722	)		225			(374,303	)
Income tax benefit (provision)		—			—			—			—			—
Equity in earnings of subsidiary, net of tax		(281,476	)		(13,349	)		—			294,825			—
Net income (loss)		(379,155	)		(281,476	)		(8,722	)		295,050			(374,303	)
Series A preferred dividends		(3,198	)		—			—			—			(3,198	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(4,852	)		—			(4,852	)
Net income (loss) available to common stockholders	$	(382,353	)	$	(281,476	)	$	(13,574	)	$	295,050		$	(382,353	)

	Three Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	153,792		$	4,318		$	—		$	158,110
Natural gas		—			5,578			—			—			5,578
Natural gas liquids		—			3,889			—			—			3,889
Total oil, natural gas and natural gas liquids sales		—			163,259			4,318			—			167,577
Other		—			447			—			—			447
Total operating revenues		—			163,706			4,318			—			168,024
Operating expenses:
Production:
Lease operating		—			24,595			638			—			25,233
Workover and other		—			3,731			—			—			3,731
Taxes other than income		—			12,614			289			—			12,903
Gathering and other		—			7,746			—			—			7,746
Restructuring		—			309			—			—			309
General and administrative		15,097			7,519			723			(677	)		22,662
Depletion, depreciation and accretion		568			97,572			4,386			(1,332	)		101,194
Full cost ceiling impairment		—			911,496			35,805			1,332			948,633
Total operating expenses		15,665			1,065,582			41,841			(677	)		1,122,411
Income (loss) from operations		(15,665	)		(901,876	)		(37,523	)		677			(954,387	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(87,564	)		—			—			(87,564	)
Interest expense and other, net		(85,042	)		24,734			(614	)		—			(60,922	)
Gain (loss) on extinguishment of debt		22,766			—			—			—			22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			—			—			(8,219	)
Total other income (expenses)		(70,495	)		(62,830	)		(614	)		—			(133,939	)
Income (loss) before income taxes		(86,160	)		(964,706	)		(38,137	)		677			(1,088,326	)
Income tax benefit (provision)		—			(285	)		—			(1	)		(286	)
Equity in earnings of subsidiary, net of tax		(1,013,519	)		(48,528	)		—			1,062,047			—
Net income (loss)		(1,099,679	)		(1,013,519	)		(38,137	)		1,062,723			(1,088,612	)
Series A preferred dividends		(4,902	)		—			—			—			(4,902	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(11,067	)		—			(11,067	)
Net income (loss) available to common stockholders	$	(1,104,581	)	$	(1,013,519	)	$	(49,204	)	$	1,062,723		$	(1,104,581	)

	Six Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	170,445		$	3,617		$	—		$	174,062
Natural gas		—			6,901			—			—			6,901
Natural gas liquids		—			5,441			—			—			5,441
Total oil, natural gas and natural gas liquids sales		—			182,787			3,617			—			186,404
Other		—			1,091			1			—			1,092
Total operating revenues		—			183,878			3,618			—			187,496
Operating expenses:
Production:
Lease operating		—			36,799			760			—			37,559
Workover and other		—			15,692			14			—			15,706
Taxes other than income		—			16,791			220			—			17,011
Gathering and other		—			21,899			4			—			21,903
Restructuring		—			5,073			—			—			5,073
General and administrative		55,840			10,406			528			(450	)		66,324
Depletion, depreciation and accretion		769			90,528			5,414			(1,774	)		94,937
Full cost ceiling impairment		—			670,828			82,167			1,774			754,769
Other operating property and equipment impairment		—			28,056			—			—			28,056
Total operating expenses		56,609			896,072			89,107			(450	)		1,041,338
Income (loss) from operations		(56,609	)		(712,194	)		(85,489	)		450			(853,842	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(35,781	)		—			—			(35,781	)
Interest expense and other, net		(155,863	)		52,753			(3,003	)		—			(106,113	)
Gain (loss) on extinguishment of debt		81,434			—			—			—			81,434
Total other income (expenses)		(74,429	)		16,972			(3,003	)		—			(60,460	)
Income (loss) before income taxes		(131,038	)		(695,222	)		(88,492	)		450			(914,302	)
Income tax benefit (provision)		—			—			—			—			—
Equity in earnings of subsidiary, net of tax		(811,781	)		(116,559	)		—			928,340			—
Net income (loss)		(942,819	)		(811,781	)		(88,492	)		928,790			(914,302	)
Series A preferred dividends		(6,396	)		—			—			—			(6,396	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(28,517	)		—			(28,517	)
Net income (loss) available to common stockholders	$	(949,215	)	$	(811,781	)	$	(117,009	)	$	928,790		$	(949,215	)

	Six Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	272,997		$	9,526		$	—		$	282,523
Natural gas		—			12,537			—			—			12,537
Natural gas liquids		—			7,957			—			—			7,957
Total oil, natural gas and natural gas liquids sales		—			293,491			9,526			—			303,017
Other		—			1,201			—			—			1,201
Total operating revenues		—			294,692			9,526			—			304,218
Operating expenses:
Production:
Lease operating		—			57,930			1,088			—			59,018
Workover and other		—			6,841			4			—			6,845
Taxes other than income		—			24,596			548			—			25,144
Gathering and other		—			21,492			—			—			21,492
Restructuring		—			2,230			—			—			2,230
General and administrative		30,352			16,637			1,435			(1,353	)		47,071
Depletion, depreciation and accretion		1,192			212,198			9,770			(2,822	)		220,338
Full cost ceiling impairment		—			1,451,630			48,184			2,822			1,502,636
Total operating expenses		31,544			1,793,554			61,029			(1,353	)		1,884,774
Income (loss) from operations		(31,544	)		(1,498,862	)		(51,503	)		1,353			(1,580,556	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			12,184			—			—			12,184
Interest expense and other, net		(168,760	)		49,566			(3,034	)		(1	)		(122,229	)
Gain (loss) on extinguishment of debt		22,766			—			—			—			22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			—			—			(8,219	)
Total other income (expenses)		(154,213	)		61,750			(3,034	)		(1	)		(95,498	)
Income (loss) before income taxes		(185,757	)		(1,437,112	)		(54,537	)		1,352			(1,676,054	)
Income tax benefit (provision)		—			(6,121	)		—			5,922			(199	)
Equity in earnings of subsidiary, net of tax		(1,510,214	)		(66,981	)		—			1,577,195			—
Net income (loss)		(1,695,971	)		(1,510,214	)		(54,537	)		1,584,469			(1,676,253	)
Series A preferred dividends		(9,803	)		—			—			—			(9,803	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(19,718	)		—			(19,718	)
Net income (loss) available to common stockholders	$	(1,705,774	)	$	(1,510,214	)	$	(74,255	)	$	1,584,469		$	(1,705,774	)

CONDENSED CONSOLIDATING BALANCE SHEETS

	June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	104		$	7,069		$	—		$	7,173
Accounts receivable		—			111,219			2,401			(765	)		112,855
Receivables from derivative contracts		—			135,455			—			—			135,455
Restricted cash		165			—			16,999			—			17,164
Inventory		—			1,498			—			—			1,498
Debt issuance costs, net		5,557			—			—			—			5,557
Prepaids and other		4,006			4,688			—			—			8,694
Total current assets		9,728			252,964			26,469			(765	)		288,396
Oil and natural gas properties (full cost method):
Evaluated		—			7,172,496			511,771			(4,350	)		7,679,917
Unevaluated		—			1,180,148			—			—			1,180,148
Gross oil and natural gas properties		—			8,352,644			511,771			(4,350	)		8,860,065
Less—accumulated depletion		—			(6,285,845	)		(497,621	)		4,350			(6,779,116	)
Net oil and natural gas properties		—			2,066,799			14,150			—			2,080,949
Other operating property and equipment:
Gas gathering and other operating assets		12,473			87,707			175			—			100,355
Less—accumulated depreciation		(9,475	)		(13,604	)		(76	)		—			(23,155	)
Net other operating property and equipment		2,998			74,103			99			—			77,200
Other noncurrent assets:
Receivables from derivative contracts		—			5,642			—			—			5,642
Intercompany notes and accounts receivable		4,642,675			367,525			—			(5,010,200	)		—
Equity in oil and natural gas partnership		—			11			—			—			11
Funds in escrow and other		515			1,098			—			—			1,613
Total assets	$	4,655,916		$	2,768,142		$	40,718		$	(5,010,965	)	$	2,453,811
Current liabilities:
Accounts payable and accrued liabilities	$	—		$	275,141		$	2,269		$	(35,221	)	$	242,189
Asset retirement obligations		—			412			—			—			412
Current portion of long-term debt, net		2,825,807			—			—			—			2,825,807
Total current liabilities		2,825,807			275,553			2,269			(35,221	)		3,068,408
Other noncurrent liabilities:
Liabilities from derivative contracts		—			194			—			—			194
Asset retirement obligations		—			47,274			1,280			—			48,554
Deferred income taxes		1,848			(1,848	)		—			—			—
Intercompany notes and accounts payable		367,525			4,642,675			—			(5,010,200	)		—
Investment in subsidiary		2,345,867			149,999			—			(2,495,866	)		—
Other		—			162			9,121			—			9,283
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			212,503			—			212,503
Stockholders' equity (deficit):
Preferred stock		—			—			—			—			—
Common stock		12			—			—			—			12
Additional paid-in capital		3,288,371			—			403,678			(403,678	)		3,288,371
Retained earnings (accumulated deficit)		(4,173,514	)		(2,345,867	)		(588,133	)		2,934,000			(4,173,514	)
Total stockholders' equity (deficit)		(885,131	)		(2,345,867	)		(184,455	)		2,530,322			(885,131	)
Total liabilities and stockholders' equity (deficit)	$	4,655,916		$	2,768,142		$	40,718		$	(5,010,965	)	$	2,453,811

	December 31, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	100		$	7,926		$	—		$	8,026
Accounts receivable		88			166,770			9,985			(3,219	)		173,624
Receivables from derivative contracts		—			348,861			—			—			348,861
Restricted cash		138			—			16,674			—			16,812
Inventory		—			4,554			81			—			4,635
Prepaids and other		328			4,307			—			—			4,635
Total current assets		554			524,592			34,666			(3,219	)		556,593
Oil and natural gas properties (full cost method):
Evaluated		—			6,634,426			430,645			(4,350	)		7,060,721
Unevaluated		—			1,566,705			74,651			—			1,641,356
Gross oil and natural gas properties		—			8,201,131			505,296			(4,350	)		8,702,077
Less—accumulated depletion		—			(5,527,948	)		(410,090	)		4,350			(5,933,688	)
Net oil and natural gas properties		—			2,673,183			95,206			—			2,768,389
Other operating property and equipment:
Gas gathering and other operating assets		12,474			117,441			175			—			130,090
Less—accumulated depreciation		(8,705	)		(13,676	)		(54	)		—			(22,435	)
Net other operating property and equipment		3,769			103,765			121			—			107,655
Other noncurrent assets:
Receivables from derivative contracts		—			16,614			—			—			16,614
Debt issuance costs, net		7,633			—			—			—			7,633
Intercompany notes and accounts receivable		4,749,760			302,096			—			(5,051,856	)		—
Equity in oil and natural gas partnership		—			209			—			—			209
Funds in escrow and other		517			1,082			—			—			1,599
Total assets	$	4,762,233		$	3,621,541		$	129,993		$	(5,055,075	)	$	3,458,692
Current liabilities:
Accounts payable and accrued liabilities	$	—		$	326,655		$	6,102		$	(37,672	)	$	295,085
Asset retirement obligations		—			163			—			—			163
Total current liabilities		—			326,818			6,102			(37,672	)		295,248
Long-term debt, net		2,873,637			—			—			—			2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts		—			290			—			—			290
Asset retirement obligations		—			45,602			1,251			—			46,853
Intercompany notes and accounts payable		302,096			4,749,760			—			(5,051,856	)		—
Investment in subsidiary		1,534,086			32,993			—			(1,567,079	)		—
Other		—			164			6,100			—			6,264
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			183,986			—			183,986
Stockholders' equity:
Preferred stock		—			—			—			—			—
Common stock		12			—			—			—			12
Additional paid-in capital		3,283,097			—			403,678			(403,678	)		3,283,097
Retained earnings (accumulated deficit)		(3,230,695	)		(1,534,086	)		(471,124	)		2,005,210			(3,230,695	)
Total stockholders' equity		52,414			(1,534,086	)		(67,446	)		1,601,532			52,414
Total liabilities and stockholders' equity	$	4,762,233		$	3,621,541		$	129,993		$	(5,055,075	)	$	3,458,692

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Six Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(207,084	)	$	348,223		$	1,604		$	—			142,743
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(168,122	)		(2,136	)					(170,258	)
Other operating property and equipment capital expenditures		—			(886	)		—			—			(886	)
Advances to subsidiary		178,978			—			—			(178,978	)		—
Funds held in escrow and other		—			(233	)		—			—			(233	)
Net cash provided by (used in) investing activities		178,978			(169,241	)		(2,136	)		(178,978	)		(171,377	)
Cash flows from financing activities:
Proceeds from borrowings		425,000			—			—			—			425,000
Repayments of borrowings		(395,648	)		—			—			—			(395,648	)
Debt issuance costs		(1,186	)		—			—			—			(1,186	)
Restricted cash		—			—			(325	)		—			(325	)
Proceeds from subsidiary		—			(178,978	)		—			178,978			—
Offering costs and other		(60	)		—			—			—			(60	)
Net cash provided by (used in) financing activities		28,106			(178,978	)		(325	)		178,978			27,781
Net increase (decrease) in cash		—			4			(857	)		—			(853	)
Cash at beginning of period		—			100			7,926			—			8,026
Cash at end of period	$	—		$	104		$	7,069		$	—		$	7,173

	Six Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(187,977	)	$	400,988		$	4,519		$	—		$	217,530
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(369,816	)		(37,935	)		—			(407,751	)
Other operating property and equipment capital expenditures		(457	)		(7,024	)		3			—			(7,478	)
Advances to subsidiary		27,136			—			—			(27,136	)		—
Funds held in escrow and other		—			3,012			—			—			3,012
Net cash provided by (used in) investing activities		26,679			(373,828	)		(37,932	)		(27,136	)		(412,217	)
Cash flows from financing activities:
Proceeds from borrowings		1,296,000			—			—			—			1,296,000
Repayments of borrowings		(1,129,000	)		—			—			—			(1,129,000	)
Debt issuance costs		(18,612	)		—			—			—			(18,612	)
Common stock issued		15,354			—			—			—			15,354
Restricted cash		—			—			(352	)		—			(352	)
Proceeds from subsidiary		—			(27,136	)		—			27,136			—
Offering costs and other		(2,444	)		—			1			—			(2,443	)
Net cash provided by (used in) financing activities		161,298			(27,136	)		(351	)		27,136			160,947
Net increase (decrease) in cash		—			24			(33,764	)		—			(33,740	)
Cash at beginning of period		—			15			43,698			—			43,713
Cash at end of period	$	—		$	39		$	9,934		$	—		$	9,973

XML

FINANCIAL STATEMENT PRESENTATION (Policies)

6 Months Ended

Jun. 30, 2016

FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

Basis of Presentation and Principles of Consolidation

        Halcón Resources Corporation (Halcón or the Company) is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries and an equity method investment. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. The Company's oil and natural gas properties are managed as a whole rather than through discrete operating areas. Operational information is tracked by operating area; however, financial performance is assessed as a whole. Allocation of capital is made across the Company's entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company's management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its 2015 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on February 26, 2016. Please refer to the notes in the 2015 Annual Report on Form 10-K when reviewing interim financial results.

        On December 28, 2015, the Company completed a one-for-five reverse stock split. As a result, all share and per share information included for all periods presented in these unaudited condensed consolidated financial statements reflect the reverse stock split.

Ability to Continue as a Going Concern

Ability to Continue as a Going Concern

        On July 27, 2016, the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a pre-packaged plan of reorganization. The Company expects to continue operations in the normal course during the pendency of the chapter 11 proceedings. Prior to filing the bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company's 13% senior secured notes due 2022 (the Third Lien Holders), the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of the Company's 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of the Company's 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders and together with the Third Lien Holders, Unsecured Noteholders and Convertible Noteholder, referred to collectively herein as, the Stakeholders). See Note 2,"Restructuring Support Agreement, "for more information. On June 20, 2016, the Halcón Entities commenced a solicitation for acceptance of the plan of reorganization (the Plan) contemplated in the Restructuring Support Agreement from the holders of impaired claims and interests entitled to vote under the Plan. At the conclusion of the Company's thirty day solicitation period, the Plan received sufficient votes to satisfy the voting conditions set forth in Section 1126(c) of the Bankruptcy Code. The Restructuring Support Agreement contains certain covenants on the part of the Halcón Entities and the Stakeholders, including that the Stakeholders vote in favor of the Plan contemplated in the Restructuring Support Agreement and otherwise facilitate and support the restructuring transaction, subject to the achievement of certain milestones and various conditions.

        The Company's debt agreements provide that the commencement of a voluntary proceeding in bankruptcy is an event of default leading to the automatic acceleration of the associated obligations. Accordingly, the filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code accelerated the Company's obligations under all of its outstanding debt instruments, although any efforts to enforce payment obligations thereunder have been automatically stayed by, and the creditors' rights of enforcement are subject to, the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Accordingly, the Company classified all of its outstanding debt as a current liability on its unaudited condensed consolidated balance sheet as of June 30, 2016.

        The significant risks and uncertainties related to the Halcón Entities' chapter 11 proceeding raise substantial doubt about the Company's ability to continue as a going concern. The unaudited condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Use of Estimates

Use of Estimates

        The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's unaudited condensed consolidated financial statements.

        Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

        The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. There were no material allowances for doubtful accounts as of June 30, 2016 or December 31, 2015.

Other Operating Property and Equipment

Other Operating Property and Equipment

        Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year or 10-year estimated useful life applicable to gas gathering systems and a compressed natural gas facility, respectively. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company capitalized $57.8 million and $87.2 million as of June 30, 2016 and December 31, 2015, respectively, related to the construction of its gas gathering systems, after any amounts impaired.

        Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years or the lesser of the lease term; trailers, seven years; heavy equipment, ten years; buildings, twenty years and leasehold improvements, lease term. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

        The Company reviews its gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360,Property, Plant, and Equipment(ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from an asset's undiscounted cash flows, then the Company recognizes an impairment loss for the difference between the carrying amount and the current fair value. The Company also evaluates the remaining useful lives of its gas gathering systems and other operating assets at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. For the three months ended March 31, 2016, the Company recorded a non-cash impairment charge of $28.1 million in"Other operating property and equipment impairment"in the Company's unaudited condensed consolidated statements of operations and in"Gas gathering and other operating assets"in the Company's unaudited condensed consolidated balance sheets. The impairment primarily relates to the Company's gross investments of $32.8 million in gas gathering infrastructure that will not likely be economically recoverable due to its shift in exploration, drilling and developmental plans to its most economic areas as a result of the low commodity price environment.

        In accordance with ASC 820,Fair Value Measurements and Disclosures(ASC 820), a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The estimate of the fair value of the Company's gas gathering systems was based on an income approach that estimated future cash flows associated with those assets, which resulted in negative net cash flows due to insufficient throughput of natural gas volumes and certain fixed costs necessary to operate and maintain the assets. This estimation includes the use of unobservable inputs, such as estimated future production, and gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company's gas gathering systems being classified as Level 3.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

        In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09,Compensation—Stock Compensation(ASU 2016-09). For public business entities, ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. The areas for simplification in this ASU 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. Some of the areas for simplification apply only to nonpublic entities. As there are multiple amendments in this ASU, the FASB has issued guidance on how an entity should apply each amendment, either prospectively or retrospectively. The Company is in the process of assessing the effects of the application of the new guidance.

        In March 2016, the FASB issued ASU No. 2016-06,Contingent Put and Call Options in Debt Instruments(ASU 2016-06). For public business entities, ASU 2016-06 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. ASU 2016-06 provides new guidance that simplifies the analysis of whether a contingent put or call option in a debt instrument qualifies as a separate derivative. An entity should apply the amendments in this ASU on a modified retrospective basis to existing debt instruments as of the beginning of the fiscal year for which the amendments are effective. The Company is in the process of assessing the effects of the application of the new guidance.

        In February 2016, the FASB issued ASU No. 2016-02,Leases (Topic 842)(ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and early adoption is permitted. The FASB issued ASU 2016-02 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. An entity should apply the amendments in this ASU on a modified retrospective basis. The transition will require application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the effects of the application of the new guidance.

        In November 2015, the FASB issued ASU No. 2015-17,Balance Sheet Classification of Deferred Taxes(ASU 2015-17) to simplify the presentation of deferred income taxes. Under ASU 2015-17, all deferred tax assets and liabilities, along with any related valuation allowance, are required to be classified as noncurrent on the balance sheet. Effective December 31, 2015, the Company early adopted ASU 2015-17, on a prospective basis, which resulted in the reclassification of its current deferred tax assets and liabilities as a non-current deferred tax asset and liability, net of the valuation allowance, in the accompanying unaudited condensed consolidated balance sheets. No prior periods were retrospectively adjusted.

        In September 2015, the FASB issued ASU No. 2015-16,Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments(ASU 2015-16). For public business entities, ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and early adoption is permitted. The amendments in this ASU require that an acquirer, in a business combination, recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. To simplify the accounting for adjustments made to provisional amounts recognized in a business combination, the amendments in this ASU eliminate the requirement to retrospectively account for those adjustments, and instead present separately on the face of the income statement or disclose in the footnotes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods. The adoption of ASU 2015-16 did not have an impact to the Company's financial statements or disclosures.

        In July 2015, the FASB issued ASU No. 2015-11,Simplifying the Measurement of Inventory(ASU 2015-11). ASU 2015-11 states that an entity should measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments in this update should be applied prospectively and early application is permitted. The Company does not expect the adoption of ASU 2015-11 to have a material impact to its financial statements or disclosures.

        In April 2015, the FASB issued ASU No. 2015-05,Intangibles—Goodwill and Other—Internal-Use Software(ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. For public business entities, the guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. An entity can elect to adopt the guidance either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. Early adoption is permitted. The Company adopted prospectively and it did not have a material impact to the Company's financial statements or disclosures.

        In February 2015, the FASB issued ASU No. 2015-02,Amendments to the Consolidation Analysis(ASU 2015-02). The amendments in ASU 2015-02 eliminate the previous presumption that a general partner controls a limited partner. ASU 2015-02 may impact the Company's accounting for its general partner interest in SBE Partners LP (SBE Partners), which is currently accounted for as an equity method investment. ASU 2015-02 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Entities may apply the guidance using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the first fiscal year adopted or it may apply the amendment retrospectively. The adoption of ASU 2015-02 did not have an impact on the Company's accounting for its general partner interest in SBE Partners, LP.

        In August 2014, the FASB issued ASU No. 2014-15,Presentation of Financial Statements—Going Concern(ASU 2014-15). ASU 2014-15 is effective for annual reporting periods (including interim periods within those periods) ending after December 15, 2016. Early application is permitted with companies applying the guidance prospectively. The amendments in ASU 2014-15 create a new ASC Sub-topic 205-40,Presentation of Financial Statements—Going Concernand require management to assess for each annual and interim reporting period if conditions exist that raise substantial doubt about an entity's ability to continue as a going concern. The rule requires various disclosures depending on the facts and circumstances surrounding an entity's ability to continue as a going concern. Effective June 30, 2016, the Company early adopted ASU 2014-15, on a prospective basis, which resulted in additional disclosures as discussed above.

        In May 2014, the FASB issued ASU No. 2014-09,Revenue from Contracts with Customers(ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08,Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)(ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2016, or after December 2017, if companies choose to elect the deferred adoption date approved by the FASB. Early adoption is not permitted. The Company is in the process of assessing the effects of the application of the new guidance.

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DEBT (Tables)

6 Months Ended

Jun. 30, 2016

DEBT

Schedule of current and long-term debt

	June 30, 2016(1)		December 31, 2015
	(In thousands)
Senior revolving credit facility	$	101,000	$	62,000
8.625% senior secured second lien notes due 2020(2)		689,064		687,797
12.0% senior secured second lien notes due 2022(3)		111,408		111,598
13.0% senior secured third lien notes due 2022(4)		1,010,048		1,009,585
9.25% senior notes due 2022(5)		36,660		51,887
8.875% senior notes due 2021(6)		296,184		347,671
9.75% senior notes due 2020(7)		312,522		336,470
8.0% convertible note due 2020(8)		268,921		266,629
	$	2,825,807	$	2,873,637

(1)	The Company's debt balance as of June 30, 2016 was classified as current. See "Senior Revolving Credit Facility" below for more details.
(2)	Amounts are net of $10.9 million and $12.2 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(3)	Amounts are net of $1.4 million and $1.2 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(4)	Amounts are net of $7.9 million and $8.4 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(5)	Amounts are net of $0.5 million and $0.8 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively.
(6)	Amounts are net of a $0.8 million and a $1.0 million unamortized discount at June 30, 2016 and December 31, 2015, respectively, related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $4.3 million and $5.5 million at June 30, 2016 and December 31, 2015, respectively. Amounts are net of $4.5 million and $5.8 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively. See "8.875% Senior Notes" below for more details.
(7)	Amounts are net of a $1.6 million and a $1.9 million unamortized discount at June 30, 2016 and December 31, 2015, respectively, related to the issuance of the original 2020 Notes. The unamortized premium related to the additional 2020 Notes was approximately $2.2 million and $2.6 million at June 30, 2016 and December 31, 2015, respectively. Amounts are net of $3.6 million and $4.3 million unamortized debt issuance costs at June 30, 2016 and December 31, 2015, respectively. See "9.75% Senior Notes" below for more details.
(8)	Amounts are net of a $20.7 million and a $23.0 million unamortized discount at June 30, 2016 and December 31, 2015, respectively. See "8.0% Convertible Note" below for more details.

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FAIR VALUE MEASUREMENTS (Tables)

6 Months Ended

Jun. 30, 2016

FAIR VALUE MEASUREMENTS

Schedule of fair value of the Company's financial assets and liabilities

	June 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	141,097	$	—	$	141,097
Liabilities
Liabilities from derivative contracts	$	—	$	42	$	152	$	194

	December 31, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	365,475	$	—	$	365,475
Liabilities
Liabilities from derivative contracts	$	—	$	105	$	185	$	290

Schedule of reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy

	Significant Unobservable Inputs (Level 3)
	June 30, 2016			December 31, 2015
	(In thousands)
Beginning Balance	$	(185	)	$	(1,319	)
Net gain (loss) on derivative contracts		33			1,134
Ending Balance	$	(152	)	$	(185	)
Change in unrealized gains (losses) included in earnings related to derivatives still held at June 30, 2016 and December 31, 2015	$	33		$	(185	)

Schedule of the estimated fair values of the Company's fixed interest rate, long-term debt instruments

	June 30, 2016				December 31, 2015
Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
	(In thousands)
8.625% senior secured second lien notes	$	700,000	$	659,120	$	700,000	$	479,500
12.0% senior secured second lien notes		112,826		106,237		112,826		77,286
13.0% senior secured third lien notes		1,017,970		539,524		1,017,970		333,385
9.25% senior notes		37,194		8,276		52,694		14,422
8.875% senior notes		297,193		66,125		348,944		95,506
9.75% senior notes		315,535		70,207		340,035		93,068
8.0% convertible note		289,669		69,926		289,669		87,393
	$	2,770,387	$	1,519,415	$	2,862,138	$	1,180,560

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DERIVATIVE AND HEDGING ACTIVITIES (Tables)

6 Months Ended

Jun. 30, 2016

DERIVATIVE AND HEDGING ACTIVITIES

Summary of location and fair value of derivative contracts

		Asset derivative contracts					Liability derivative contracts
Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	June 30, 2016		December 31, 2015		Balance sheet location	June 30, 2016			December 31, 2015
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	135,455	$	348,861	Current liabilities—liabilities from derivative contracts	$	—		$	—
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		5,642		16,614	Other noncurrent liabilities—liabilities from derivative contracts		(194	)		(290	)
Total derivatives not designated as hedging contracts under ASC 815		$	141,097	$	365,475		$	(194	)	$	(290	)

Summary of the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts

		Amount of gain or (loss) recognized in income on derivative contracts for the Three Months Ended June 30,						Amount of gain or (loss) recognized in income on derivative contracts for the Six Months Ended June 30,
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2016			2015			2016			2015
		(In thousands)						(In thousands)
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(135,303	)	$	(175,712	)	$	(224,281	)	$	(183,713	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		80,780			88,148			188,500			195,897
Total net gain (loss) on derivative contracts		$	(54,523	)	$	(87,564	)	$	(35,781	)	$	12,184

Schedule of open derivative contracts

			June 30, 2016
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
July 2016 - December 2016	Collars	Natural Gas		368,000	$4.00	$	4.00	$4.22	$	4.22
July 2016 - December 2016(1)(3)	Collars	Crude Oil		2,024,000	60.00 - 90.00		73.00	64.00 - 95.10		78.87
July 2016 - December 2016(2)(3)	Swaps	Crude Oil		2,392,000	62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750	50.00 - 60.00		57.33	70.00 - 76.84		74.16

			December 31, 2015
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
January 2016 - June 2016	Collars	Crude Oil		182,000	$90.00	$	90.00	$96.85	$	96.85
January 2016 - December 2016	Collars	Natural Gas		732,000	4.00		4.00	4.22		4.22
January 2016 - December 2016(1)	Collars	Crude Oil		4,392,000	60.00 - 90.00		71.91	64.00 - 95.10		77.71
January 2016 - December 2016(2)	Swaps	Crude Oil		4,758,000	62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750	50.00 - 60.00		57.33	70.00 - 76.84		74.16

(1)	Includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $60.00 per Bbl and a ceiling of $75.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2017.
(2)	Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended by the counterparty at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.
(3)	Subsequent to June 30, 2016, crude oil collars totaling 184,000 Bbls and crude oil swaps totaling 184,000 Bbls for the remainder of 2016 were terminated resulting in proceeds of $9.6 million to the Company.

Schedule of potential effects of master netting arrangements on the fair value of derivative contracts

	Derivative Assets						Derivative Liabilities
Offsetting of Derivative Assets and Liabilities	June 30, 2016			December 31, 2015			June 30, 2016			December 31, 2015
	(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	141,097		$	365,475		$	(194	)	$	(290	)
Amounts Not Offset in the Consolidated Balance Sheet		(21	)		(53	)		20			52
Net Amount	$	141,076		$	365,422		$	(174	)	$	(238	)

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ASSET RETIREMENT OBLIGATIONS (Tables)

6 Months Ended

Jun. 30, 2016

ASSET RETIREMENT OBLIGATIONS

Schedule of activity related to ARO liability

        The Company recorded the following activity related to its ARO liability for the six months ended June 30, 2016 (in thousands, inclusive of the current portion):

Liability for asset retirement obligations as of December 31, 2015	$	47,016
Liabilities settled and divested		(180	)
Additions		1,024
Acquisitions		75
Accretion expense		1,031
Liability for asset retirement obligations as of June 30, 2016	$	48,966

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MEZZANINE EQUITY (Tables)

6 Months Ended

Jun. 30, 2016

MEZZANINE EQUITY

Reconciliation of financial assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3)

        The following table sets forth a reconciliation of the changes in fair value of the embedded derivative associated with the amended transaction, which is classified as Level 3 in the fair value hierarchy (in thousands):

	Embedded derivative
Balance at December 31, 2015	$	6,100
Change in fair value		3,020
Balance at June 30, 2016	$	9,120

Schedule of activity related to the preferred shares recorded as mezzanine equity

        The Company recorded the following activity related to the preferred shares recorded in"Mezzanine equity"on the unaudited condensed consolidated balance sheets for the period presented (in thousands, except share amounts):

	Redeemable noncontrolling interest
	Shares		Amount
Balances at December 31, 2015		165,639	$	183,986
Dividends paid in-kind		6,655		6,655
Accretion of redeemable noncontrolling interest		—		21,862
Balances at June 30, 2016		172,294	$	212,503

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EARNINGS PER COMMON SHARE (Tables)

6 Months Ended

Jun. 30, 2016

EARNINGS PER COMMON SHARE

Schedule of calculation of earnings (loss) per share

        The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Basic:
Net income (loss) available to common stockholders	$	(382,353	)	$	(1,104,581	)	$	(949,215	)	$	(1,705,774	)
Weighted average basic number of common shares outstanding		120,708			109,063			120,360			96,569
Basic net income (loss) per share of common stock	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)
Diluted:
Net income (loss) available to common stockholders	$	(382,353	)	$	(1,104,581	)	$	(949,215	)	$	(1,705,774	)
Weighted average basic number of common shares outstanding		120,708			109,063			120,360			96,569
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of performance units		—			—			—			—
Conversion of Convertible Note		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Conversion of Series A Preferred Stock		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Weighted average diluted number of common shares outstanding		120,708			109,063			120,360			96,569
Diluted net income (loss) per share of common stock	$	(3.17	)	$	(10.13	)	$	(7.89	)	$	(17.66	)

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ADDITIONAL FINANCIAL STATEMENT INFORMATION (Tables)

6 Months Ended

Jun. 30, 2016

ADDITIONAL FINANCIAL STATEMENT INFORMATION

Schedule of additional financial statement information, balance sheet

	June 30, 2016		December 31, 2015
	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	55,250	$	55,129
Joint interest accounts		32,685		67,626
Accrued settlements on derivative contracts		23,072		47,011
Affiliated partnership		123		176
Other		1,725		3,682
	$	112,855	$	173,624
Prepaids and other:
Prepaids	$	8,643	$	4,585
Other		51		50
	$	8,694	$	4,635
Accounts payable and accrued liabilities:
Trade payables	$	23,357	$	47,261
Accrued oil and natural gas capital costs		25,356		54,651
Revenues and royalties payable		56,296		64,002
Accrued interest expense		105,782		88,499
Accrued employee compensation		4,954		2,829
Accrued lease operating expenses		16,435		20,036
Drilling advances from partners		223		7,964
Income taxes payable		9,172		9,172
Affiliated partnership		241		365
Other		373		306
	$	242,189	$	295,085

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Tables)

6 Months Ended

Jun. 30, 2016

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Results of operations

	Three Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	96,995		$	2,100		$	—		$	99,095
Natural gas		—			3,159			—			—			3,159
Natural gas liquids		—			3,504			—			—			3,504
Total oil, natural gas and natural gas liquids sales		—			103,658			2,100			—			105,758
Other		—			388			1			—			389
Total operating revenues		—			104,046			2,101			—			106,147
Operating expenses:
Production:
Lease operating		—			16,667			314			—			16,981
Workover and other		—			7,896			19			—			7,915
Taxes other than income		—			9,565			188			—			9,753
Gathering and other		—			10,516			3			—			10,519
Restructuring		—			189			—			—			189
General and administrative		20,243			4,453			237			(225	)		24,708
Depletion, depreciation and accretion		367			38,397			1,188			(281	)		39,671
Full cost ceiling impairment		—			250,753			6,835			281			257,869
Total operating expenses		20,610			338,436			8,784			(225	)		367,605
Income (loss) from operations		(20,610	)		(234,390	)		(6,683	)		225			(261,458	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(54,523	)		—			—			(54,523	)
Interest expense and other, net		(77,069	)		20,786			(2,039	)		—			(58,322	)
Total other income (expenses)		(77,069	)		(33,737	)		(2,039	)		—			(112,845	)
Income (loss) before income taxes		(97,679	)		(268,127	)		(8,722	)		225			(374,303	)
Income tax benefit (provision)		—			—			—			—			—
Equity in earnings of subsidiary, net of tax		(281,476	)		(13,349	)		—			294,825			—
Net income (loss)		(379,155	)		(281,476	)		(8,722	)		295,050			(374,303	)
Series A preferred dividends		(3,198	)		—			—			—			(3,198	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(4,852	)		—			(4,852	)
Net income (loss) available to common stockholders	$	(382,353	)	$	(281,476	)	$	(13,574	)	$	295,050		$	(382,353	)

	Three Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	153,792		$	4,318		$	—		$	158,110
Natural gas		—			5,578			—			—			5,578
Natural gas liquids		—			3,889			—			—			3,889
Total oil, natural gas and natural gas liquids sales		—			163,259			4,318			—			167,577
Other		—			447			—			—			447
Total operating revenues		—			163,706			4,318			—			168,024
Operating expenses:
Production:
Lease operating		—			24,595			638			—			25,233
Workover and other		—			3,731			—			—			3,731
Taxes other than income		—			12,614			289			—			12,903
Gathering and other		—			7,746			—			—			7,746
Restructuring		—			309			—			—			309
General and administrative		15,097			7,519			723			(677	)		22,662
Depletion, depreciation and accretion		568			97,572			4,386			(1,332	)		101,194
Full cost ceiling impairment		—			911,496			35,805			1,332			948,633
Total operating expenses		15,665			1,065,582			41,841			(677	)		1,122,411
Income (loss) from operations		(15,665	)		(901,876	)		(37,523	)		677			(954,387	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(87,564	)		—			—			(87,564	)
Interest expense and other, net		(85,042	)		24,734			(614	)		—			(60,922	)
Gain (loss) on extinguishment of debt		22,766			—			—			—			22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			—			—			(8,219	)
Total other income (expenses)		(70,495	)		(62,830	)		(614	)		—			(133,939	)
Income (loss) before income taxes		(86,160	)		(964,706	)		(38,137	)		677			(1,088,326	)
Income tax benefit (provision)		—			(285	)		—			(1	)		(286	)
Equity in earnings of subsidiary, net of tax		(1,013,519	)		(48,528	)		—			1,062,047			—
Net income (loss)		(1,099,679	)		(1,013,519	)		(38,137	)		1,062,723			(1,088,612	)
Series A preferred dividends		(4,902	)		—			—			—			(4,902	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(11,067	)		—			(11,067	)
Net income (loss) available to common stockholders	$	(1,104,581	)	$	(1,013,519	)	$	(49,204	)	$	1,062,723		$	(1,104,581	)

	Six Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	170,445		$	3,617		$	—		$	174,062
Natural gas		—			6,901			—			—			6,901
Natural gas liquids		—			5,441			—			—			5,441
Total oil, natural gas and natural gas liquids sales		—			182,787			3,617			—			186,404
Other		—			1,091			1			—			1,092
Total operating revenues		—			183,878			3,618			—			187,496
Operating expenses:
Production:
Lease operating		—			36,799			760			—			37,559
Workover and other		—			15,692			14			—			15,706
Taxes other than income		—			16,791			220			—			17,011
Gathering and other		—			21,899			4			—			21,903
Restructuring		—			5,073			—			—			5,073
General and administrative		55,840			10,406			528			(450	)		66,324
Depletion, depreciation and accretion		769			90,528			5,414			(1,774	)		94,937
Full cost ceiling impairment		—			670,828			82,167			1,774			754,769
Other operating property and equipment impairment		—			28,056			—			—			28,056
Total operating expenses		56,609			896,072			89,107			(450	)		1,041,338
Income (loss) from operations		(56,609	)		(712,194	)		(85,489	)		450			(853,842	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			(35,781	)		—			—			(35,781	)
Interest expense and other, net		(155,863	)		52,753			(3,003	)		—			(106,113	)
Gain (loss) on extinguishment of debt		81,434			—			—			—			81,434
Total other income (expenses)		(74,429	)		16,972			(3,003	)		—			(60,460	)
Income (loss) before income taxes		(131,038	)		(695,222	)		(88,492	)		450			(914,302	)
Income tax benefit (provision)		—			—			—			—			—
Equity in earnings of subsidiary, net of tax		(811,781	)		(116,559	)		—			928,340			—
Net income (loss)		(942,819	)		(811,781	)		(88,492	)		928,790			(914,302	)
Series A preferred dividends		(6,396	)		—			—			—			(6,396	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(28,517	)		—			(28,517	)
Net income (loss) available to common stockholders	$	(949,215	)	$	(811,781	)	$	(117,009	)	$	928,790		$	(949,215	)

	Six Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	272,997		$	9,526		$	—		$	282,523
Natural gas		—			12,537			—			—			12,537
Natural gas liquids		—			7,957			—			—			7,957
Total oil, natural gas and natural gas liquids sales		—			293,491			9,526			—			303,017
Other		—			1,201			—			—			1,201
Total operating revenues		—			294,692			9,526			—			304,218
Operating expenses:
Production:
Lease operating		—			57,930			1,088			—			59,018
Workover and other		—			6,841			4			—			6,845
Taxes other than income		—			24,596			548			—			25,144
Gathering and other		—			21,492			—			—			21,492
Restructuring		—			2,230			—			—			2,230
General and administrative		30,352			16,637			1,435			(1,353	)		47,071
Depletion, depreciation and accretion		1,192			212,198			9,770			(2,822	)		220,338
Full cost ceiling impairment		—			1,451,630			48,184			2,822			1,502,636
Total operating expenses		31,544			1,793,554			61,029			(1,353	)		1,884,774
Income (loss) from operations		(31,544	)		(1,498,862	)		(51,503	)		1,353			(1,580,556	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			12,184			—			—			12,184
Interest expense and other, net		(168,760	)		49,566			(3,034	)		(1	)		(122,229	)
Gain (loss) on extinguishment of debt		22,766			—			—			—			22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		(8,219	)		—			—			—			(8,219	)
Total other income (expenses)		(154,213	)		61,750			(3,034	)		(1	)		(95,498	)
Income (loss) before income taxes		(185,757	)		(1,437,112	)		(54,537	)		1,352			(1,676,054	)
Income tax benefit (provision)		—			(6,121	)		—			5,922			(199	)
Equity in earnings of subsidiary, net of tax		(1,510,214	)		(66,981	)		—			1,577,195			—
Net income (loss)		(1,695,971	)		(1,510,214	)		(54,537	)		1,584,469			(1,676,253	)
Series A preferred dividends		(9,803	)		—			—			—			(9,803	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(19,718	)		—			(19,718	)
Net income (loss) available to common stockholders	$	(1,705,774	)	$	(1,510,214	)	$	(74,255	)	$	1,584,469		$	(1,705,774	)

Balance sheet

	June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	104		$	7,069		$	—		$	7,173
Accounts receivable		—			111,219			2,401			(765	)		112,855
Receivables from derivative contracts		—			135,455			—			—			135,455
Restricted cash		165			—			16,999			—			17,164
Inventory		—			1,498			—			—			1,498
Debt issuance costs, net		5,557			—			—			—			5,557
Prepaids and other		4,006			4,688			—			—			8,694
Total current assets		9,728			252,964			26,469			(765	)		288,396
Oil and natural gas properties (full cost method):
Evaluated		—			7,172,496			511,771			(4,350	)		7,679,917
Unevaluated		—			1,180,148			—			—			1,180,148
Gross oil and natural gas properties		—			8,352,644			511,771			(4,350	)		8,860,065
Less—accumulated depletion		—			(6,285,845	)		(497,621	)		4,350			(6,779,116	)
Net oil and natural gas properties		—			2,066,799			14,150			—			2,080,949
Other operating property and equipment:
Gas gathering and other operating assets		12,473			87,707			175			—			100,355
Less—accumulated depreciation		(9,475	)		(13,604	)		(76	)		—			(23,155	)
Net other operating property and equipment		2,998			74,103			99			—			77,200
Other noncurrent assets:
Receivables from derivative contracts		—			5,642			—			—			5,642
Intercompany notes and accounts receivable		4,642,675			367,525			—			(5,010,200	)		—
Equity in oil and natural gas partnership		—			11			—			—			11
Funds in escrow and other		515			1,098			—			—			1,613
Total assets	$	4,655,916		$	2,768,142		$	40,718		$	(5,010,965	)	$	2,453,811
Current liabilities:
Accounts payable and accrued liabilities	$	—		$	275,141		$	2,269		$	(35,221	)	$	242,189
Asset retirement obligations		—			412			—			—			412
Current portion of long-term debt, net		2,825,807			—			—			—			2,825,807
Total current liabilities		2,825,807			275,553			2,269			(35,221	)		3,068,408
Other noncurrent liabilities:
Liabilities from derivative contracts		—			194			—			—			194
Asset retirement obligations		—			47,274			1,280			—			48,554
Deferred income taxes		1,848			(1,848	)		—			—			—
Intercompany notes and accounts payable		367,525			4,642,675			—			(5,010,200	)		—
Investment in subsidiary		2,345,867			149,999			—			(2,495,866	)		—
Other		—			162			9,121			—			9,283
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			212,503			—			212,503
Stockholders' equity (deficit):
Preferred stock		—			—			—			—			—
Common stock		12			—			—			—			12
Additional paid-in capital		3,288,371			—			403,678			(403,678	)		3,288,371
Retained earnings (accumulated deficit)		(4,173,514	)		(2,345,867	)		(588,133	)		2,934,000			(4,173,514	)
Total stockholders' equity (deficit)		(885,131	)		(2,345,867	)		(184,455	)		2,530,322			(885,131	)
Total liabilities and stockholders' equity (deficit)	$	4,655,916		$	2,768,142		$	40,718		$	(5,010,965	)	$	2,453,811

	December 31, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	100		$	7,926		$	—		$	8,026
Accounts receivable		88			166,770			9,985			(3,219	)		173,624
Receivables from derivative contracts		—			348,861			—			—			348,861
Restricted cash		138			—			16,674			—			16,812
Inventory		—			4,554			81			—			4,635
Prepaids and other		328			4,307			—			—			4,635
Total current assets		554			524,592			34,666			(3,219	)		556,593
Oil and natural gas properties (full cost method):
Evaluated		—			6,634,426			430,645			(4,350	)		7,060,721
Unevaluated		—			1,566,705			74,651			—			1,641,356
Gross oil and natural gas properties		—			8,201,131			505,296			(4,350	)		8,702,077
Less—accumulated depletion		—			(5,527,948	)		(410,090	)		4,350			(5,933,688	)
Net oil and natural gas properties		—			2,673,183			95,206			—			2,768,389
Other operating property and equipment:
Gas gathering and other operating assets		12,474			117,441			175			—			130,090
Less—accumulated depreciation		(8,705	)		(13,676	)		(54	)		—			(22,435	)
Net other operating property and equipment		3,769			103,765			121			—			107,655
Other noncurrent assets:
Receivables from derivative contracts		—			16,614			—			—			16,614
Debt issuance costs, net		7,633			—			—			—			7,633
Intercompany notes and accounts receivable		4,749,760			302,096			—			(5,051,856	)		—
Equity in oil and natural gas partnership		—			209			—			—			209
Funds in escrow and other		517			1,082			—			—			1,599
Total assets	$	4,762,233		$	3,621,541		$	129,993		$	(5,055,075	)	$	3,458,692
Current liabilities:
Accounts payable and accrued liabilities	$	—		$	326,655		$	6,102		$	(37,672	)	$	295,085
Asset retirement obligations		—			163			—			—			163
Total current liabilities		—			326,818			6,102			(37,672	)		295,248
Long-term debt, net		2,873,637			—			—			—			2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts		—			290			—			—			290
Asset retirement obligations		—			45,602			1,251			—			46,853
Intercompany notes and accounts payable		302,096			4,749,760			—			(5,051,856	)		—
Investment in subsidiary		1,534,086			32,993			—			(1,567,079	)		—
Other		—			164			6,100			—			6,264
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			183,986			—			183,986
Stockholders' equity:
Preferred stock		—			—			—			—			—
Common stock		12			—			—			—			12
Additional paid-in capital		3,283,097			—			403,678			(403,678	)		3,283,097
Retained earnings (accumulated deficit)		(3,230,695	)		(1,534,086	)		(471,124	)		2,005,210			(3,230,695	)
Total stockholders' equity		52,414			(1,534,086	)		(67,446	)		1,601,532			52,414
Total liabilities and stockholders' equity	$	4,762,233		$	3,621,541		$	129,993		$	(5,055,075	)	$	3,458,692

Cash flows

	Six Months Ended June 30, 2016
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(207,084	)	$	348,223		$	1,604		$	—			142,743
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(168,122	)		(2,136	)					(170,258	)
Other operating property and equipment capital expenditures		—			(886	)		—			—			(886	)
Advances to subsidiary		178,978			—			—			(178,978	)		—
Funds held in escrow and other		—			(233	)		—			—			(233	)
Net cash provided by (used in) investing activities		178,978			(169,241	)		(2,136	)		(178,978	)		(171,377	)
Cash flows from financing activities:
Proceeds from borrowings		425,000			—			—			—			425,000
Repayments of borrowings		(395,648	)		—			—			—			(395,648	)
Debt issuance costs		(1,186	)		—			—			—			(1,186	)
Restricted cash		—			—			(325	)		—			(325	)
Proceeds from subsidiary		—			(178,978	)		—			178,978			—
Offering costs and other		(60	)		—			—			—			(60	)
Net cash provided by (used in) financing activities		28,106			(178,978	)		(325	)		178,978			27,781
Net increase (decrease) in cash		—			4			(857	)		—			(853	)
Cash at beginning of period		—			100			7,926			—			8,026
Cash at end of period	$	—		$	104		$	7,069		$	—		$	7,173

	Six Months Ended June 30, 2015
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(187,977	)	$	400,988		$	4,519		$	—		$	217,530
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(369,816	)		(37,935	)		—			(407,751	)
Other operating property and equipment capital expenditures		(457	)		(7,024	)		3			—			(7,478	)
Advances to subsidiary		27,136			—			—			(27,136	)		—
Funds held in escrow and other		—			3,012			—			—			3,012
Net cash provided by (used in) investing activities		26,679			(373,828	)		(37,932	)		(27,136	)		(412,217	)
Cash flows from financing activities:
Proceeds from borrowings		1,296,000			—			—			—			1,296,000
Repayments of borrowings		(1,129,000	)		—			—			—			(1,129,000	)
Debt issuance costs		(18,612	)		—			—			—			(18,612	)
Common stock issued		15,354			—			—			—			15,354
Restricted cash		—			—			(352	)		—			(352	)
Proceeds from subsidiary		—			(27,136	)		—			27,136			—
Offering costs and other		(2,444	)		—			1			—			(2,443	)
Net cash provided by (used in) financing activities		161,298			(27,136	)		(351	)		27,136			160,947
Net increase (decrease) in cash		—			24			(33,764	)		—			(33,740	)
Cash at beginning of period		—			15			43,698			—			43,713
Cash at end of period	$	—		$	39		$	9,934		$	—		$	9,973

XML

FINANCIAL STATEMENT PRESENTATION (Details) $ in Millions		6 Months Ended
	Dec. 28, 2015	Jun. 30, 2016 USD ($) item	Dec. 31, 2015 USD ($)
Basis of Presentation and Principles of Consolidation
Number of operating segments | item		1
Reverse stock split ratio	0.20
Allowance for doubtful accounts receivable | $		$ 0.0	$ 0.0

XML

FINANCIAL STATEMENT PRESENTATION- Going concern (Details)	1 Months Ended	6 Months Ended	12 Months Ended
	Jul. 31, 2016	Jun. 30, 2016	Dec. 31, 2015	Jun. 20, 2016	Sep. 10, 2015	Aug. 13, 2013	Nov. 06, 2012	Jul. 16, 2012	Feb. 08, 2012
Restructuring Support Agreement
Dividend rate (as a percent)		5.75%	5.75%
Length of solicitation period	30 days
5.75% Series A Convertible Perpetual Preferred Stock
Restructuring Support Agreement
Dividend rate (as a percent)		5.75%
13.0% senior secured third lien notes due 2022
Restructuring Support Agreement
Interest rate (as a percent)		13.00%	13.00%		13.00%
9.25% senior notes due 2022
Restructuring Support Agreement
Interest rate (as a percent)		9.25%	9.25%	9.25%	9.25%	9.25%
8.875% senior notes due 2021
Restructuring Support Agreement
Interest rate (as a percent)		8.875%	8.875%	8.875%	8.875%		8.875%
9.75% senior notes due 2020
Restructuring Support Agreement
Interest rate (as a percent)		9.75%	9.75%	9.75%	9.75%			9.75%
8.0% convertible note due 2017
Restructuring Support Agreement
Interest rate (as a percent)		8.00%	8.00%						8.00%

XML

FINANCIAL STATEMENT PRESENTATION- Other PPE (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Other operating property and equipment
Non-cash impairment charge	$ 28,100	$ 28,056
Gross investments		$ 100,355	$ 130,090
Gas gathering systems and equipment
Other operating property and equipment
Estimated useful life		30 years
Cost capitalized		$ 57,800	$ 87,200
Non-cash impairment charge	28,100
Gross investments	$ 32,800
Compressed natural gas facilities
Other operating property and equipment
Estimated useful life		10 years
Automobiles
Other operating property and equipment
Estimated useful life		3 years
Computers
Other operating property and equipment
Estimated useful life		3 years
Computer software | Maximum
Other operating property and equipment
Estimated useful life		5 years
Fixtures, furniture and equipment | Maximum
Other operating property and equipment
Estimated useful life		5 years
Trailers
Other operating property and equipment
Estimated useful life		7 years
Heavy equipment
Other operating property and equipment
Estimated useful life		10 years
Buildings
Other operating property and equipment
Estimated useful life		20 years

XML

RESTRUCTURING SUPPORT AGREEMENT (Details) - USD ($) $ in Thousands						1 Months Ended		6 Months Ended	12 Months Ended
	Jul. 25, 2016	Jun. 20, 2016	Dec. 21, 2015	Sep. 10, 2015	Mar. 09, 2015	Jul. 31, 2016	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2015	Jul. 22, 2016	May 26, 2016	May 01, 2015	Aug. 13, 2013	Jan. 14, 2013	Nov. 06, 2012	Jul. 16, 2012	Feb. 08, 2012
Restructuring Support Agreement
Principal amount outstanding, net									$ 2,873,637
Principal amount							$ 2,770,387	$ 2,770,387	$ 2,862,138
Dividend rate (as a percent)								5.75%	5.75%
Consent fee (as a percent)						1.25%
5.75% Series A Convertible Perpetual Preferred Stock
Restructuring Support Agreement
Dividend rate (as a percent)								5.75%
8.625% senior secured second lien notes due 2020
Restructuring Support Agreement
Principal amount outstanding, net									$ 687,797
Interest rate (as a percent)							8.625%	8.625%	8.625%			8.625%
Principal amount							$ 700,000	$ 700,000	$ 700,000			$ 700,000
12.0% senior secured second lien notes due 2022
Restructuring Support Agreement
Principal amount outstanding, net									$ 111,598
Interest rate (as a percent)			12.00%				12.00%	12.00%	12.00%
Principal amount			$ 112,800				$ 112,826	$ 112,826	$ 112,826
13.0% senior secured third lien notes due 2022
Restructuring Support Agreement
Principal amount outstanding, net									$ 1,009,585
Interest rate (as a percent)				13.00%			13.00%	13.00%	13.00%
Principal amount				$ 1,020,000			$ 1,017,970	$ 1,017,970	$ 1,017,970
9.25% senior notes due 2022
Restructuring Support Agreement
Principal amount outstanding, net									$ 51,887
Interest rate (as a percent)		9.25%		9.25%			9.25%	9.25%	9.25%				9.25%
Principal amount							$ 37,194	$ 37,194	$ 52,694				$ 400,000
8.875% senior notes due 2021
Restructuring Support Agreement
Principal amount outstanding, net									$ 347,671
Interest rate (as a percent)		8.875%		8.875%			8.875%	8.875%	8.875%						8.875%
Principal amount							$ 297,193	$ 297,193	$ 348,944					$ 600,000	$ 750,000
9.75% senior notes due 2020
Restructuring Support Agreement
Principal amount outstanding, net									$ 336,470
Interest rate (as a percent)		9.75%		9.75%			9.75%	9.75%	9.75%							9.75%
Principal amount							$ 315,535	$ 315,535	$ 340,035							$ 750,000
8.0% convertible note due 2017
Restructuring Support Agreement
Principal amount outstanding, net									$ 266,629
Interest rate (as a percent)							8.00%	8.00%	8.00%								8.00%
Principal amount							$ 289,669	$ 289,669	$ 289,669								$ 275,000
8% convertible Note post-amendment
Restructuring Support Agreement
Extension term					3 years
Senior revolving credit facility
Restructuring Support Agreement
Principal amount outstanding, net									$ 62,000
Maximum borrowing capacity																	$ 1,500,000
Amount borrowed under line of credit	$ 444,000
Senior Unsecured Notes Held by Certain Holders | 9.25% senior notes due 2022
Restructuring Support Agreement
Extinguishment of debt, aggregate principal			35,300	$ 294,400
Senior Unsecured Notes Held by Certain Holders | 8.875% senior notes due 2021
Restructuring Support Agreement
Extinguishment of debt, aggregate principal			137,700	774,700
Senior Unsecured Notes Held by Certain Holders | 9.75% senior notes due 2020
Restructuring Support Agreement
Extinguishment of debt, aggregate principal			$ 116,600	$ 497,200
Waiver to the Senior Credit Agreement
Restructuring Support Agreement
Maximum borrowing capacity	444,000										$ 450,000
Amount borrowed under line of credit	$ 338,000
Second lien holders | Minimum
Restructuring Support Agreement
Percentage of outstanding debt represented by the Restructuring Support Agreement (as a percent)										51.00%
Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | Common Stock
Restructuring Support Agreement
Percentage of outstanding debt represented by the Restructuring Support Agreement (as a percent)							4.00%	4.00%
Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | 5.75% Series A Convertible Perpetual Preferred Stock
Restructuring Support Agreement
Cash payment to noteholders							$ 11,100
Percentage voted for the Plan (as a percent)		99.86%
Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | 13.0% senior secured third lien notes due 2022
Restructuring Support Agreement
Redemption price of debt instrument (as a percent)							76.50%
Cash payment to noteholders							$ 33,800
Percentage voted for the Plan (as a percent)		99.997%
Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | 8.0% convertible note due 2017
Restructuring Support Agreement
Percentage of outstanding debt represented by the Restructuring Support Agreement (as a percent)							4.00%	4.00%
Equity value needed to exercise warrants							$ 1,330,000	$ 1,330,000
Cash payment to noteholders							$ 15,000
Percentage voted for the Plan (as a percent)		100.00%
Pro forma equity of reorganized Halcon (as a percent)							1.00%
Extension term							4 years
Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | Senior Unsecured Notes Held by Certain Holders
Restructuring Support Agreement
Percentage of outstanding debt represented by the Restructuring Support Agreement (as a percent)							15.50%	15.50%
Equity value needed to exercise warrants							$ 1,330,000	$ 1,330,000
Cash payment to noteholders							$ 37,600
Percentage voted for the Plan (as a percent)		99.86%
Pro forma equity of reorganized Halcon (as a percent)							4.00%
Warrant term							4 years
Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | Waiver to the Senior Credit Agreement | Minimum
Restructuring Support Agreement
Principal amount							$ 600,000	$ 600,000

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OIL AND NATURAL GAS PROPERTIES (Details) $ in Thousands	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($) $ / bbl	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($) $ / bbl	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 $ / MMBTU $ / bbl	Dec. 31, 2015 $ / bbl	Jun. 30, 2015 $ / MMBTU $ / bbl	Dec. 31, 2014 $ / bbl
Ceiling Limitation Disclosures
First day average of the West Texas Intermediate (WTI) crude oil spot price (in dollars per barrel) | $ / bbl							43.12		71.68
First day average of the Henry Hub natural gas price (in dollars per Mmbtu) | $ / MMBTU							2.24		3.39
Full cost ceiling impairment	$ 257,869	$ 496,900	$ 948,633	$ 554,000	$ 754,769	$ 1,502,636
Full cost ceiling impairment, after tax	$ 163,100	$ 315,100	$ 597,300	$ 348,800
Percent decrease in the first-day-of-the-month average prices for crude oil	7.00%				8.00%
Average price (in dollars per barrel) | $ / bbl		46.26		82.71				50.28		94.99
Unevaluated Oil and Gas Leaseholds
Oil and Natural Gas Properties
Interest costs capitalized					$ 52,900	$ 51,200
Tuscaloosa Marine Shale | Unevaluated Oil and Gas Leaseholds
Ceiling Limitation Disclosures
Amount of unevaluated property costs transferred to the full cost pool					74,800
Utica areas | Unevaluated Oil and Gas Leaseholds
Ceiling Limitation Disclosures
Amount of unevaluated property costs transferred to the full cost pool					$ 330,400

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DEBT (Details) - USD ($) $ in Thousands	Dec. 21, 2015	Sep. 10, 2015	Jun. 30, 2016	Jun. 20, 2016	Dec. 31, 2015	May 01, 2015	Mar. 09, 2015	Dec. 19, 2013	Aug. 13, 2013	Jan. 14, 2013	Nov. 06, 2012	Jul. 16, 2012	Feb. 08, 2012
Current and long-term debt
Current portion of long-term debt, net			$ 2,825,807
Principal amount outstanding, net					$ 2,873,637
Principal amount			2,770,387		2,862,138
8.625% senior secured second lien notes due 2020
Current and long-term debt
Current portion of long-term debt, net			$ 689,064
Principal amount outstanding, net					$ 687,797
Interest rate (as a percent)			8.625%		8.625%	8.625%
Principal amount			$ 700,000		$ 700,000	$ 700,000
Unamortized debt issuance costs			10,900		12,200
12.0% senior secured second lien notes due 2022
Current and long-term debt
Current portion of long-term debt, net			$ 111,408
Principal amount outstanding, net					$ 111,598
Interest rate (as a percent)	12.00%		12.00%		12.00%
Principal amount	$ 112,800		$ 112,826		$ 112,826
Unamortized debt issuance costs			1,400		1,200
13.0% senior secured third lien notes due 2022
Current and long-term debt
Current portion of long-term debt, net			$ 1,010,048
Principal amount outstanding, net					$ 1,009,585
Interest rate (as a percent)		13.00%	13.00%		13.00%
Principal amount		$ 1,020,000	$ 1,017,970		$ 1,017,970
Unamortized debt issuance costs			7,900		8,400
9.25% senior notes due 2022
Current and long-term debt
Current portion of long-term debt, net			$ 36,660
Principal amount outstanding, net					$ 51,887
Interest rate (as a percent)		9.25%	9.25%	9.25%	9.25%				9.25%
Principal amount			$ 37,194		$ 52,694				$ 400,000
Unamortized debt issuance costs			500		800
8.875% senior notes due 2021
Current and long-term debt
Current portion of long-term debt, net			$ 296,184
Principal amount outstanding, net					$ 347,671
Interest rate (as a percent)		8.875%	8.875%	8.875%	8.875%						8.875%
Principal amount			$ 297,193		$ 348,944					$ 600,000	$ 750,000
Unamortized debt issuance costs			4,500		5,800
Unamortized discount			800		1,000						$ 5,700
Unamortized premium related to debt issued			4,300		5,500					$ 30,000
9.75% senior notes due 2020
Current and long-term debt
Current portion of long-term debt, net			$ 312,522
Principal amount outstanding, net					$ 336,470
Interest rate (as a percent)		9.75%	9.75%	9.75%	9.75%							9.75%
Principal amount			$ 315,535		$ 340,035							$ 750,000
Unamortized debt issuance costs			3,600		4,300
Unamortized discount			1,600		1,900							$ 10,200
Unamortized premium related to debt issued			2,200		2,600			$ 11,000
8.0% convertible note due 2017
Current and long-term debt
Current portion of long-term debt, net			$ 268,921
Principal amount outstanding, net					$ 266,629
Interest rate (as a percent)			8.00%		8.00%								8.00%
Principal amount			$ 289,669		$ 289,669								$ 275,000
Unamortized discount			20,700		23,000
8% convertible Note post-amendment
Current and long-term debt
Unamortized discount							$ 25,900
Senior revolving credit facility
Current and long-term debt
Current portion of long-term debt, net			$ 101,000
Principal amount outstanding, net					$ 62,000
Senior Unsecured Notes Held by Certain Holders | 9.25% senior notes due 2022
Current and long-term debt
Extinguishment of debt, aggregate principal	35,300	$ 294,400
Senior Unsecured Notes Held by Certain Holders | 8.875% senior notes due 2021
Current and long-term debt
Extinguishment of debt, aggregate principal	137,700	774,700
Senior Unsecured Notes Held by Certain Holders | 9.75% senior notes due 2020
Current and long-term debt
Extinguishment of debt, aggregate principal	$ 116,600	$ 497,200

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DEBT-Senior Facility (Details) $ in Thousands				6 Months Ended
	Jul. 25, 2016 USD ($)	Feb. 08, 2012 USD ($) item	Feb. 08, 2012 USD ($)	Jun. 30, 2016 USD ($)	May 26, 2016 USD ($)	Mar. 17, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 21, 2015 USD ($)
Current and long-term debt
Principal amount				$ 2,770,387			$ 2,862,138
12.0% senior secured second lien notes due 2022
Current and long-term debt
Principal amount				$ 112,826			$ 112,826	$ 112,800
Interest rate (as a percent)				12.00%			12.00%	12.00%
Senior revolving credit facility
Current and long-term debt
Maximum borrowing capacity		$ 1,500,000	$ 1,500,000
Current borrowing capacity		$ 700,000	$ 700,000
Amount outstanding	$ 338,000
Amount borrowed under line of credit	444,000
Number of interim unscheduled redeterminations of borrowing base to which the company and lender each have the right | item		1
Number of consecutive semi-annual redeterminations between which the company and the lenders each have the right to one interim unscheduled redetermination of borrowing base | item		2
Weighted average interest rate (as a percent)				3.20%
Senior revolving credit facility | Minimum
Current and long-term debt
Working capital levels			1.0
Senior revolving credit facility | Maximum
Current and long-term debt
Total secured debt to EBITDA ratio		2.75
Senior revolving credit facility | ABR - based
Current and long-term debt
Variable rate base			Base rate
Senior revolving credit facility | ABR - based | Minimum
Current and long-term debt
Applicable margin (as a percent)			1.50%
Senior revolving credit facility | ABR - based | Maximum
Current and long-term debt
Applicable margin (as a percent)			2.50%
Senior revolving credit facility | Euro-dollar based
Current and long-term debt
Variable rate base			LIBOR
Senior revolving credit facility | Euro-dollar based | Minimum
Current and long-term debt
Applicable margin (as a percent)			2.50%
Senior revolving credit facility | Euro-dollar based | Maximum
Current and long-term debt
Applicable margin (as a percent)			3.50%
Senior revolving credit facility | The DIP Facility
Current and long-term debt
Interim availability borrowings	500,000
Debtor in possession interim credit facility maximum borrowing capacity	$ 600,000
Maturity period of debtor-in-possession facility	3 months
Extension periods at the request of the borrower for the DIP Facility	3 months
Senior revolving credit facility | The DIP Facility | ABR - based | Minimum
Current and long-term debt
Applicable margin (as a percent)	1.75%
Senior revolving credit facility | The DIP Facility | ABR - based | Maximum
Current and long-term debt
Applicable margin (as a percent)	2.75%
Senior revolving credit facility | The DIP Facility | LIBOR | Minimum
Current and long-term debt
Applicable margin (as a percent)	2.75%
Senior revolving credit facility | The DIP Facility | LIBOR | Maximum
Current and long-term debt
Applicable margin (as a percent)	3.75%
Senior revolving credit facility | Exit Senior Secured Reserve Based Revolving Credit Facility
Current and long-term debt
Debtor in possession financing borrowings arranged upon final order	$ 600,000
Waiver to the Senior Credit Agreement
Current and long-term debt
Maximum borrowing capacity	444,000				$ 450,000
Amount borrowed under line of credit	$ 338,000
Amount outstanding				$ 101,000
Letters of credit outstanding				$ 5,200
Thirteenth Amendment to the Senior Credit Agreement
Current and long-term debt
Current borrowing capacity						$ 700,000

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DEBT - Amended Senior Facilities (Details) - USD ($) $ in Thousands									6 Months Ended
	Dec. 21, 2015	Sep. 10, 2015	May 01, 2015	Dec. 19, 2013	Aug. 13, 2013	Jan. 14, 2013	Nov. 06, 2012	Jul. 16, 2012	Jun. 30, 2016	Jun. 20, 2016	Dec. 31, 2015	Feb. 08, 2012
Current and long-term debt
Principal amount									$ 2,770,387		$ 2,862,138
Ownership percentage in subsidiaries									100.00%
Principal amount outstanding, net											2,873,637
8.625% senior secured second lien notes due 2020
Current and long-term debt
Principal amount			$ 700,000						$ 700,000		$ 700,000
Interest rate (as a percent)			8.625%						8.625%		8.625%
Net proceeds from issuance			$ 686,200
Principal amount outstanding, net											$ 687,797
12.0% senior secured second lien notes due 2022
Current and long-term debt
Principal amount	$ 112,800								$ 112,826		$ 112,826
Gross debt extinguished for new notes	$ 289,600
Interest rate (as a percent)	12.00%								12.00%		12.00%
Principal amount outstanding, net											$ 111,598
13.0% senior secured third lien notes due 2022
Current and long-term debt
Principal amount		$ 1,020,000							$ 1,017,970		$ 1,017,970
Interest rate (as a percent)		13.00%							13.00%		13.00%
Principal amount outstanding, net											$ 1,009,585
9.25% senior notes due 2022
Current and long-term debt
Principal amount					$ 400,000				$ 37,194		$ 52,694
Interest rate (as a percent)		9.25%			9.25%				9.25%	9.25%	9.25%
Net proceeds from issuance					$ 392,100
Ownership percentage in subsidiaries									100.00%
Independent assets									$ 0
Independent operations									0
Principal amount repurchased									15,500
Principal amount outstanding, net											$ 51,887
Net gain on extinguishment of debt									11,100
8.875% senior notes due 2021
Current and long-term debt
Principal amount						$ 600,000	$ 750,000		$ 297,193		$ 348,944
Interest rate (as a percent)		8.875%					8.875%		8.875%	8.875%	8.875%
Issue price as a percentage of par value						105.00%	99.247%
Net proceeds from issuance						$ 619,500	$ 725,600
Ownership percentage in subsidiaries									100.00%
Independent assets									$ 0
Independent operations									0
Unamortized discount							$ 5,700		800		$ 1,000
Unamortized premium						$ 30,000			4,300		5,500
Principal amount repurchased									51,800
Principal amount outstanding, net											347,671
Net gain on extinguishment of debt									47,500
9.75% senior notes due 2020
Current and long-term debt
Principal amount								$ 750,000	$ 315,535		$ 340,035
Interest rate (as a percent)		9.75%						9.75%	9.75%	9.75%	9.75%
Issue price as a percentage of par value				102.75%				98.646%
Net proceeds from issuance				$ 406,300				$ 723,100
Ownership percentage in subsidiaries									100.00%
Principal amount of debt issued				400,000
Independent assets									$ 0
Independent operations									0
Unamortized discount								$ 10,200	1,600		$ 1,900
Unamortized premium				$ 11,000					2,200		2,600
Principal amount repurchased									24,500
Principal amount outstanding, net											336,470
Net gain on extinguishment of debt									$ 22,800
Senior revolving credit facility
Current and long-term debt
Principal amount outstanding, net											$ 62,000
Current borrowing capacity												$ 700,000
Senior Unsecured Notes Held by Certain Holders | 9.25% senior notes due 2022
Current and long-term debt
Extinguishment of debt, aggregate principal	$ 35,300	$ 294,400
Senior Unsecured Notes Held by Certain Holders | 8.875% senior notes due 2021
Current and long-term debt
Extinguishment of debt, aggregate principal	137,700	774,700
Senior Unsecured Notes Held by Certain Holders | 9.75% senior notes due 2020
Current and long-term debt
Extinguishment of debt, aggregate principal	$ 116,600	$ 497,200

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DEBT-Convertible Notes (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended			6 Months Ended
	Mar. 09, 2015	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Jun. 30, 2016	Dec. 31, 2015	Feb. 08, 2014	Feb. 29, 2012	Feb. 08, 2012
Current and long-term debt
Principal amount					$ 2,770,387	$ 2,862,138
Debt issuance costs expensed					$ 2,500
February 2012 Warrants
Current and long-term debt
Term					5 years
Exercise price (in dollars per share)	$ 12.20				$ 12.20			$ 22.50
8.0% convertible note due 2017
Current and long-term debt
Principal amount					$ 289,669	$ 289,669			$ 275,000
Interest rate (as a percent)					8.00%	8.00%			8.00%
Interest in kind		$ 5,800	$ 5,700	$ 3,200
Principal outstanding					$ 289,700
Unamortized discount					$ 20,700	$ 23,000
8% convertible Note pre-amendment
Current and long-term debt
Amount of principal and accrued interest that is convertible into one share of the entity's common stock (in dollars per share)							$ 22.50
8% convertible Note post-amendment
Current and long-term debt
Extension term	3 years
Amount of principal and accrued interest that is convertible into one share of the entity's common stock (in dollars per share)					$ 12.20
Unamortized discount	$ 25,900

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DEBT- Senior Unsecured Notes (Details) - USD ($) $ in Thousands			6 Months Ended
	Dec. 21, 2015	Sep. 10, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Aug. 13, 2013	Jan. 14, 2013	Nov. 06, 2012	Jul. 16, 2012
Current and long-term debt
Principal amount			$ 2,770,387		$ 2,862,138
Debt Issuance Costs
Costs associated with the issuance of debt capitalized			1,186	$ 18,612
Debt issuance costs expensed			2,500
Debt issuance costs, net					7,633
8.875% senior notes due 2021
Current and long-term debt
Principal amount			297,193		348,944		$ 600,000	$ 750,000
Net gain on extinguishment of debt			47,500
13.0% senior secured third lien notes due 2022
Current and long-term debt
Principal amount		$ 1,020,000	1,017,970		1,017,970
9.25% senior notes due 2022
Current and long-term debt
Principal amount			37,194		52,694	$ 400,000
Net gain on extinguishment of debt			11,100
9.75% senior notes due 2020
Current and long-term debt
Principal amount			315,535		340,035				$ 750,000
Net gain on extinguishment of debt			22,800
Senior revolving credit facility
Debt Issuance Costs
Debt issuance costs, net			$ 34,500		$ 40,300
Senior Unsecured Notes Held by Certain Holders | 8.875% senior notes due 2021
Current and long-term debt
Extinguishment of debt, aggregate principal	$ 137,700	774,700
Senior Unsecured Notes Held by Certain Holders | 9.25% senior notes due 2022
Current and long-term debt
Extinguishment of debt, aggregate principal	35,300	294,400
Senior Unsecured Notes Held by Certain Holders | 9.75% senior notes due 2020
Current and long-term debt
Extinguishment of debt, aggregate principal	$ 116,600	$ 497,200

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FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Assets
Asset transfers between levels	$ 0	$ 0
Liabilities
Liability transfers between levels	0	0
Recurring | Total
Assets
Receivables from derivative contracts	141,097	365,475
Liabilities
Liabilities from derivative contracts	194	290
Recurring | Level 2
Assets
Receivables from derivative contracts	141,097	365,475
Liabilities
Liabilities from derivative contracts	42	105
Recurring | Level 3
Liabilities
Liabilities from derivative contracts	$ 152	$ 185

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FAIR VALUE MEASUREMENTS-Level 3 Reconciliation (Details) - Recurring - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Reconciliation of changes in the fair value of the Company's oil derivative instruments classified as Level 3 in the fair value hierarchy
Beginning Balance	$ (185)	$ (1,319)
Net gain (loss) on derivative contracts	33	1,134
Ending Balance	(152)	(185)
Change in unrealized gains (losses) included in earnings related to derivatives still held at the end of the period	$ 33	$ (185)

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FAIR VALUE MEASUREMENTS-Estimated FV (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Mar. 31, 2016	Jun. 30, 2016	Jun. 20, 2016	Dec. 31, 2015	Dec. 21, 2015	Sep. 10, 2015	May 01, 2015	Aug. 13, 2013	Nov. 06, 2012	Jul. 16, 2012	Feb. 08, 2012
Fair value measurements
Non-cash impairment charge	$ 28,100	$ 28,056
8.625% senior secured second lien notes due 2020
Fair value measurements
Interest rate (as a percent)		8.625%		8.625%			8.625%
12.0% senior secured second lien notes due 2022
Fair value measurements
Interest rate (as a percent)		12.00%		12.00%	12.00%
13.0% senior secured third lien notes due 2022
Fair value measurements
Interest rate (as a percent)		13.00%		13.00%		13.00%
9.25% senior notes due 2022
Fair value measurements
Interest rate (as a percent)		9.25%	9.25%	9.25%		9.25%		9.25%
8.875% senior notes due 2021
Fair value measurements
Interest rate (as a percent)		8.875%	8.875%	8.875%		8.875%			8.875%
9.75% senior notes due 2020
Fair value measurements
Interest rate (as a percent)		9.75%	9.75%	9.75%		9.75%				9.75%
8.0% convertible note due 2017
Fair value measurements
Interest rate (as a percent)		8.00%		8.00%							8.00%
Total
Fair value measurements
Estimated fair value of short-term debt		$ 1,519,415
Estimated fair value of debt				$ 1,180,560
Total | 8.625% senior secured second lien notes due 2020
Fair value measurements
Estimated fair value of short-term debt		659,120
Estimated fair value of debt				479,500
Total | 12.0% senior secured second lien notes due 2022
Fair value measurements
Estimated fair value of short-term debt		106,237
Estimated fair value of debt				77,286
Total | 13.0% senior secured third lien notes due 2022
Fair value measurements
Estimated fair value of short-term debt		539,524
Estimated fair value of debt				333,385
Total | 9.25% senior notes due 2022
Fair value measurements
Estimated fair value of short-term debt		8,276
Estimated fair value of debt				14,422
Total | 8.875% senior notes due 2021
Fair value measurements
Estimated fair value of short-term debt		66,125
Estimated fair value of debt				95,506
Total | 9.75% senior notes due 2020
Fair value measurements
Estimated fair value of short-term debt		70,207
Estimated fair value of debt				93,068
Total | 8.0% convertible note due 2017
Fair value measurements
Estimated fair value of short-term debt		$ 69,926
Estimated fair value of debt				$ 87,393

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DERIVATIVE AND HEDGING ACTIVITIES (Details) $ in Thousands	Jun. 30, 2016 USD ($) item	Dec. 31, 2015 USD ($) item
Derivative and hedging activities
Asset derivative contracts	$ 141,097	$ 365,475
Liability derivative contracts	(194)	(290)
Derivatives not designated as hedging contracts
Derivative and hedging activities
Asset derivative contracts	141,097	365,475
Liability derivative contracts	$ (194)	$ (290)
Derivatives not designated as hedging contracts | Commodity contracts
Derivative and hedging activities
Number of open commodity derivative contracts | item	34	36
Derivatives not designated as hedging contracts | Commodity contracts | Current assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	$ 135,455	$ 348,861
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	5,642	16,614
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts	$ (194)	$ (290)
Derivatives not designated as hedging contracts | Commodity contracts | Collars | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts | item	1	1
Derivatives not designated as hedging contracts | Commodity contracts | Collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts | item	14	16
Derivatives not designated as hedging contracts | Commodity contracts | Swaps | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts | item	13	13
Derivatives not designated as hedging contracts | Commodity contracts | Swaptions | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts | item	5	5
Derivatives not designated as hedging contracts | Commodity contracts | Extendable collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts | item	1	1

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DERIVATIVE AND HEDGING ACTIVITIES- Realized Unrealized (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative and hedging activities
Total net gain (loss) on derivative contracts	$ (54,523)	$ (87,564)	$ (35,781)	$ 12,184
Derivatives not designated as hedging contracts | Commodity contracts | Other Income Expense
Derivative and hedging activities
Unrealized gain (loss) on commodity contracts	(135,303)	(175,712)	(224,281)	(183,713)
Realized gain (loss) on commodity contracts	80,780	88,148	188,500	195,897
Total net gain (loss) on derivative contracts	$ (54,523)	$ (87,564)	$ (35,781)	$ 12,184

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DERIVATIVE AND HEDGING ACTIVITIES- Open contracts (Details) $ in Thousands	Jun. 30, 2016 USD ($) MMBTU $ / MMBTU $ / bbl bbl	Dec. 31, 2015 USD ($) MMBTU $ / MMBTU $ / bbl bbl
Derivative Assets
Gross amounts presented in the consolidated balance sheets | $	$ 141,097	$ 365,475
Amounts not offset in the consolidated balance sheets | $	(21)	(53)
Net amount | $	141,076	365,422
Derivative Liabilities
Gross amounts presented in the consolidated balance sheet | $	(194)	(290)
Amounts not offset in the consolidated balance sheet | $	20	52
Net amount | $	(174)	$ (238)
Commodity contracts | 184,000 Bbls
Derivative and hedging activities
Proceeds from termination of derivative contract | $	$ 9,600
Collars | Commodity contracts | Crude oil | 184,000 Bbls
Derivative and hedging activities
Volume in Bbl's | bbl	184,000
Swaps | Commodity contracts | Crude oil | 184,000 Bbls
Derivative and hedging activities
Volume in Bbl's | bbl	184,000
January 2016 - June 2016 | Collars | Commodity contracts | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		182,000
Floors (in dollars per Mmbtu's/Bbl's)		90.00
Ceilings (in dollars per Mmbtu's/Bbl's)		96.85
January 2016 - June 2016 | Collars | Commodity contracts | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		90.00
Ceilings (in dollars per Mmbtu's/Bbl's)		96.85
January 2016 - December 2016 | Collars | Commodity contracts | Crude oil
Derivative and hedging activities
Volume in Mmbtu's | MMBTU		4,392,000
January 2016 - December 2016 | Collars | Commodity contracts | Crude oil | 365,000 Bbls | Extendable period through December 31, 2017
Derivative and hedging activities
Volume in Bbl's | bbl	365,000	365,000
Floors (in dollars per Mmbtu's/Bbl's)	60.00	60.00
Ceilings (in dollars per Mmbtu's/Bbl's)	75.00	75.00
January 2016 - December 2016 | Collars | Commodity contracts | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		60.00
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		64.00
January 2016 - December 2016 | Collars | Commodity contracts | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		90.00
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		95.10
January 2016 - December 2016 | Collars | Commodity contracts | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		71.91
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		77.71
January 2016 - December 2016 | Collars | Commodity contracts | Natural gas
Derivative and hedging activities
Volume in Bbl's | bbl		732,000
Floors (in dollars per Mmbtu's/Bbl's)		4.00
Ceilings (in dollars per Mmbtu's/Bbl's)		4.22
January 2016 - December 2016 | Collars | Commodity contracts | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		4.00
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		4.22
January 2016 - December 2016 | Swaps | Commodity contracts | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		4,758,000
January 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | 730,000 Bbls | Extendable period through December 31, 2017
Derivative and hedging activities
Volume in Bbl's | bbl	730,000	730,000
Floors (in dollars per Mmbtu's/Bbl's)	88.25	88.25
January 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | 912,500 Bbls | Extendable period through December 31, 2017
Derivative and hedging activities
Volume in Bbl's | bbl	912,500	912,500
Floors (in dollars per Mmbtu's/Bbl's)	88.00	88.00
January 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | 547,500 Bbls | Extendable period through December 31, 2017
Derivative and hedging activities
Volume in Bbl's | bbl	547,500	547,500
Floors (in dollars per Mmbtu's/Bbl's)	88.87	88.87
January 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		62.00
January 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		91.73
January 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		85.43
July 2016 - December 2016 | Collars | Commodity contracts | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,024,000
July 2016 - December 2016 | Collars | Commodity contracts | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	60.00
Ceilings (in dollars per Mmbtu's/Bbl's)	64.00
July 2016 - December 2016 | Collars | Commodity contracts | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	90.00
Ceilings (in dollars per Mmbtu's/Bbl's)	95.10
July 2016 - December 2016 | Collars | Commodity contracts | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	73.00
Ceilings (in dollars per Mmbtu's/Bbl's)	78.87
July 2016 - December 2016 | Collars | Commodity contracts | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU	368,000
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	4.00
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	4.22
July 2016 - December 2016 | Collars | Commodity contracts | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	4.00
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	4.22
July 2016 - December 2016 | Swaps | Commodity contracts | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,392,000
July 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	62.00
July 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	91.73
July 2016 - December 2016 | Swaps | Commodity contracts | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	85.43
January 2017 - December 2017 | Collars | Commodity contracts | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	1,368,750	1,368,750
January 2017 - December 2017 | Collars | Commodity contracts | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50.00	50.00
Ceilings (in dollars per Mmbtu's/Bbl's)	70.00	70.00
January 2017 - December 2017 | Collars | Commodity contracts | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	60.00	60.00
Ceilings (in dollars per Mmbtu's/Bbl's)	76.84	76.84
January 2017 - December 2017 | Collars | Commodity contracts | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	57.33	57.33
Ceilings (in dollars per Mmbtu's/Bbl's)	74.16	74.16

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ASSET RETIREMENT OBLIGATIONS (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2016 USD ($)
Activity related to ARO liability
Liability for asset retirement obligations at the beginning of the period	$ 47,016
Liabilities settled and divested	(180)
Additions	1,024
Acquisitions	75
Accretion expense	1,031
Liability for asset retirement obligations at the end of the period	$ 48,966

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COMMITMENTS AND CONTINGENCIES (Details)	3 Months Ended	6 Months Ended
	Mar. 31, 2016 item	Jun. 30, 2016 USD ($) item	Jun. 30, 2015 USD ($)	Apr. 05, 2016 USD ($)	Jan. 31, 2015 USD ($)
Commitments and contingencies
Rent expense		$ 4,300,000	$ 4,300,000
Office and equipment lease agreements amount		$ 46,800,000
Non-cancelable termination penalties				$ 1,200,000	$ 6,000,000
Number of long-term natural gas gathering contracts to which the entity is committed | item	1
Number of trigger dates | item		2
Maximum
Commitments and contingencies
Drilling rig commitments		$ 3,000,000
Drilling rig commitments
Commitments and contingencies
Non-cancelable termination penalties		$ 14,800,000
Number of drilling rig commitments | item		2
Drilling rig commitments		$ 20,800,000
Drilling rig commitments | Minimum
Commitments and contingencies
Stacking fees per day pertaining to the new drilling rig commitment		16,000
Drilling rig commitments | Maximum
Commitments and contingencies
Stacking fees per day pertaining to the new drilling rig commitment		$ 17,000
Gathering, transportation and sales | North Dakota
Commitments and contingencies
Number of long-term crude oil sales contracts to which the entity is committed | item		9
Number of long-term natural gas sales contracts to which the entity is committed | item		5
Gathering, transportation and sales | North Dakota | Minimum
Commitments and contingencies
Period of commitment for production from the date of first production		1 year
Gathering, transportation and sales | North Dakota | Maximum
Commitments and contingencies
Period of commitment for production from the date of first production		10 years

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MEZZANINE EQUITY (Details) $ / shares in Units, $ in Thousands		6 Months Ended
	Jun. 16, 2014 USD ($) multiplier shares	Jun. 30, 2016 USD ($) item $ / shares shares	Jun. 30, 2015 shares	Jun. 01, 2015 item
Preferred Stock
Mezzanine equity
Balances at beginning of period (in shares) | shares		165,639
Dividends paid in-kind (in shares) | shares		6,655
Balances at end of period (in shares) | shares		172,294
Increase (Decrease) in Temporary Equity
Balances at beginning of period		$ 183,986
Dividends paid in-kind		6,655
Accretion of redeemable noncontrolling interest		21,862
Balances at end of period		212,503
HK TMS
Mezzanine equity
Withdrawal exit fee		6,200
Value of quarterly dividend payments whose equivalent amount is to be maintained as minimum cash balance		3,500
Additional amount to be maintained as cash balance		$ 10,000
Restriction percentage on transfer of assets		20.00%
HK TMS | Maximum
Mezzanine equity
Restriction percentage on transfer out of the maximum net acres		20.00%
HK TMS | Preferred Stock
Mezzanine equity
Proceeds contributed by parent	$ 50,000
HK TMS | Preferred Stock | Minimum
Mezzanine equity
Withdrawal exit fee (per share) | $ / shares		$ 2.50
HK TMS | Preferred Stock | Maximum
Mezzanine equity
Withdrawal exit fee (per share) | $ / shares		$ 20.00
HK TMS | Apollo | Preferred Stock
Mezzanine equity
Proceeds received on sale of preferred shares	$ 150,000
Dividend rate (as a percent)	8.00%
Number of dividends to be paid prior to December 31, 2016 | item		0
Additional preferred shares issued for dividends paid-in-kind | shares		6,655	6,131
PIK exit fee per share | $ / shares		$ 5.00
Total PIK exit fees incurred		$ 5,600
Rate of return on preferred shares (as a percent)	12.00%
Multiple factor on investment | multiplier	1.25
Additional preferred shares available for issuance | shares	150,000
Number of wells committed to be drilled | item				6.5
Number of consecutive twelve month periods beginning December 31, 2015 for wells committed to be drilled | item				5

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MEZZANINE EQUITY-Change in FV (Details) - Embedded Derivative $ in Thousands	6 Months Ended
	Jun. 30, 2016 USD ($)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning Balance	$ 6,100
Change in fair value	3,020
Ending Balance	$ 9,120

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STOCKHOLDERS' EQUITY (Details) $ / shares in Units, $ in Thousands			1 Months Ended	6 Months Ended	12 Months Ended
	Dec. 28, 2015	Jun. 18, 2013 USD ($) $ / shares shares	Feb. 29, 2012 USD ($) $ / shares shares	Jun. 30, 2016 USD ($) item $ / shares shares	Dec. 31, 2015 USD ($) shares	Mar. 09, 2015 $ / shares	May 22, 2014 shares
Preferred stock and stockholders' equity
Proceeds from the offering of common stock | $					$ 15,356
Dividend rate (as a percent)				5.75%	5.75%
Preferred stock, shares outstanding				222,454	244,724
Authorized shares of common stock, after amendment of certificate of incorporation				1,340,000,000	1,340,000,000
Cash dividends paid | $					$ 8,177
Reverse stock split ratio	0.20
February 2012 Warrants
Preferred stock and stockholders' equity
Payment for capital commitment | $			$ 600
Number of shares of common stock that can be purchased from warrants			7,300,000
Exercise price (in dollars per share) | $ / shares			$ 22.50	$ 12.20		$ 12.20
Proceeds from issuance of warrants | $			$ 43,600
Common Stock
Preferred stock and stockholders' equity
Shares issued					1,900,000
Proceeds from the offering of common stock | $					$ 15,000
Authorized shares of common stock, after amendment of certificate of incorporation							1,340,000,000
Increase in shares of common stock authorized							670,000,000
5.75% Series A Convertible Perpetual Preferred Stock
Preferred stock and stockholders' equity
Shares issued		345,000		4,000,000
Dividend rate (as a percent)				5.75%
Number of shares of common stock to be issued upon conversion				32.49
Share price (in dollars per share) | $ / shares		$ 1,000
Net proceeds received | $		$ 335,200
Preferred stock converted into common stock (in shares)				122,546
Benefit from conversion of stock (in dollars per share) | $ / shares				$ 30.80
Preferred stock, shares outstanding				222,454
Liquidation preference per share (in dollars per share) | $ / shares				$ 1,000
Number of shares of common stock to be issued upon conversion at initial conversion rate				11,200,000
Closing sale price of common stock as minimum percentage of the conversion price to automatically convert preferred stock into common stock				150.00%
Minimum number of trading days within 30 consecutive trading days during which the closing sales price of common stock per share must exceed the conversion price for the preferred stocks to be redeemable				20 days
Number of consecutive trading day periods within which the closing sale price of common stock price per share must exceed the conversion price for at least 20 trading days for the preferred stocks to be redeemable				30 days
Number of consecutive trading day periods ending on the third business day prior to settlement date				5 days
Number of shares of common stock to be issued upon conversion on fundamental change				58.48
Threshold period of dividends in arrears and unpaid which will give holders of the Convertible Preferred Stock voting rights				18 months
Number of additional directors that can be appointed by holders of the Convertible Preferred Stock until arrearage is paid in full | item				2
Cumulative, undeclared dividends | $				$ 7,500

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STOCKHOLDERS' EQUITY- PSU and Options (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	May 23, 2013	May 17, 2012
Weighted Average Exercise Price Per Share
Granted (in dollars per share)					$ 9.60
General and administrative
Stock-based compensation
Compensation expense recorded		$ 1.5	$ 3.4	$ 3.7	$ 8.2
Performance share units (PSU)
Stock-based compensation
Unrecognized compensation expense			$ 2.7		$ 2.7
Weighted average remaining vesting period				8 months 12 days	1 year 8 months 12 days
Performance Share Units
Unrecognized compensation expense	$ 1.1	$ 1.1		$ 1.1
Performance share units (PSU) | Common Stock
Performance Share Units
Number of trading days considered to measure the average of adjusted closing price of common stock				60 days
Performance share units (PSU) | Common Stock | $20.00
Performance Share Units
Entitlement percentage of shares underlining awards, to be received and vested				50.00%
Performance share units (PSU) | Common Stock | $35.00
Performance Share Units
Average market price (in dollars per share)	$ 35.00	$ 35.00		$ 35.00
Performance share units (PSU) | Common Stock | $50.00
Performance Share Units
Average market price (in dollars per share)	$ 50.00	$ 50.00		$ 50.00
Entitlement percentage of shares underlining awards, to be received and vested				200.00%
Performance share units (PSU) | Common Stock | Senior management
Number of Shares
Unvested outstanding shares at the end of the period (in shares)	0.3	0.3	0.3	0.3	0.3
Performance share units (PSU) | Minimum | Common Stock | $20.00
Performance Share Units
Average market price (in dollars per share)	$ 20.00	$ 20.00		$ 20.00
Performance share units (PSU) | Maximum | Common Stock
Stock-based compensation
Maximum number of shares that will be issued for vested performance units	0.6	0.6		0.6
Stock options
Stock-based compensation
Vesting period					3 years
Percentage of awards other than stock options vesting on the annual anniversary date of the award					33.33%
Expiration term					10 years
Unrecognized compensation expense	$ 2.8	$ 2.8	$ 9.0	$ 2.8	$ 9.0
Weighted average remaining vesting period				1 year 2 months 12 days	1 year 3 months 18 days
Number of Shares
Granted (in shares)					0.7
Stock options | Minimum
Stock-based compensation
Exercise price (in dollars per share)					$ 7.85
Stock options | Maximum
Stock-based compensation
Exercise price (in dollars per share)					$ 9.85
Restricted Stock
Stock-based compensation
Unrecognized compensation expense	$ 5.2	$ 5.2		$ 5.2
Weighted average remaining vesting period	1 year 3 months 18 days			1 year 3 months 18 days
Weighted average grant date price (in dollars per share)	$ 8.70	$ 8.70		$ 8.70
Performance Share Units
Unrecognized compensation expense	$ 13.4	$ 13.4		$ 13.4
Restricted Stock | Directors and employees
Performance Share Units
Granted (in shares)					0.5
Number of Shares
Granted (in shares)					0.5
Restricted Stock | Employee
Stock-based compensation
Vesting period				3 years
Percentage of awards vesting on the annual anniversary date of the grant				33.33%
Restricted Stock | Non-employee director
Stock-based compensation
Vesting period				6 months
Restricted Stock | Minimum
Stock-based compensation
Grant date price (in dollars per share)	$ 6.10	$ 6.10		$ 6.10
Restricted Stock | Maximum
Stock-based compensation
Grant date price (in dollars per share)	$ 9.85	$ 9.85		$ 9.85
Plan | Common Stock
Stock-based compensation
Shares issuable under the plan							16.3	8.3
Maximum number of shares that remained reserved for issuance under the Plan	7.4	7.4		7.4		6.3

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EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Basic:
Net income (loss) available to common stockholders	$ (382,353)	$ (1,104,581)	$ (949,215)	$ (1,705,774)
Weighted average basic number of common shares outstanding	120,708	109,063	120,360	96,569
Basic net income (loss) per share of common stock (in dollars per share)	$ (3.17)	$ (10.13)	$ (7.89)	$ (17.66)
Diluted:
Net income (loss) available to common stockholders	$ (382,353)	$ (1,104,581)	$ (949,215)	$ (1,705,774)
Weighted average basic number of common shares outstanding	120,708	109,063	120,360	96,569
Weighted average diluted number of common shares outstanding	120,708	109,063	120,360	96,569
Diluted net income (loss) per share of common stock (in dollars per share)	$ (3.17)	$ (10.13)	$ (7.89)	$ (17.66)
Common stock equivalents of stock options, warrants, restricted shares, convertible debt and preferred stock, not included in the computations of diluted earnings per share of common stock as their effect would have been anti-dilutive (in shares)	44,600	48,300	45,200	48,200

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ADDITIONAL FINANCIAL STATEMENT INFORMATION (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$ 55,250	$ 55,129
Joint interest accounts	32,685	67,626
Accrued settlements on derivative contracts	23,072	47,011
Affiliated partnership	123	176
Other	1,725	3,682
Total	112,855	173,624
Prepaids and other:
Prepaids	8,643	4,585
Other	51	50
Total	8,694	4,635
Accounts payable and accrued liabilities:
Trade payables	23,357	47,261
Accrued oil and natural gas capital costs	25,356	54,651
Revenues and royalties payable	56,296	64,002
Accrued interest expense	105,782	88,499
Accrued employee compensation	4,954	2,829
Accrued lease operating expenses	16,435	20,036
Drilling advances from partners	223	7,964
Income taxes payable	9,172	9,172
Affiliated partnership	241	365
Other	373	306
Total	$ 242,189	$ 295,085

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Noncontrolling Interest, Ownership Percentage by Parent	100.00%				100.00%
Oil, natural gas and natural gas liquids sales:
Oil	$ 99,095		$ 158,110		$ 174,062	$ 282,523
Natural gas	3,159		5,578		6,901	12,537
Natural gas liquids	3,504		3,889		5,441	7,957
Total oil, natural gas and natural gas liquids sales	105,758		167,577		186,404	303,017
Other	389		447		1,092	1,201
Total operating revenues	106,147		168,024		187,496	304,218
Production:
Lease operating	16,981		25,233		37,559	59,018
Workover and other	7,915		3,731		15,706	6,845
Taxes other than income	9,753		12,903		17,011	25,144
Gathering and other	10,519		7,746		21,903	21,492
Restructuring	189		309		5,073	2,230
General and administrative	24,708		22,662		66,324	47,071
Depletion, depreciation and accretion	39,671		101,194		94,937	220,338
Full cost ceiling impairment	257,869	$ 496,900	948,633	$ 554,000	754,769	1,502,636
Other operating property and equipment impairment		$ 28,100			28,056
Total operating expenses	367,605		1,122,411		1,041,338	1,884,774
Income (loss) from operations	(261,458)		(954,387)		(853,842)	(1,580,556)
Other income (expenses):
Net gain (loss) on derivative contracts	(54,523)		(87,564)		(35,781)	12,184
Interest expense and other, net	(58,322)		(60,922)		(106,113)	(122,229)
Gain (loss) on extinguishment of debt			22,766		81,434	22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants			(8,219)			(8,219)
Total other income (expenses)	(112,845)		(133,939)		(60,460)	(95,498)
Income (loss) before income taxes	(374,303)		(1,088,326)		(914,302)	(1,676,054)
Income tax benefit (provision)			(286)			(199)
Net income (loss)	(374,303)		(1,088,612)		(914,302)	(1,676,253)	$ (1,922,621)
Series A preferred dividends	(3,198)		(4,902)		(6,396)	(9,803)
Preferred dividends and accretion on redeemable noncontrolling interest	(4,852)		(11,067)		(28,517)	(19,718)
Net income (loss) available to common stockholders	(382,353)		(1,104,581)		(949,215)	(1,705,774)
Reportable legal entities | Parent Company
Production:
General and administrative	20,243		15,097		55,840	30,352
Depletion, depreciation and accretion	367		568		769	1,192
Total operating expenses	20,610		15,665		56,609	31,544
Income (loss) from operations	(20,610)		(15,665)		(56,609)	(31,544)
Other income (expenses):
Interest expense and other, net	(77,069)		(85,042)		(155,863)	(168,760)
Gain (loss) on extinguishment of debt			22,766		81,434	22,766
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants			(8,219)			(8,219)
Total other income (expenses)	(77,069)		(70,495)		(74,429)	(154,213)
Income (loss) before income taxes	(97,679)		(86,160)		(131,038)	(185,757)
Equity in earnings of subsidiary, net of tax	(281,476)		(1,013,519)		(811,781)	(1,510,214)
Net income (loss)	(379,155)		(1,099,679)		(942,819)	(1,695,971)
Series A preferred dividends	(3,198)		(4,902)		(6,396)	(9,803)
Net income (loss) available to common stockholders	(382,353)		(1,104,581)		(949,215)	(1,705,774)
Reportable legal entities | Guarantor Subsidiaries
Oil, natural gas and natural gas liquids sales:
Oil	96,995		153,792		170,445	272,997
Natural gas	3,159		5,578		6,901	12,537
Natural gas liquids	3,504		3,889		5,441	7,957
Total oil, natural gas and natural gas liquids sales	103,658		163,259		182,787	293,491
Other	388		447		1,091	1,201
Total operating revenues	104,046		163,706		183,878	294,692
Production:
Lease operating	16,667		24,595		36,799	57,930
Workover and other	7,896		3,731		15,692	6,841
Taxes other than income	9,565		12,614		16,791	24,596
Gathering and other	10,516		7,746		21,899	21,492
Restructuring	189		309		5,073	2,230
General and administrative	4,453		7,519		10,406	16,637
Depletion, depreciation and accretion	38,397		97,572		90,528	212,198
Full cost ceiling impairment	250,753		911,496		670,828	1,451,630
Other operating property and equipment impairment					28,056
Total operating expenses	338,436		1,065,582		896,072	1,793,554
Income (loss) from operations	(234,390)		(901,876)		(712,194)	(1,498,862)
Other income (expenses):
Net gain (loss) on derivative contracts	(54,523)		(87,564)		(35,781)	12,184
Interest expense and other, net	20,786		24,734		52,753	49,566
Total other income (expenses)	(33,737)		(62,830)		16,972	61,750
Income (loss) before income taxes	(268,127)		(964,706)		(695,222)	(1,437,112)
Income tax benefit (provision)			(285)			(6,121)
Equity in earnings of subsidiary, net of tax	(13,349)		(48,528)		(116,559)	(66,981)
Net income (loss)	(281,476)		(1,013,519)		(811,781)	(1,510,214)
Net income (loss) available to common stockholders	(281,476)		(1,013,519)		(811,781)	(1,510,214)
Reportable legal entities | Non-Guarantor Subsidiary
Oil, natural gas and natural gas liquids sales:
Oil	2,100		4,318		3,617	9,526
Total oil, natural gas and natural gas liquids sales	2,100		4,318		3,617	9,526
Other	1				1
Total operating revenues	2,101		4,318		3,618	9,526
Production:
Lease operating	314		638		760	1,088
Workover and other	19				14	4
Taxes other than income	188		289		220	548
Gathering and other	3				4
General and administrative	237		723		528	1,435
Depletion, depreciation and accretion	1,188		4,386		5,414	9,770
Full cost ceiling impairment	6,835		35,805		82,167	48,184
Total operating expenses	8,784		41,841		89,107	61,029
Income (loss) from operations	(6,683)		(37,523)		(85,489)	(51,503)
Other income (expenses):
Interest expense and other, net	(2,039)		(614)		(3,003)	(3,034)
Total other income (expenses)	(2,039)		(614)		(3,003)	(3,034)
Income (loss) before income taxes	(8,722)		(38,137)		(88,492)	(54,537)
Net income (loss)	(8,722)		(38,137)		(88,492)	(54,537)
Preferred dividends and accretion on redeemable noncontrolling interest	(4,852)		(11,067)		(28,517)	(19,718)
Net income (loss) available to common stockholders	(13,574)		(49,204)		(117,009)	(74,255)
Eliminations
Production:
General and administrative	(225)		(677)		(450)	(1,353)
Depletion, depreciation and accretion	(281)		(1,332)		(1,774)	(2,822)
Full cost ceiling impairment	281		1,332		1,774	2,822
Total operating expenses	(225)		(677)		(450)	(1,353)
Income (loss) from operations	225		677		450	1,353
Other income (expenses):
Interest expense and other, net						(1)
Total other income (expenses)						(1)
Income (loss) before income taxes	225		677		450	1,352
Income tax benefit (provision)			(1)			5,922
Equity in earnings of subsidiary, net of tax	294,825		1,062,047		928,340	1,577,195
Net income (loss)	295,050		1,062,723		928,790	1,584,469
Net income (loss) available to common stockholders	$ 295,050		$ 1,062,723		$ 928,790	$ 1,584,469

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION-Balance Sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash	$ 7,173	$ 8,026
Accounts receivable	112,855	173,624
Receivables from derivative contracts	135,455	348,861
Restricted cash	17,164	16,812
Inventory	1,498	4,635
Debt issuance costs, net	5,557
Prepaids and other	8,694	4,635
Total current assets	288,396	556,593
Oil and natural gas properties (full cost method):
Evaluated	7,679,917	7,060,721
Unevaluated	1,180,148	1,641,356
Gross oil and natural gas properties	8,860,065	8,702,077
Less - accumulated depletion	(6,779,116)	(5,933,688)
Net oil and natural gas properties	2,080,949	2,768,389
Other operating property and equipment:
Gas gathering and other operating assets	100,355	130,090
Less - accumulated depreciation	(23,155)	(22,435)
Net other operating property and equipment	77,200	107,655
Other noncurrent assets:
Receivables from derivative contracts	5,642	16,614
Debt issuance costs, net		7,633
Equity in oil and natural gas partnership	11	209
Funds in escrow and other	1,613	1,599
Total assets	2,453,811	3,458,692
Current liabilities:
Accounts payable and accrued liabilities	242,189	295,085
Asset retirement obligations	412	163
Current portion of long-term debt, net	2,825,807
Total current liabilities	3,068,408	295,248
Long -term debt, net		2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts	194	290
Asset retirement obligations	48,554	46,853
Other	9,283	6,264
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest	212,503	183,986
Stockholders' equity (deficit):
Preferred stock
Common stock	12	12
Additional paid-in capital	3,288,371	3,283,097
Retained earnings (accumulated deficit)	(4,173,514)	(3,230,695)
Total stockholders' equity (deficit)	(885,131)	52,414	$ 1,772,169
Total liabilities and stockholders' equity (deficit)	2,453,811	3,458,692
Reportable legal entities | Parent Company
Current assets:
Accounts receivable		88
Restricted cash	165	138
Debt issuance costs, net	5,557
Prepaids and other	4,006	328
Total current assets	9,728	554
Other operating property and equipment:
Gas gathering and other operating assets	12,473	12,474
Less - accumulated depreciation	(9,475)	(8,705)
Net other operating property and equipment	2,998	3,769
Other noncurrent assets:
Debt issuance costs, net		7,633
Intercompany notes and accounts receivable	4,642,675	4,749,760
Funds in escrow and other	515	517
Total assets	4,655,916	4,762,233
Current liabilities:
Current portion of long-term debt, net	2,825,807
Total current liabilities	2,825,807
Long -term debt, net		2,873,637
Other noncurrent liabilities:
Deferred income taxes	1,848
Intercompany notes and accounts payable	367,525	302,096
Investment in subsidiary	2,345,867	1,534,086
Commitments and contingencies
Stockholders' equity (deficit):
Preferred stock
Common stock	12	12
Additional paid-in capital	3,288,371	3,283,097
Retained earnings (accumulated deficit)	(4,173,514)	(3,230,695)
Total stockholders' equity (deficit)	(885,131)	52,414
Total liabilities and stockholders' equity (deficit)	4,655,916	4,762,233
Reportable legal entities | Guarantor Subsidiaries
Current assets:
Cash	104	100
Accounts receivable	111,219	166,770
Receivables from derivative contracts	135,455	348,861
Inventory	1,498	4,554
Prepaids and other	4,688	4,307
Total current assets	252,964	524,592
Oil and natural gas properties (full cost method):
Evaluated	7,172,496	6,634,426
Unevaluated	1,180,148	1,566,705
Gross oil and natural gas properties	8,352,644	8,201,131
Less - accumulated depletion	(6,285,845)	(5,527,948)
Net oil and natural gas properties	2,066,799	2,673,183
Other operating property and equipment:
Gas gathering and other operating assets	87,707	117,441
Less - accumulated depreciation	(13,604)	(13,676)
Net other operating property and equipment	74,103	103,765
Other noncurrent assets:
Receivables from derivative contracts	5,642	16,614
Intercompany notes and accounts receivable	367,525	302,096
Equity in oil and natural gas partnership	11	209
Funds in escrow and other	1,098	1,082
Total assets	2,768,142	3,621,541
Current liabilities:
Accounts payable and accrued liabilities	275,141	326,655
Asset retirement obligations	412	163
Total current liabilities	275,553	326,818
Other noncurrent liabilities:
Liabilities from derivative contracts	194	290
Asset retirement obligations	47,274	45,602
Deferred income taxes	(1,848)
Intercompany notes and accounts payable	4,642,675	4,749,760
Investment in subsidiary	149,999	32,993
Other	162	164
Commitments and contingencies
Stockholders' equity (deficit):
Preferred stock
Retained earnings (accumulated deficit)	(2,345,867)	(1,534,086)
Total stockholders' equity (deficit)	(2,345,867)	(1,534,086)
Total liabilities and stockholders' equity (deficit)	2,768,142	3,621,541
Reportable legal entities | Non-Guarantor Subsidiary
Current assets:
Cash	7,069	7,926
Accounts receivable	2,401	9,985
Restricted cash	16,999	16,674
Inventory		81
Total current assets	26,469	34,666
Oil and natural gas properties (full cost method):
Evaluated	511,771	430,645
Unevaluated		74,651
Gross oil and natural gas properties	511,771	505,296
Less - accumulated depletion	(497,621)	(410,090)
Net oil and natural gas properties	14,150	95,206
Other operating property and equipment:
Gas gathering and other operating assets	175	175
Less - accumulated depreciation	(76)	(54)
Net other operating property and equipment	99	121
Other noncurrent assets:
Total assets	40,718	129,993
Current liabilities:
Accounts payable and accrued liabilities	2,269	6,102
Total current liabilities	2,269	6,102
Other noncurrent liabilities:
Asset retirement obligations	1,280	1,251
Other	9,121	6,100
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest	212,503	183,986
Stockholders' equity (deficit):
Preferred stock
Additional paid-in capital	403,678	403,678
Retained earnings (accumulated deficit)	(588,133)	(471,124)
Total stockholders' equity (deficit)	(184,455)	(67,446)
Total liabilities and stockholders' equity (deficit)	40,718	129,993
Eliminations
Current assets:
Accounts receivable	(765)	(3,219)
Total current assets	(765)	(3,219)
Oil and natural gas properties (full cost method):
Evaluated	(4,350)	(4,350)
Gross oil and natural gas properties	(4,350)	(4,350)
Less - accumulated depletion	4,350	4,350
Other noncurrent assets:
Intercompany notes and accounts receivable	(5,010,200)	(5,051,856)
Total assets	(5,010,965)	(5,055,075)
Current liabilities:
Accounts payable and accrued liabilities	(35,221)	(37,672)
Total current liabilities	(35,221)	(37,672)
Other noncurrent liabilities:
Intercompany notes and accounts payable	(5,010,200)	(5,051,856)
Investment in subsidiary	(2,495,866)	(1,567,079)
Commitments and contingencies
Stockholders' equity (deficit):
Preferred stock
Additional paid-in capital	(403,678)	(403,678)
Retained earnings (accumulated deficit)	2,934,000	2,005,210
Total stockholders' equity (deficit)	2,530,322	1,601,532
Total liabilities and stockholders' equity (deficit)	$ (5,010,965)	$ (5,055,075)

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION- Cash Flow (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$ 142,743	$ 217,530
Cash flows from investing activities:
Oil and natural gas capital expenditures	(170,258)	(407,751)
Other operating property and equipment capital expenditures	(886)	(7,478)
Funds held in escrow and other	(233)	3,012
Net cash provided by (used in) investing activities	(171,377)	(412,217)
Cash flows from financing activities:
Proceeds from borrowings	425,000	1,296,000
Repayments of borrowings	(395,648)	(1,129,000)
Debt issuance costs	(1,186)	(18,612)
Common stock issued		15,354
Restricted cash	(325)	(352)
Offering costs and other	(60)	(2,443)
Net cash provided by (used in) financing activities	27,781	160,947
Net increase (decrease) in cash	(853)	(33,740)
Cash at beginning of period	8,026	43,713
Cash at end of period	7,173	9,973
Eliminations
Cash flows from investing activities:
Advances to subsidiary	(178,978)	(27,136)
Net cash provided by (used in) investing activities	(178,978)	(27,136)
Cash flows from financing activities:
Proceeds from subsidiary	178,978	27,136
Net cash provided by (used in) financing activities	178,978	27,136
Parent Company | Reportable legal entities
Cash flows from operating activities:
Net cash provided by (used in) operating activities	(207,084)	(187,977)
Cash flows from investing activities:
Other operating property and equipment capital expenditures		(457)
Advances to subsidiary	178,978	27,136
Net cash provided by (used in) investing activities	178,978	26,679
Cash flows from financing activities:
Proceeds from borrowings	425,000	1,296,000
Repayments of borrowings	(395,648)	(1,129,000)
Debt issuance costs	(1,186)	(18,612)
Common stock issued		15,354
Offering costs and other	(60)	(2,444)
Net cash provided by (used in) financing activities	28,106	161,298
Guarantor Subsidiaries | Reportable legal entities
Cash flows from operating activities:
Net cash provided by (used in) operating activities	348,223	400,988
Cash flows from investing activities:
Oil and natural gas capital expenditures	(168,122)	(369,816)
Other operating property and equipment capital expenditures	(886)	(7,024)
Funds held in escrow and other	(233)	3,012
Net cash provided by (used in) investing activities	(169,241)	(373,828)
Cash flows from financing activities:
Proceeds from subsidiary	(178,978)	(27,136)
Net cash provided by (used in) financing activities	(178,978)	(27,136)
Net increase (decrease) in cash	4	24
Cash at beginning of period	100	15
Cash at end of period	104	39
Non-Guarantor Subsidiary | Reportable legal entities
Cash flows from operating activities:
Net cash provided by (used in) operating activities	1,604	4,519
Cash flows from investing activities:
Oil and natural gas capital expenditures	(2,136)	(37,935)
Other operating property and equipment capital expenditures		3
Net cash provided by (used in) investing activities	(2,136)	(37,932)
Cash flows from financing activities:
Restricted cash	(325)	(352)
Offering costs and other		1
Net cash provided by (used in) financing activities	(325)	(351)
Net increase (decrease) in cash	(857)	(33,764)
Cash at beginning of period	7,926	43,698
Cash at end of period	$ 7,069	$ 9,934