BATTALION OIL CORP - Quarter Report: 2016 March (Form 10-Q)

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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 March 31, 2016
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number: 001-35467

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 May 4, 2016, 122,683,698 shares of the Registrant's Common Stock were outstanding.

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PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements (Unaudited)	5
	Condensed Consolidated Statements of Operations (Unaudited) for the Three Months Ended March 31, 2016 and 2015	5
	Condensed Consolidated Balance Sheets as of March 31, 2016 (Unaudited) and December 31, 2015	6
	Condensed Consolidated Statements of Stockholders' Equity for the Three Months Ended March 31, 2016 (Unaudited) and Year Ended December 31, 2015	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 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	42
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	52
ITEM 4.	Controls and Procedures	53
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	53
ITEM 1A.	Risk Factors	54
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
ITEM 3.	Defaults Upon Senior Securities	54
ITEM 4.	Mine Safety Disclosures	54
ITEM 5.	Other Information	54
ITEM 6.	Exhibits	55
Signatures		57

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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 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:

•: 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, 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;
•: 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;

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•: 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.

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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 March 31,

	2016			2015
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	74,967		$	124,413
Natural gas		3,742			6,959
Natural gas liquids		1,937			4,068

Total oil, natural gas and natural gas liquids sales		80,646			135,440
Other		703			754

Total operating revenues		81,349			136,194

Operating expenses:
Production:
Lease operating		20,578			33,785
Workover and other		7,791			3,114
Taxes other than income		7,258			12,241
Gathering and other		11,384			13,746
Restructuring		4,884			1,921
General and administrative		41,616			24,409
Depletion, depreciation and accretion		55,266			119,144
Full cost ceiling impairment		496,900			554,003
Other operating property and equipment impairment		28,056			—

Total operating expenses		673,733			762,363

Income (loss) from operations		(592,384	)		(626,169	)
Other income (expenses):
Net gain (loss) on derivative contracts		18,742			99,748
Interest expense and other, net		(47,791	)		(61,307	)
Gain (loss) on extinguishment of debt		81,434			—

Total other income (expenses)		52,385			38,441

Income (loss) before income taxes		(539,999	)		(587,728	)
Income tax benefit (provision)		—			87

Net income (loss)		(539,999	)		(587,641	)
Series A preferred dividends		(3,198	)		(4,901	)
Preferred dividends and accretion on redeemable noncontrolling interest		(23,665	)		(8,651	)

Net income (loss) available to common stockholders	$	(566,862	)	$	(601,193	)



Net income (loss) per share of common stock:
Basic	$	(4.72	)	$	(7.16	)



Diluted	$	(4.72	)	$	(7.16	)



Weighted average common shares outstanding:
Basic		120,011			83,937



Diluted		120,011			83,937

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	March 31, 2016			December 31, 2015

Current assets:
Cash	$	8,603		$	8,026
Accounts receivable		139,245			173,624
Receivables from derivative contracts		262,493			348,861
Restricted cash		16,977			16,812
Inventory		4,761			4,635
Prepaids and other		7,923			4,635

Total current assets		440,002			556,593

Oil and natural gas properties (full cost method):
Evaluated		7,522,052			7,060,721
Unevaluated		1,270,045			1,641,356

Gross oil and natural gas properties		8,792,097			8,702,077
Less—accumulated depletion		(6,483,529	)		(5,933,688	)

Net oil and natural gas properties		2,308,568			2,768,389

Other operating property and equipment:
Gas gathering and other operating assets		100,187			130,090
Less—accumulated depreciation		(21,795	)		(22,435	)

Net other operating property and equipment		78,392			107,655

Other noncurrent assets:
Receivables from derivative contracts		13,857			16,614
Debt issuance costs, net		6,007			7,633
Equity in oil and natural gas partnership		64			209
Funds in escrow and other		1,590			1,599

Total assets	$	2,848,480		$	3,458,692



Current liabilities:
Accounts payable and accrued liabilities	$	213,615		$	295,085
Asset retirement obligations		164			163

Total current liabilities		213,779			295,248

Long-term debt, net		2,879,517			2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts		143			290
Asset retirement obligations		47,948			46,853
Other		7,238			6,264
Commitments and contingencies (Note 7)
Mezzanine equity:
Redeemable noncontrolling interest		207,651			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 March 31, 2016 and December 31, 2015, respectively		—			—
Common stock: 1,340,000,000 shares of $0.0001 par value authorized; 122,739,612 and 122,523,559 shares issued and outstanding at March 31, 2016 and December 31, 2015, respectively		12			12
Additional paid-in capital		3,286,551			3,283,097
Accumulated deficit		(3,794,359	)		(3,230,695	)

Total stockholders' equity (deficit)		(507,796	)		52,414

Total liabilities and stockholders' equity (deficit)	$	2,848,480		$	3,458,692

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Preferred Stock					Common Stock

	Preferred Stock					Common Stock					Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity (Deficit)
	Shares			Amount		Shares			Amount		Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity (Deficit)
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)		—			—		—			—		—			(539,999	)		(539,999	)
Conversion of Series A preferred stock		(23	)		—		724			—		—			—			—
Preferred dividends on redeemable noncontrolling interest		—			—		—			—		—			(3,295	)		(3,295	)
Accretion of redeemable noncontrolling interest		—			—		—			—		—			(20,370	)		(20,370	)
Reverse stock-split rounding		—			—		5			—		—			—			—
Offering costs		—			—		—			—		(10	)		—			(10	)
Long-term incentive plan forfeitures		—			—		(411	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(102	)		—		(46	)		—			(46	)
Share-based compensation		—			—		—			—		3,510			—			3,510

Balances at March 31, 2016		222		$	—		122,740		$	12	$	3,286,551		$	(3,794,359	)	$	(507,796	)

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Three Months Ended March 31,

	2016			2015
Cash flows from operating activities:
Net income (loss)	$	(539,999	)	$	(587,641	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		55,266			119,144
Full cost ceiling impairment		496,900			554,003
Other operating property and equipment impairment		28,056			—
Share-based compensation, net		2,145			4,772
Unrealized loss (gain) on derivative contracts		88,978			8,001
Amortization and write-off of deferred loan costs		1,746			1,559
Non-cash interest and amortization of discount and premium		551			1,107
Loss (gain) on extinguishment of debt		(81,434	)		—
Accrued settlements on derivative contracts		(32,882	)		(37,592	)
Other income (expense)		1,925			2,541
Change in assets and liabilities:
Accounts receivable		61,531			56,276
Inventory		(126	)		314
Prepaids and other		(3,302	)		(1,156	)
Accounts payable and accrued liabilities		(44,981	)		(27,393	)

Net cash provided by (used in) operating activities		34,374			93,935

Cash flows from investing activities:
Oil and natural gas capital expenditures		(116,759	)		(264,626	)
Other operating property and equipment capital expenditures		(646	)		(4,345	)
Funds held in escrow and other		(351	)		959

Net cash provided by (used in) investing activities		(117,756	)		(268,012	)

Cash flows from financing activities:
Proceeds from borrowings		286,000			361,000
Repayments of borrowings		(200,648	)		(217,000	)
Debt issuance costs		(1,185	)		—
Common stock issued		—			6,019
Restricted cash		(151	)		(191	)
Offering costs and other		(57	)		(853	)

Net cash provided by (used in) financing activities		83,959			148,975

Net increase (decrease) in cash		577			(25,102	)
Cash at beginning of period		8,026			43,713

Cash at end of period	$	8,603		$	18,611



Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	(17,186	)	$	(8,270	)
Asset retirement obligations		583			1,120
Series A preferred dividends paid in common stock		—			4,901
Preferred dividends on redeemable noncontrolling interest paid-in-kind		3,295			3,019
Accretion of redeemable noncontrolling interest		20,370			5,632
Common stock issued		—			2,182
Offering costs		(903	)		(78	)

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

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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.

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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 March 31, 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 $57.6 million and $87.2 million as of March 31, 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 our shift in exploration, drilling and developmental plans to our most economic areas as a result of the low commodity price environment.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 sheets. 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 assets and liabilities, net of the valuation

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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.

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HALCÓN RESOURCES CORPORATION

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 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. The Company is in the process of assessing the effects of the application of the new guidance.

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 an amount that reflects 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. 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). The amendments in ASU 2016-08 clarify the implementation guidance on principal versus agent considerations. ASU 2014-09 was also updated with ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing (ASU 2016-10). In ASU 2016-10, the FASB finalized amendments to the new revenue standard on identifying performance obligations and accounting for licenses of intellectual property. ASU 2014-09 must be applied retrospectively 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. 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.

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HALCÓN RESOURCES CORPORATION

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2. OIL AND NATURAL GAS PROPERTIES (Continued)

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 three months ended March 31, 2016 and 2015, the Company capitalized interest costs of $32.1 million and $24.6 million, respectively.

At March 31, 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 March 31, 2016 of the West Texas Intermediate (WTI) crude oil spot price of $46.26 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 March 31, 2016 of the Henry Hub natural gas price of $2.40 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 March 31, 2016 exceeded the ceiling amount by $496.9 million ($315.1 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. The impairment 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 long-term 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 March 31, 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 March 31, 2015 of the WTI spot price of $82.71 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 March 31, 2015 of the Henry Hub natural gas price of $3.88 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 March 31, 2015 exceeded the ceiling amount by $554.0 million ($348.8 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. The ceiling test impairment was driven primarily by a 13% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $94.99 per barrel at December 31, 2014.

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

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HALCÓN RESOURCES CORPORATION

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2. OIL AND NATURAL GAS PROPERTIES (Continued)

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.

3. LONG-TERM DEBT

Long-term debt as of March 31, 2016 and December 31, 2015 consisted of the following:

	March 31, 2016		December 31, 2015

	(In thousands)
Senior revolving credit facility	$	157,000	$	62,000
8.625% senior secured second lien notes due 2020⁽¹⁾		688,426		687,797
12.0% senior secured second lien notes due 2022⁽²⁾		111,365		111,598
13.0% senior secured third lien notes due 2022⁽³⁾		1,009,811		1,009,585
9.25% senior notes due 2022⁽⁴⁾		36,642		51,887
8.875% senior notes due 2021⁽⁵⁾		296,145		347,671
9.75% senior notes due 2020⁽⁶⁾		312,374		336,470
8.0% convertible note due 2020⁽⁷⁾		267,754		266,629

	$	2,879,517	$	2,873,637

⁽¹⁾: Amounts are net of $11.6 million and $12.2 million unamortized debt issuance costs at March 31, 2016 and December 31, 2015, respectively.
⁽²⁾: Amounts are net of $1.5 million and $1.2 million unamortized debt issuance costs at March 31, 2016 and December 31, 2015, respectively.
⁽³⁾: Amounts are net of $8.2 million and $8.4 million unamortized debt issuance costs at March 31, 2016 and December 31, 2015, respectively.
⁽⁴⁾: Amounts are net of $0.6 million and $0.8 million unamortized debt issuance costs at March 31, 2016 and December 31, 2015, respectively.
⁽⁵⁾: Amounts are net of a $0.9 million and a $1.0 million unamortized discount at March 31, 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 $4.5 million and $5.5 million at March 31, 2016 and December 31, 2015, respectively. Amounts are net of $4.7 million and $5.8 million unamortized debt issuance costs at March 31, 2016 and December 31, 2015, respectively. See "8.875% Senior Notes" below for more details.
⁽⁶⁾: Amounts are net of a $1.7 million and a $1.9 million unamortized discount at March 31, 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 $2.3 million and $2.6 million at March 31, 2016 and December 31, 2015, respectively. Amounts are net of $3.8 million and $4.3 million unamortized debt issuance costs at March 31, 2016 and December 31, 2015, respectively. See "9.75% Senior Notes" below for more details.
⁽⁷⁾: Amounts are net of a $21.9 million and a $23.0 million unamortized discount at March 31, 2016 and December 31, 2015, respectively. See "8.0% Convertible Note" below for more details.

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HALCÓN RESOURCES CORPORATION

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3. LONG-TERM 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 currently provides for a $1.5 billion facility with a current borrowing base of $700.0 million. Amounts borrowed under the Senior Credit Agreement will mature on August 1, 2019. The borrowing base will be 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. The borrowing base is subject to a reduction, in most cases, equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that the Company may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the term of the facility. 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 March 31, 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 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 March 31, 2016, under the effective borrowing base of $700.0 million, the Company had $157.0 million of indebtedness outstanding, $4.7 million of letters of credit outstanding and approximately $538.3 million of borrowing capacity available under the Company's Senior Credit Agreement.

At March 31, 2016, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

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 value. 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.

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3. LONG-TERM DEBT (Continued)

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 is payable on the 2022 Second Lien Notes 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, 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.

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3. LONG-TERM DEBT (Continued)

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 extinguisment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2022 Notes. As of March 31, 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.

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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 $0.9 million at March 31, 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 $4.5 million at March 31, 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 extinguisment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2021 Notes. As of March 31, 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.

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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 $1.7 million at March 31, 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 $2.3 million at March 31, 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 extinguisment of debt. At closing, the Company paid all accrued and unpaid interest since the prior interest payment date of the 2020 Notes. As of March 31, 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

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3. LONG-TERM DEBT (Continued)

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 March 31, 2016, the remaining unamortized discount was $21.9 million.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. For the three months ended March 31, 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 March 31, 2016 and December 31, 2015, the Company had approximately $36.3 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 "Long-term debt, net" within total liabilities on the unaudited condensed consolidated balance sheets.

4. 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 March 31, 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. FAIR VALUE MEASUREMENTS (Continued)

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 three months ended March 31, 2016 or the year ended December 31, 2015.

	March 31, 2016

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	276,350	$	—	$	276,350



Liabilities
Liabilities from derivative contracts	$	—	$	49	$	94	$	143

	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 5, "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)

	March 31, 2016			December 31, 2015
	(In thousands)
Beginning Balance	$	(185	)	$	(1,319	)
Net gain (loss) on derivative contracts		91			1,134

Ending Balance	$	(94	)	$	(185	)



Change in unrealized gains (losses) included in earnings related to derivatives still held at March 31, 2016 and December 31, 2015	$	91		$	(185	)

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. FAIR VALUE MEASUREMENTS (Continued)

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, long-term debt instruments as of March 31, 2016 and December 31, 2015 (excluding discounts, premiums and debt issuance costs):

	March 31, 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	$	497,000	$	700,000	$	479,500
12.0% senior secured second lien notes		112,826		80,106		112,826		77,286
13.0% senior secured third lien notes		1,017,970		307,936		1,017,970		333,385
9.25% senior notes		37,194		7,457		52,694		14,422
8.875% senior notes		297,193		59,587		348,944		95,506
9.75% senior notes		315,535		63,265		340,035		93,068
8.0% convertible note		289,669		64,017		289,669		87,393

	$	2,770,387	$	1,079,368	$	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 3, "Long-term Debt" and in Note 9, "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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. FAIR VALUE MEASUREMENTS (Continued)

derived from historical costs and management's expectation of future cost environments; consequently, the Company has designated these liabilities as Level 3. See Note 6, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

5. 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 March 31, 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 March 31, 2016, 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.

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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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. 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 March 31, 2016 and December 31, 2015:

		Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	March 31, 2016		December 31, 2015		Balance sheet location	March 31, 2016			December 31, 2015
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	262,493	$	348,861	Current liabilities—liabilities from derivative contracts	$	—		$	—
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		13,857		16,614	Other noncurrent liabilities—liabilities from derivative contracts		(143	)		(290	)

Total derivatives not designated as hedging contracts under ASC 815		$	276,350	$	365,475		$	(143	)	$	(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 March 31,

	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2016			2015
		(In thousands)
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(88,978	)	$	(8,001	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		107,720			107,749

Total net gain (loss) on derivative contracts		$	18,742		$	99,748

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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

			March 31, 2016

					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
April 2016 - June 2016	Collars	Crude Oil		91,000	$90.00	$	90.00	$96.85	$	96.85
April 2016 - December 2016	Collars	Natural Gas		550,000	4.00		4.00	4.22		4.22
April 2016 - December 2016⁽¹⁾	Collars	Crude Oil		3,300,000	60.00 - 90.00		71.91	64.00 - 95.10		77.71
April 2016 - December 2016⁽²⁾	Swaps	Crude Oil		3,575,000	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.

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 March 31, 2016 and December 31, 2015:

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	March 31, 2016			December 31, 2015			March 31, 2016			December 31, 2015
	(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	276,350		$	365,475		$	(143	)	$	(290	)
Amounts Not Offset in the Consolidated Balance Sheet		(25	)		(53	)		24			52

Net Amount	$	276,325		$	365,422		$	(119	)	$	(238	)

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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.

6. 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 three months ended March 31, 2016 (in thousands, inclusive of the current portion):


Liability for asset retirement obligations as of December 31, 2015	$	47,016
Liabilities settled and divested		(125	)
Additions		632
Acquisitions		76
Accretion expense		513

Liability for asset retirement obligations as of March 31, 2016	$	48,112

7. 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 $2.2 million and $2.0 million for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 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 $48.8 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,

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. COMMITMENTS AND CONTINGENCIES (Continued)

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 $16.7 million, which would be in lieu of the remaining $23.4 million of drilling rig commitments as of March 31, 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 March 31, 2016, the Company had in place ten 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. See Note 8, "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.

8. 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 wholly owned Delaware limited liability company (HK TMS), 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. MEZZANINE EQUITY (Continued)

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 March 31, 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 March 31, 2016, HK TMS incurred Withdrawal Exit Fees of $4.1 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 $3.0 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. MEZZANINE EQUITY (Continued)

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		974

Balance at March 31, 2016	$	7,074

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		3,295		3,295
Accretion of redeemable noncontrolling interest		—		20,370

Balances at March 31, 2016		168,934	$	207,651

For the three months ended March 31, 2016 and 2015, HK TMS issued 3,295 and 3,019 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 March 31, 2016, HK TMS incurred PIK Exit Fees totaling $4.7 million, which were recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

9. 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

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 March 31, 2016, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $4.3 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 March 31, 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

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 3, "Long-term 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 March 31, 2016 and December 31, 2015, a maximum of 7.0 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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

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 months ended March 31, 2016 and 2015, the Company recognized $2.1 million and $4.8 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 March 31, 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 March 31, 2016, the Company had $1.5 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 0.9 years. At March 31, 2015, the Company had $3.1 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 1.9 years.

Stock Options

At March 31, 2016, the Company had $3.5 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.5 years.

During the three months ended March 31, 2015, the Company granted stock options under the Plan covering 0.6 million shares of common stock to employees of the Company, with an exercise price of $9.85. 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 March 31, 2015, the Company had $11.0 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.5 years.

Restricted Stock

At March 31, 2016, the Company had $6.6 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.5 years.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

During the three months ended March 31, 2015, the Company granted 0.3 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 $9.85. 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 March 31, 2015, the Company had $15.4 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.6 years.

10. EARNINGS PER COMMON SHARE

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

	Three Months Ended March 31,

	2016			2015
Basic:
Net income (loss) available to common stockholders	$	(566,862	)	$	(601,193	)



Weighted average basic number of common shares outstanding		120,011			83,937

Basic net income (loss) per share of common stock	$	(4.72	)	$	(7.16	)



Diluted:
Net income (loss) available to common stockholders	$	(566,862	)	$	(601,193	)



Weighted average basic number of common shares outstanding		120,011			83,937
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive
Vesting of performance units		—			—
Conversion of Convertible Note		Anti-dilutive			Anti-dilutive
Conversion of Series A Preferred Stock		Anti-dilutive			Anti-dilutive

Weighted average diluted number of common shares outstanding		120,011			83,937

Diluted net income (loss) per share of common stock	$	(4.72	)	$	(7.16	)

Common stock equivalents, including stock options, warrants, restricted shares, convertible debt and preferred stock totaling 45.9 million shares for the three months ended March 31, 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 loss. Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock totaling 37.2 million shares for the three months ended March 31, 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 loss.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:

	March 31, 2016		December 31, 2015

	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	51,053	$	55,129
Joint interest accounts		52,787		67,626
Accrued settlements on derivative contracts		32,882		47,011
Affiliated partnership		—		176
Other		2,523		3,682

	$	139,245	$	173,624



Prepaids and other:
Prepaids	$	7,872	$	4,585
Other		51		50

	$	7,923	$	4,635



Accounts payable and accrued liabilities:
Trade payables	$	36,615	$	47,261
Accrued oil and natural gas capital costs		36,350		54,651
Revenues and royalties payable		57,953		64,002
Accrued interest expense		46,660		88,499
Accrued employee compensation		4,475		2,829
Accrued lease operating expenses		19,136		20,036
Drilling advances from partners		2,466		7,964
Income taxes payable		9,172		9,172
Affiliated partnership		453		365
Other		335		306

	$	213,615	$	295,085

12. 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 3, "Long-term 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 8, "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 March 31, 2016 and December 31, 2015 and for the three months ended March 31, 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

	Three Months Ended March 31, 2016

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	73,450		$	1,517		$	—		$	74,967
Natural gas		—			3,742			—			—			3,742
Natural gas liquids		—			1,937			—			—			1,937

Total oil, natural gas and natural gas liquids sales		—			79,129			1,517			—			80,646
Other		—			703			—			—			703

Total operating revenues		—			79,832			1,517			—			81,349

Operating expenses:
Production:
Lease operating		—			20,132			446			—			20,578
Workover and other		—			7,796			(5	)		—			7,791
Taxes other than income		—			7,226			32			—			7,258
Gathering and other		—			11,383			1			—			11,384
Restructuring		—			4,884			—			—			4,884
General and administrative		35,597			5,953			291			(225	)		41,616
Depletion, depreciation and accretion		402			52,131			4,226			(1,493	)		55,266
Full cost ceiling impairment		—			420,075			75,332			1,493			496,900
Other operating property and equipment impairment		—			28,056			—			—			28,056

Total operating expenses		35,999			557,636			80,323			(225	)		673,733

Income (loss) from operations		(35,999	)		(477,804	)		(78,806	)		225			(592,384	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			18,742			—			—			18,742
Interest expense and other, net		(78,794	)		31,967			(964	)		—			(47,791	)
Gain (loss) on extinguishment of debt		81,434			—			—			—			81,434

Total other income (expenses)		2,640			50,709			(964	)		—			52,385

Income (loss) before income taxes		(33,359	)		(427,095	)		(79,770	)		225			(539,999	)
Income tax benefit (provision)		—			—			—			—			—
Equity in earnings of subsidiary, net of tax		(530,305	)		(103,210	)		—			633,515			—

Net income (loss)		(563,664	)		(530,305	)		(79,770	)		633,740			(539,999	)
Series A preferred dividends		(3,198	)		—			—			—			(3,198	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(23,665	)		—			(23,665	)

Net income (loss) available to common stockholders	$	(566,862	)	$	(530,305	)	$	(103,435	)	$	633,740		$	(566,862	)

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	Three Months Ended March 31, 2015

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	—		$	119,205		$	5,208		$	—		$	124,413
Natural gas		—			6,959			—			—			6,959
Natural gas liquids		—			4,068			—			—			4,068

Total oil, natural gas and natural gas liquids sales		—			130,232			5,208			—			135,440
Other		—			754			—			—			754

Total operating revenues		—			130,986			5,208			—			136,194

Operating expenses:
Production:
Lease operating		—			33,335			450			—			33,785
Workover and other		—			3,110			4			—			3,114
Taxes other than income		—			11,982			259			—			12,241
Gathering and other		—			13,746			—			—			13,746
Restructuring		—			1,921			—			—			1,921
General and administrative		15,255			9,118			712			(676	)		24,409
Depletion, depreciation and accretion		624			114,626			5,384			(1,490	)		119,144
Full cost ceiling impairment		—			540,134			12,379			1,490			554,003

Total operating expenses		15,879			727,972			19,188			(676	)		762,363

Income (loss) from operations		(15,879	)		(596,986	)		(13,980	)		676			(626,169	)
Other income (expenses):
Net gain (loss) on derivative contracts		—			99,748			—			—			99,748
Interest expense and other, net		(83,718	)		24,832			(2,420	)		(1	)		(61,307	)

Total other income (expenses)		(83,718	)		124,580			(2,420	)		(1	)		38,441

Income (loss) before income taxes		(99,597	)		(472,406	)		(16,400	)		675			(587,728	)
Income tax benefit (provision)		—			(5,836	)		—			5,923			87
Equity in earnings of subsidiary, net of tax		(496,695	)		(18,453	)		—			515,148			—

Net income (loss)		(596,292	)		(496,695	)		(16,400	)		521,746			(587,641	)
Series A preferred dividends		(4,901	)		—			—			—			(4,901	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			—			(8,651	)		—			(8,651	)

Net income (loss) available to common stockholders	$	(601,193	)	$	(496,695	)	$	(25,051	)	$	521,746		$	(601,193	)

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS

	March 31, 2016

	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
	(In thousands)
Current assets:
Cash	$	—		$	35		$	8,568		$	—		$	8,603
Accounts receivable		—			133,152			7,377			(1,284	)		139,245
Receivables from derivative contracts		—			262,493			—			—			262,493
Restricted cash		152			—			16,825			—			16,977
Inventory		—			4,667			94			—			4,761
Prepaids and other		4,490			3,433			—			—			7,923

Total current assets		4,642			403,780			32,864			(1,284	)		440,002

Oil and natural gas properties (full cost method):
Evaluated		—			7,021,086			505,316			(4,350	)		7,522,052
Unevaluated		—			1,270,045			—			—			1,270,045

Gross oil and natural gas properties		—			8,291,131			505,316			(4,350	)		8,792,097
Less—accumulated depletion		—			(5,998,256	)		(489,623	)		4,350			(6,483,529	)

Net oil and natural gas properties		—			2,292,875			15,693			—			2,308,568

Other operating property and equipment:
Gas gathering and other operating assets		12,473			87,539			175			—			100,187
Less—accumulated depreciation		(9,107	)		(12,623	)		(65	)		—			(21,795	)

Net other operating property and equipment		3,366			74,916			110			—			78,392

Other noncurrent assets:
Receivables from derivative contracts		—			13,857			—			—			13,857
Debt issuance costs, net		6,007			—			—			—			6,007
Intercompany notes and accounts receivable		4,717,121			293,692			—			(5,010,813	)		—
Equity in oil and natural gas partnership		—			64			—			—			64
Funds in escrow and other		516			1,074			—			—			1,590

Total assets	$	4,731,652		$	3,080,258		$	48,667		$	(5,012,097	)	$	2,848,480



Current liabilities:
Accounts payable and accrued liabilities	$	—		$	245,794		$	3,559		$	(35,738	)	$	213,615
Asset retirement obligations		—			164			—			—			164

Total current liabilities		—			245,958			3,559			(35,738	)		213,779

Long-term debt, net		2,879,517			—			—			—			2,879,517
Other noncurrent liabilities:
Liabilities from derivative contracts		—			143			—			—			143
Asset retirement obligations		—			46,682			1,266			—			47,948
Deferred income taxes		1,848			(1,848	)		—			—			—
Intercompany notes and accounts payable		293,692			4,717,121			—			(5,010,813	)		—
Investment in subsidiary		2,064,391			136,427			—			(2,200,818	)		—
Other		—			166			7,072			—			7,238
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		—			—			207,651			—			207,651
Stockholders' equity (deficit):
Preferred stock		—			—			—			—			—
Common stock		12			—			—			—			12
Additional paid-in capital		3,286,551			—			403,678			(403,678	)		3,286,551
Retained earnings (accumulated deficit)		(3,794,359	)		(2,064,391	)		(574,559	)		2,638,950			(3,794,359	)

Total stockholders' equity (deficit)		(507,796	)		(2,064,391	)		(170,881	)		2,235,272			(507,796	)

Total liabilities and stockholders' equity (deficit)	$	4,731,652		$	3,080,258		$	48,667		$	(5,012,097	)	$	2,848,480

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. 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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Three Months Ended March 31, 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	$	(113,653	)	$	146,659		$	1,368		$	—			34,374
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(116,184	)		(575	)		—			(116,759	)
Other operating property and equipment capital expenditures		—			(646	)		—			—			(646	)
Advances to subsidiary		29,543			—			—			(29,543	)		—
Funds held in escrow and other		—			(351	)		—			—			(351	)

Net cash provided by (used in) investing activities		29,543			(117,181	)		(575	)		(29,543	)		(117,756	)

Cash flows from financing activities:
Proceeds from borrowings		286,000			—			—			—			286,000
Repayments of borrowings		(200,648	)		—			—			—			(200,648	)
Debt issuance costs		(1,185	)		—			—			—			(1,185	)
Restricted cash		—			—			(151	)		—			(151	)
Proceeds from subsidiary		—			(29,543	)		—			29,543			—
Offering costs and other		(57	)		—			—			—			(57	)

Net cash provided by (used in) financing activities		84,110			(29,543	)		(151	)		29,543			83,959

Net increase (decrease) in cash		—			(65	)		642			—			577
Cash at beginning of period		—			100			7,926			—			8,026

Cash at end of period	$	—		$	35		$	8,568		$	—		$	8,603

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Continued)

	Three Months Ended March 31, 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	$	(93,977	)	$	184,408		$	3,504		$	—		$	93,935
Cash flows from investing activities:
Oil and natural gas capital expenditures		—			(236,209	)		(28,417	)		—			(264,626	)
Other operating property and equipment capital expenditures		(646	)		(3,702	)		3			—			(4,345	)
Advances to subsidiary		(54,543	)		—						54,543			—
Funds held in escrow and other		—			959			—			—			959

Net cash provided by (used in) investing activities		(55,189	)		(238,952	)		(28,414	)		54,543			(268,012	)

Cash flows from financing activities:
Proceeds from borrowings		361,000			—			—			—			361,000
Repayments of borrowings		(217,000	)											(217,000	)
Common stock issued		6,019			—			—			—			6,019
Restricted cash		—			—			(191	)		—			(191	)
Proceeds from subsidiary		—			54,543			—			(54,543	)		—
Offering costs and other		(853	)		—			—			—			(853	)

Net cash provided by (used in) financing activities		149,166			54,543			(191	)		(54,543	)		148,975

Net increase (decrease) in cash		—			(1	)		(25,101	)		—			(25,102	)
Cash at beginning of period		—			15			43,698			—			43,713

Cash at end of period	$	—		$	14		$	18,597		$	—		$	18,611

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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 three months ended March 31, 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. We have acquired acreage and may acquire additional acreage in 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 quarter 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 three months of 2016, production averaged 39,527 barrels of oil equivalent (Boe) per day (Boe/d) compared to average daily production of 43,078 Boe/d during the first three months of 2015. During the first three months of 2016, we participated in the drilling of 23 gross (6.9 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 March 31, 2016 had been $41.34 per Bbl for oil and $2.23 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 $286.0 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 April 2016, with the crude oil price for April 2016 of $36.79 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 $286.0 million, primarily as a result of a decrease in our proved undeveloped reserves of approximately 33%, primarily 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 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 long-term 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. We are continuing to actively explore and evaluate various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations, including, through debt repurchases, exchanges of existing debt securities for new debt securities and exchanges or conversions of existing debt securities for new equity securities, among other options. To this end, we are currently in discussions with certain stakeholders regarding the terms upon which we could materially reduce the Company's indebtedness. The timing and outcome of these efforts is highly uncertain. One or more of these alternatives could potentially be consummated without the consent of any one or more of our current security holders and, if consummated, could be dilutive to the holders of our outstanding equity securities and adversely affect the trading prices and values of our current debt and equity securities. Although we believe that we will 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 long-term 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.

Amendment to the Senior Credit Agreement

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

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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.

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 and borrowings under our Senior Credit Agreement, which has a current borrowing base of $700.0 million and approximately $538.3 million of borrowing capacity available at March 31, 2016. Amounts borrowed under the Senior Credit Agreement will mature on August 1, 2019. Our borrowing base is redetermined on a semi-annual basis (with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations) and adjusted based on the estimated value of our oil and natural gas reserves, the amount and cost of our other indebtedness and other relevant factors. Our next redetermination is scheduled for September 1, 2016.

Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base and covenants under our Senior Credit Agreement and our senior debt indentures. Our Senior Credit Agreement contains customary financial and other 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 covenant that requires the ratio of our total secured debt to EBITDA (as defined in the Senior Credit Agreement) be no greater than 2.75 to 1.0. Pursuant to the Eleventh Amendment, the Third Lien Notes are excluded from the calculation of total secured debt to EBITDA ratio. We are also subject to additional covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test, the fixed charge coverage ratio test, applies to all indebtedness and requires that after giving effect to the incurrence of additional debt the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0. The second test allows us to incur additional indebtedness, beyond the limitations of the fixed charge coverage ratio test, as long as this additional debt is incurred under Credit Facilities (as defined in our indentures) and, in the case of certain secured indebtedness, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $950 million, (ii) the borrowing base in effect under our Senior Credit Agreement, and (iii) 30% of our adjusted consolidated net tangible assets, or ACNTA, and, in the case of unsecured indebtedness, the amount thereof is not more than the greater of the fixed sum of $750 million or 30% of our ACNTA. ACNTA is defined in all of our indentures and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to our unevaluated properties. At March 31, 2016, we had $157.0 million of indebtedness outstanding, $4.7 million of letters of credit outstanding and approximately $538.3 million of borrowing capacity

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available under our Senior Credit Agreement. At March 31, 2016, we were in compliance with the financial covenants under the Senior Credit Agreement.

Our ability to meet our debt covenants and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. For example, lower oil and natural gas prices could result in a redetermination of the borrowing base under our Senior Credit Agreement at a lower level and reduce our adjusted consolidated EBITDA, as well as our ACNTA under our indentures, and thus could reduce our ability to incur indebtedness. Our strategic divestitures of non-core producing properties in favor of investing in undeveloped acreage, coupled with our current drilling plans have also impacted our near-term ability to comply with certain debt covenants by reducing our production and reserves on a current and, for purposes of covenant calculations, a pro forma historical basis. As a consequence, we continuously monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

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 recent 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 have 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, and we continue to explore opportunities to divest non-core properties.

If, in the future, the lenders under our Senior Credit Agreement are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Senior Credit Agreement and seek alternative sources of capital to fund our business and anticipated capital expenditures. 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. Further, our failure to comply with the restrictive covenants relating to our indebtedness could result in the declaration of a default and cross default under the instruments governing our indebtedness, potentially resulting in acceleration of our obligations and adversely impacting our 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. We therefore continuously monitor our liquidity and the capital markets 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.

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We strive to maintain financial flexibility while pursuing our drilling plans and evaluating potential acquisitions, and will therefore continue to access capital markets if available on acceptable terms to, among other things, maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects while sustaining sufficient operating cash levels. Our ability to complete future debt and equity offerings and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, reserves and commodity prices, as well as various economic and market conditions that have historically affected the 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 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 82% of anticipated remaining 2016 oil production hedged at a weighted average price of $80.50 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 three months ended March 31, 2016 and 2015 were from operating and financing activities. In the first three 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:

	Three Months Ended March 31,

	2016			2015
	(In thousands)
Cash flows provided by (used in) operating activities	$	34,374		$	93,935
Cash flows provided by (used in) investing activities		(117,756	)		(268,012	)
Cash flows provided by (used in) financing activities		83,959			148,975

Net increase (decrease) in cash	$	577		$	(25,102	)

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2016 and 2015 was $34.4 million and $93.9 million, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs and realized settlements on our derivative contracts.

The $34.4 million of operating cash flows for the three months ended March 31, 2016 primarily reflect the realized settlements on our derivative contracts, which continue to mitigate decreases in revenues due to the low commodity price environment.

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The $93.9 million of operating cash flows for the three months ended March 31, 2015 primarily reflect the impact of realized settlements on our derivative contracts, which largely offset decreases in revenues due to lower commodity prices. Cash operating expenses decreased slightly 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 $117.8 million and $268.0 million for the three months ended March 31, 2016 and 2015, respectively.

During the first three months of 2016, we spent $116.8 million on oil and natural gas capital expenditures, of which $65.1 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 three months of 2015, we spent $264.6 million on oil and natural gas capital expenditures, of which $215.8 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 three months of 2015 were largely attributable to costs incurred before we slowed our drilling and completion program, but were also partially attributable to costs related to wells spud or drilled during the period.

Financing Activities. Net cash flows provided by financing activities were $84.0 million and $149.0 million for the three months ended March 31, 2016 and 2015, respectively. The primary drivers of cash provided by financing activities for the three months ended March 31, 2016 and 2015 were net borrowings on our Senior Credit Agreement.

During the first quarter 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.

In the first quarter of 2015, cash flows from financing activities were modestly impacted by sales of our common stock under the Equity Distribution Agreement. For the three months ended March 31, 2015, we sold approximately 1.0 million shares for net proceeds of approximately $8.1 million, after deducting offering expenses. Of the net proceeds of $8.1 million, approximately $2.1 million was recorded as a receivable at March 31, 2015 and was collected in April 2015.

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 $2.2 million and $2.0 million for the three months ended March 31, 2016 and 2015, respectively. As of March 31, 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 Form 10-K for the fiscal year ended

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December 31, 2015, approximating $48.8 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 operations.

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 $16.7 million, which would be in lieu of the remaining $23.4 million of drilling rig commitments as of March 31, 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 March 31, 2016, we had in place ten 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 8, "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 March 31, 2016 and 2015

We reported a net loss of $540.0 million and $587.6 million for the three months ended March 31, 2016 and 2015, respectively. The following table summarizes key items of comparison and their related change for the periods indicated.

	Three Months Ended March 31,

In thousands (except per unit and per Boe amounts)	2016			2015			Change
Net income (loss)	$	(539,999	)	$	(587,641	)	$	47,642
Operating revenues:
Oil		74,967			124,413			(49,446	)
Natural gas		3,742			6,959			(3,217	)
Natural gas liquids		1,937			4,068			(2,131	)
Other		703			754			(51	)
Operating expenses:
Production:
Lease operating		20,578			33,785			(13,207	)
Workover and other		7,791			3,114			4,677
Taxes other than income		7,258			12,241			(4,983	)
Gathering and other		11,384			13,746			(2,362	)
Restructuring		4,884			1,921			2,963
General and administrative:
General and administrative		39,471			19,637			19,834
Share-based compensation		2,145			4,772			(2,627	)
Depletion, depreciation and accretion:
Depletion—Full cost		52,941			116,611			(63,670	)
Depreciation—Other		1,812			2,093			(281	)
Accretion expense		513			440			73
Full cost ceiling impairment		496,900			554,003			(57,103	)
Other operating property and equipment impairment		28,056			—			28,056
Other income (expenses):
Net gain (loss) on derivative contracts		18,742			99,748			(81,006	)
Interest expense and other, net		(47,791	)		(61,307	)		13,516
Gain (loss) on extinguishment of debt		81,434			—			81,434
Income tax (provision) benefit		—			87			(87	)
Production:
Oil—MBbls		2,776			3,096			(320	)
Natural Gas—Mmcf		2,520			2,635			(115	)
Natural gas liquids—MBbls		401			342			59
Total MBoe⁽¹⁾		3,597			3,877			(280	)
Average daily production—Boe⁽¹⁾		39,527			43,078			(3,551	)
*Average price per unit⁽²⁾***:
Oil price—Bbl	$	27.01		$	40.19		$	(13.18	)
Natural gas price—Mcf		1.48			2.64			(1.16	)
Natural gas liquids price—Bbl		4.83			11.89			(7.06	)
Total per Boe⁽¹⁾		22.42			34.93			(12.51	)
Average cost per Boe:
Production:
Lease operating	$	5.72		$	8.71		$	(2.99	)
Workover and other		2.17			0.80			1.37
Taxes other than income		2.02			3.16			(1.14	)
Gathering and other		3.16			3.55			(0.39	)
Restructuring		1.36			0.50			0.86
General and administrative:
General and administrative		10.97			5.06			5.91
Share-based compensation		0.60			1.23			(0.63	)
Depletion		14.72			30.08			(15.36	)

(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 March 31, 2016, oil, natural gas and natural gas liquids revenues decreased $54.8 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 $34.93 per Boe to $22.42 per Boe, representing a 36% 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 8% from the prior year period, as we have curtailed our drilling in response to the decline in commodity prices.

Lease operating expenses decreased $13.2 million for the three months ended March 31, 2016. On a per unit basis, lease operating expenses were $5.72 per Boe for the three months ended March 31, 2016, compared to $8.71 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 $4.7 million to $7.8 million for the three months ended March 31, 2016 as compared to the same period in 2015. The increased costs from the prior year relate primarily to the installation of electric submersible pumps to stimulate production in our Bakken area. On a per unit basis, workover and other expenses were $2.17 per Boe for the three months ended March 31, 2016, compared to $0.80 per Boe for the same period in 2015.

Taxes other than income decreased $5.0 million for the three months ended March 31, 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 $2.02 per Boe and $3.16 per Boe for the three months ended March 31, 2016 and 2015, respectively.

Gathering and other expenses for the three months ended March 31, 2016 and 2015 were $11.4 million and $13.7 million, respectively. Approximately $7.8 million and $7.5 million of expenses incurred for the three months ended March 31, 2016 and 2015, respectively, relate to gathering and other fees paid on our oil and natural gas production. Also included are $3.2 million and $6.0 million of rig stacking charges (including any termination penalties) for the three months ended March 31, 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 March 31, 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 $4.9 million and $1.9 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees during the three months ended March 31, 2016 and 2015, respectively.

General and administrative expense for the three months ended March 31, 2016 increased to $39.5 million from $19.6 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, and increases in professional fees totaling $23.3 million, offset by a reduction in our payroll and employee related benefits costs of $3.4 million due to a reduction in workforce. On a per unit basis, general and administrative expenses were $10.97 per Boe and $5.06 per Boe, for the three months ended March 31, 2016 and 2015, respectively.

Share-based compensation expense for the three months ended March 31, 2016 was $2.1 million, a decrease of $2.6 million compared to the same period in 2015. The decrease results from forfeitures since the prior year period and no new grants awarded during the three months ended March 31, 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 $63.7 million over the prior year period. On a per unit basis, depletion expense was $14.72 per Boe for the three months ended March 31, 2016 compared to $30.08 per Boe for the three months ended March 31, 2015. The decrease in depletion expense and the depletion rate per Boe is attributable to decreases in the amortizable base due to the 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 $496.9 million for the three months ended March 31, 2016. The impairment reflects additional transfers of the remaining unevaluated Utica / Point Pleasant (Utica) and 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. We consider the facts and circumstances around our 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 our Utica or TMS acreage positions in advance of the related lease expirations due to our evaluation of strategic alternatives to reduce our long-term debt while preserving liquidity in light of continued low commodity prices, together with a reduction of our exploration department and our intent to expend capital only on our most economical and proven areas. We recorded a full cost ceiling test impairment before income taxes of $554.0 million for the three months ended March 31, 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 were $94.99 and $82.71 per barrel at December 31, 2014 and March 31, 2015, respectively. 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 review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the three months ended March 31, 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 record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At March 31, 2016, we had a $276.4 million derivative asset, $262.5 million of which was classified as current, and we had a $0.1 million derivative liability, all of which was classified as non-current associated with these contracts. We recorded a net derivative gain of $18.7 million ($89.0 million net unrealized loss and $107.7 million net realized gain on settled contracts) for the three months ended March 31, 2016 compared to a net derivative gain of $99.7 million ($8.0 million net unrealized loss and $107.7 million net realized gain on settled contracts), in the same period in 2015.

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Interest expense and other decreased $13.5 million for the three months ended March 31, 2016 from the same period in 2015. Capitalized interest for the three months ended March 31, 2016 and 2015 was $32.1 million and $24.7 million, respectively. The increase in capitalized interest was driven by an increase in our weighted average interest rate from 8.2% in the prior year period to 10.3% in the current year period, primarily reflecting the 2022 Second Lien Notes and the Third Lien Notes issued at 12% and 13%, respectively, since the prior year period. Interest expense subject to capitalization decreased to $78.8 million in the three months ended March 31, 2016 from $83.7 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.

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 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.

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.

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.

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Condensed Consolidated Financial Statements (Unaudited)—Note 5, "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 4, "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 March 31, 2016, the principal amount of our long-term debt was approximately $2.8 billion, of which approximately 95% bears interest at a weighted average fixed interest rate of 10.5% per year. The remaining 5% of our total long-term debt at March 31, 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 March 31, 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 March 31, 2016 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.5 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 March 31, 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 March 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

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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.

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.

		Average Price Paid Per Share

January 2016	—	$	—	—	—
February 2016	75,125		0.49	—	—
March 2016	26,451		0.98	—	—

(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 March 31, 2016, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $4.3 million.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

On May 2, 2016, we were informed by the New York Stock Exchange (the NYSE), that we had regained compliance with the NYSE's $1.00 per share minimum stock price requirement on the basis of trading in our common stock for 30-trading day period ended April 29, 2016. We previously reported falling out of compliance on a Current Report on Form 8-K filed August 28, 2015.

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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		Thirteenth Amendment to Senior Revolving Credit Agreement, dated as of March 17, 2016, among Halcón Resources Corporation, as borrower, each of the lenders from time to time party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed March 17, 2016).

10.2	†	Key Employee Retention Agreement between Floyd C. Wilson and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.37 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.3	†	Key Employee Retention Agreement between Stephen W. Herod and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.38 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.4	†	Key Employee Retention Agreement between Mark J. Mize and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.39 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.5	†	Key Employee Retention Agreement between David S. Elkouri and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.40 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.6	†	Second Amended and Restated Summary of Non-Employee Director Compensation adopted on March 9, 2016 (Incorporated by reference to Exhibit 10.25 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.7	†	Amended and Restated Stock Ownership Guidelines Policy adopted on February 25, 2015 (Incorporated by reference to Exhibit 10.26 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

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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

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.
†: Indicates management contract or compensatory plan or arrangement.

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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
May 9, 2016	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer
May 9, 2016	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
May 9, 2016	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Senior Vice President, Chief Accounting Officer and Controller