BATTALION OIL CORP - Quarter Report: 2014 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, 2014
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 ý		Accelerated Filer o		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 5, 2014, 420,476,893 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, 2014 and 2013	5
	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2014 and December 31, 2013	6
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Three Months Ended March 31, 2014 and Year Ended December 31, 2013	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 2014 and 2013	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	35
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	43
ITEM 4.	Controls and Procedures	44
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	45
ITEM 1A.	Risk Factors	45
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
ITEM 3.	Defaults Upon Senior Securities	47
ITEM 4.	Mine Safety Disclosures	47
ITEM 5.	Other Information	47
ITEM 6.	Exhibits	48
Signatures		52

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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 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, 2013, 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:

•: 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 will divert management's time and energy, which could have an adverse effect on our financial position, results of operations, or cash flows;
•: risks in connection with potential acquisitions and the integration of significant acquisitions;
•: 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 successfully develop our large inventory of undeveloped acreage in our resource plays;
•: access to and availability of water and other treatment materials to carry out planned 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, which is necessary to fully execute our capital program;
•: 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;
•: volatility in commodity prices for oil and natural gas;
•: our ability to replace our oil and natural gas reserves;
•: 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;
•: our ability to retain key members of senior management and key technical employees;

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•: competition, including competition for acreage in resource play holdings;
•: environmental risks;
•: drilling and operating risks;
•: exploration and development risks;
•: the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations);
•: general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;
•: social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or acts of terrorism or sabotage;
•: other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;
•: the insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;
•: 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,

	2014			2013
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	256,029		$	180,827
Natural gas		9,409			5,669
Natural gas liquids		8,759			3,828


Total oil, natural gas and natural gas liquids sales		274,197			190,324
Other		952			530


Total operating revenues		275,149			190,854


Operating expenses:
Production:
Lease operating		36,638			25,304
Workover and other		2,789			1,624
Taxes other than income		24,160			17,436
Gathering and other		5,073			333
Restructuring		987			671
General and administrative		32,798			31,597
Depletion, depreciation and accretion		119,908			81,858
Full cost ceiling impairment		61,165			—


Total operating expenses		283,518			158,823


Income (loss) from operations		(8,369	)		32,031
Other income (expenses):
Net gain (loss) on derivative contracts		(33,656	)		(18,422	)
Interest expense and other, net		(30,939	)		(4,850	)


Total other income (expenses)		(64,595	)		(23,272	)


Income (loss) before income taxes		(72,964	)		8,759
Income tax benefit (provision)		—			(3,294	)


Net income (loss)		(72,964	)		5,465
Series A preferred dividends		(4,959	)		—


Net income (loss) available to common stockholders	$	(77,923	)	$	5,465




Net income (loss) per share of common stock:
Basic	$	(0.19	)	$	0.02




Diluted	$	(0.19	)	$	0.01




Weighted average common shares outstanding:
Basic		413,521			346,139




Diluted		413,521			383,565

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, 2014			December 31, 2013

Current assets:
Cash	$	366		$	2,834
Accounts receivable		309,304			312,518
Receivables from derivative contracts		1,214			2,028
Inventory		4,868			5,148
Prepaids and other		11,436			16,098


Total current assets		327,188			338,626


Oil and natural gas properties (full cost method):
Evaluated		5,382,235			4,960,467
Unevaluated		2,110,612			2,028,044


Gross oil and natural gas properties		7,492,847			6,988,511
Less—accumulated depletion		(2,367,926	)		(2,189,515	)


Net oil and natural gas properties		5,124,921			4,798,996


Other operating property and equipment:
Gas gathering and other operating assets		137,849			125,837
Less—accumulated depreciation		(10,441	)		(8,461	)


Net other operating property and equipment		127,408			117,376


Other noncurrent assets:
Receivables from derivative contracts		14,243			22,734
Debt issuance costs, net		62,350			64,308
Deferred income taxes		4,505			8,474
Equity in oil and natural gas partnership		5,294			4,463
Funds in escrow and other		10,225			1,514


Total assets	$	5,676,134		$	5,356,491




Current liabilities:
Accounts payable and accrued liabilities	$	652,203		$	636,589
Liabilities from derivative contracts		32,890			17,859
Asset retirement obligations		141			71
Current portion of deferred income taxes		4,505			8,474
Current portion of long-term debt		1,389			1,389


Total current liabilities		691,128			664,382


Long-term debt		3,533,193			3,183,823
Other noncurrent liabilities:
Liabilities from derivative contracts		21,018			19,333
Asset retirement obligations		38,834			39,186
Other		11,157			2,157
Commitments and contingencies (Note 8)
Stockholders' equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 345,000 shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding as of March 31, 2014 and December 31, 2013		—			—
Common stock: 670,000,000 shares of $0.0001 par value authorized; 420,521,463 and 415,729,962 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively		41			41
Additional paid-in capital		2,964,903			2,953,786
Accumulated deficit		(1,584,140	)		(1,506,217	)


Total stockholders' equity		1,380,804			1,447,610


Total liabilities and stockholders' equity	$	5,676,134		$	5,356,491

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								Treasury Stock

	Preferred Stock				Common Stock					Additional Paid-In Capital			Treasury Stock						Accumulated Deficit			Stockholders' Equity
	Shares		Amount		Shares			Amount		Additional Paid-In Capital			Shares			Amount			Accumulated Deficit			Stockholders' Equity
Balances at December 31, 2012		—	$	—		259,802		$	26	$	1,681,717			1,650		$	(9,298	)	$	(274,463	)	$	1,397,982
Net income (loss)		—		—		—			—		—			—			—			(1,222,662	)		(1,222,662	)
Dividends on Series A preferred stock		—		—		2,045			—		9,092			—			—			(9,092	)		—
Preferred stock conversion		—		—		108,801			11		695,227			—			—			—			695,238
Sale of Series A preferred stock		345		—		—			—		345,000			—			—			—			345,000
Common stock issuance		—		—		43,700			4		222,866			—			—			—			222,870
Offering costs		—		—		—			—		(17,346	)		—			—			—			(17,346	)
Long-term incentive plan grants		—		—		3,267			—		—			—			—			—			—
Long-term incentive plan forfeitures		—		—		(205	)		—		—			—			—			—			—
Reduction in shares to cover individuals' tax withholding		—		—		(30	)		—		(148	)		—			—			—			(148	)
Retirement of shares in treasury		—		—		(442	)		—		(2,492	)		(442	)		2,492			—			—
Long-term incentive plan grants issued out of treasury		—		—		(1,208	)		—		(6,806	)		(1,208	)		6,806			—			—
Share-based compensation		—		—		—			—		26,676			—			—			—			26,676


Balances at December 31, 2013		345	$	—		415,730		$	41	$	2,953,786			—		$	—		$	(1,506,217	)	$	1,447,610
Net income (loss)		—		—		—			—		—			—			—			(72,964	)		(72,964	)
Dividends on Series A preferred stock		—		—		1,394			—		4,959			—			—			(4,959	)		—
Offering costs		—		—		—			—		45			—			—			—			45
Long-term incentive plan grants		—		—		3,568			—		—			—			—			—			—
Long-term incentive plan forfeitures		—		—		(68	)		—		—			—			—			—			—
Reduction in shares to cover individuals' tax withholding		—		—		(103	)		—		(389	)		—			—			—			(389	)
Share-based compensation		—		—		—			—		6,502			—			—			—			6,502


Balances at March 31, 2014		345	$	—		420,521		$	41	$	2,964,903			—		$	—		$	(1,584,140	)	$	1,380,804

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,

	2014			2013
Cash flows from operating activities:
Net income (loss)	$	(72,964	)	$	5,465
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		119,908			81,858
Full cost ceiling impairment		61,165			—
Deferred income tax provision (benefit)		—			(999	)
Share-based compensation, net		4,332			2,335
Unrealized loss (gain) on derivative contracts		26,021			16,071
Amortization and write-off of deferred loan costs		842			265
Non-cash interest and amortization of discount and premium		554			866
Other income (expense)		354			(1,013	)
Change in assets and liabilities, net of acquisitions:
Accounts receivable		12,062			(50,746	)
Inventory		280			(1,033	)
Prepaids and other		4,662			3,924
Accounts payable and accrued liabilities		2,284			(11,283	)


Net cash provided by (used in) operating activities		159,500			45,710


Cash flows from investing activities:
Oil and natural gas capital expenditures		(432,783	)		(380,117	)
Acquisition of Williston Basin Assets		—			(29,895	)
Other operating property and equipment capital expenditures		(16,036	)		(36,340	)
Advance on carried interest		(62,500	)		—
Funds held in escrow and other		1,821			1,328


Net cash provided by (used in) investing activities		(509,498	)		(445,024	)


Cash flows from financing activities:
Proceeds from borrowings		614,000			844,000
Repayments of borrowings		(266,000	)		(434,476	)
Debt issuance costs		(126	)		(11,483	)
Offering costs and other		(344	)		(431	)


Net cash provided by (used in) financing activities		347,530			397,610


Net increase (decrease) in cash		(2,468	)		(1,704	)
Cash at beginning of period		2,834			2,506


Cash at end of period	$	366		$	802




Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	(4,763	)	$	9,569
Asset retirement obligations		(730	)		1,512
Series A preferred dividends paid in common stock		4,959			—

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 2013 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC). Please refer to the notes in the 2013 Annual Report on Form 10-K when reviewing interim financial results.

During the year ended 2013, the Company determined that "Net cash provided by operating activities" and "Net cash used in investing activities" for the three month period ended March 31, 2013 were both overstated by $9.6 million as a result of the inclusion of capitalized non-cash interest in the change in "Accounts payable and accrued liabilities" line item in operating cash flows and "Oil and natural gas capital expenditures" and "Other operating property and equipment capital expenditures" in investing cash flows. The Company has corrected the error, which had no impact to the net cash flows for the period, and provided related supplemental non-cash information in the accompanying unaudited condensed consolidated statements of cash flows for the three month period ended March 31, 2013.

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

accordance with accounting principles generally accepted in the United States, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Accounts Receivable and Allowance for Doubtful Accounts

The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. There were no allowances for doubtful accounts as of March 31, 2014 or December 31, 2013.

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 estimated useful life. 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 $101.2 million and $92.0 million as of March 31, 2014 and December 31, 2013, respectively, related to the construction of its gas gathering systems.

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; trailers, seven years; heavy equipment, ten years; an airplane and 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 its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company 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.

Recently Issued Accounting Pronouncements

In February 2013, the FASB issued ASU No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU 2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

obligations resulting from joint and several liability arrangements, such as debt arrangements, other contractual obligations and settled litigation and judicial rulings. This pronouncement must be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of ASU 2013-04 did not have an impact to the Company's operating results, financial position and disclosures.

In February 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU 2013-11). ASU 2013-11 provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This pronouncement should be applied prospectively to all unrecognized tax benefits that exist at the effective date and retrospective application is permitted. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this pronouncement did not have an impact to the Company's operating results and financial position.

2. ACQUISITIONS AND DIVESTITURES

Divestitures

Non-core Properties

During the third quarter of 2013, the Company entered into three separate purchase and sale agreements with unrelated parties to divest parcels of non-core properties located in the United States for total consideration of approximately $302.0 million, all of which closed by December 31, 2013. The transactions and consideration are subject to customary closing conditions and adjustments, with an effective date of July 1, 2013. Proceeds from the sales were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

Eagle Ford Assets

On July 19, 2013, the Company completed the sale of its interest in Eagle Ford assets located in Fayette and Gonzales Counties, Texas, previously acquired as part of the merger with GeoResources, Inc. (the Merger), to private buyers for proceeds of approximately $147.9 million, before post-closing adjustments. The transaction had an effective date of January 1, 2013. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

3. OIL AND NATURAL GAS PROPERTIES

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. OIL AND NATURAL GAS PROPERTIES (Continued)

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

Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that are excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the unaudited condensed consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. For the three months ended March 31, 2014 and 2013, the Company capitalized interest costs of $46.6 million and $52.2 million, respectively.

At March 31, 2014, 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, 2014 of the West Texas Intermediate (WTI) spot price of $98.46 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, 2014 of the Henry Hub price of $3.99 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, 2014 exceeded the ceiling amount by $61.2 million ($39.0 million after taxes) which resulted in a ceiling test impairment of that amount for the quarter. The Company recorded the full cost ceiling test impairment in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

At March 31, 2013, the ceiling test value of the Company's reserves was calculated based on the first day average of the 12-months ended March 31, 2013 of the WTI spot price of $92.63 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended March 31, 2013 of the Henry Hub price of $2.95 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, 2013 did not exceed the ceiling amount.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT

Long-term debt as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014⁽¹⁾		December 31, 2013⁽¹⁾

	(In thousands)
Senior revolving credit facility	$	348,000	$	—
9.25% senior notes due 2022		400,000		400,000
8.875% senior notes due 2021⁽²⁾		1,371,791		1,372,355
9.75% senior notes due 2020⁽³⁾		1,152,029		1,152,099
8.0% convertible note due 2017⁽⁴⁾		261,373		259,369


	$	3,533,193	$	3,183,823

⁽¹⁾: Table excludes $1.4 million of deferred premiums on derivative contracts which were classified as current at March 31, 2014 and December 31, 2013.
⁽²⁾: Amounts are net of a $5.0 million and a $5.1 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $26.8 million and $27.5 million at March 31, 2014 and December 31, 2013, respectively. See "8.875% Senior Notes" below for more details.
⁽³⁾: Amounts are net of a $8.6 million and a $8.9 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2020 Notes. On December 19, 2013, the Company completed the issuance of an additional $400 million principal amount of these notes. The unamortized premium related to these additional 2020 Notes was approximately $10.6 million and $11.0 million at March 31, 2014 and December 31, 2013, respectively. See "9.75% Senior Notes" below for more details.
⁽⁴⁾: Amount is net of a $28.3 million and a $30.3 million unamortized discount at March 31, 2014 and December 31, 2013, respectively. See "8.0% Convertible Note" below for more details.

Senior Revolving Credit Facility

On February 8, 2012, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Senior Credit Agreement provides for a $1.5 billion facility with a current borrowing base of $800.0 million. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. 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 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 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 five-year

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

term of the facility. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's 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 minimum coverage of interest expenses of i) not less than 2.0 to 1.0 through December 31, 2014 (pursuant to the Seventh Amendment, discussed below) and ii) not less than 2.5 to 1.0 for subsequent periods.

At March 31, 2014, under the borrowing base of $800.0 million, the Company had $348.0 million of indebtedness outstanding, $1.2 million of letters of credit outstanding and $450.8 million of borrowing capacity available under the Senior Credit Agreement, of which approximately $332 million was available under the indebtedness limitation in the Company's indentures.

On October 31, 2013, the Company entered into the Sixth Amendment to the Senior Credit Agreement , which, amount other things, provides for EBITDA (as defined in the Senior Credit Agreement) to be annualized for the next three fiscal quarters for purposes of measuring compliance with the interest coverage test. Specifically, (i) for the fiscal quarter ended December 31, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the three month period then ended multiplied by 4; (ii) for the fiscal quarter ended March 31, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the six month period then ended multiplied by 2; and (iii) for the fiscal quarter ended June 30, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the nine month period then ended multiplied by 1.333.

On March 21, 2014, the Company entered into the Seventh Amendment to its Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment increased the borrowing base to $800.0 million in connection with the Company's annual spring redetermination and also provided the Company additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

At March 31, 2014, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

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 commissions and offering 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, rank equally with all of its current and future senior indebtedness and are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

one minor subsidiary. Halcón, the issuer of the 2022 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In connection with the sales of the 2022 Notes, the Company entered into registration rights agreements, pursuant to which the Company agreed to conduct a registered exchange offer for the 2022 Notes or cause to become effective a shelf registration statement providing for the resale of the 2022 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement and use its reasonable best efforts to cause such registration statement for the 2022 Notes to become effective, (b) promptly following the effectiveness of such registration statement, offer to exchange new registered notes having terms substantially identical to the 2022 Notes for outstanding 2022 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2022 Notes. If the exchange offer is not consummated within 365 days after August 13, 2013, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2022 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the registration rights agreements it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2022 Notes. On March 14, 2014, the Company filed a registration statement on Form S-4 with the SEC relating to the offer to exchange registered 9.25% senior notes due 2022 for any and all of its 2022 Notes and, on April 18, 2014, the Company commenced such offer to exchange.

On or before August 15, 2016, the Company may redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.250% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2022 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the related equity offering. In addition, at any time prior to August 15, 2017, the Company may redeem some or all of the 2022 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at August 15, 2017, plus (ii) any required interest payments due on the notes through August 15, 2017 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

The indenture governing the 2022 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

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 the initial purchasers' discounts, commissions and offering expenses) were used to fund a portion of the cash consideration paid in the acquisition of two wholly-owned subsidiaries of Petro-Hunt Holdings, LLC and Pillar Holdings, LLC, which owned acreage prospective for the Bakken / Three Forks formations located in North Dakota, in Williams, Mountrail, McKenzie and Dunn Counties.

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 the initial purchasers' premiums, commissions and offering 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 Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of the Company 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 one minor subsidiary. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

On June 4, 2013, the Company completed a registered exchange offer of outstanding 2021 Notes for new registered notes having terms substantially identical to the 2021 Notes.

On or before November 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds of certain equity offerings at a redemption price of 108.875% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2021 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the date of closing of the related equity offering. In addition, at any time prior to November 15, 2016, the Company may redeem some or all of the 2021 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at November 15, 2016, plus (ii) any required interest payments due on the notes through November 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

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 $5.0 million at March 31, 2014. 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 $26.8 million at March 31, 2014.

The indenture governing the 2021 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

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 the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Merger 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 $406.1 million (after the initial purchasers' fees, commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of the Company and 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

subsidiaries, except for one minor subsidiary. Halcón, the issuer of the 2020 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

On June 4, 2013, the Company completed a registered exchange offer of the outstanding 2020 Notes originally issued, for new registered notes having terms substantially identical to the original 2020 Notes. In connection with the sales of the additional 2020 Notes, the Company entered into registration rights agreements, pursuant to which the Company agreed to conduct a registered exchange offer for the 2020 Notes or cause to become effective a shelf registration statement providing for the resale of the 2020 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement and use its reasonable best efforts to cause such registration statement for the 2020 Notes to become effective, (b) promptly following the effectiveness of such registration statement, offer to exchange new registered notes having terms substantially identical to the 2020 Notes for outstanding 2020 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2020 Notes. If the exchange offer is not consummated within 180 days after December 19, 2013, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2020 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the registration rights agreements it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2020 Notes. On March 14, 2014, the Company filed a registration statement on Form S-4 with the SEC relating to the offer to exchange registered 9.75% senior notes due 2020 for any and all of its 2020 Notes and, on April 18, 2014, the Company commenced such offer to exchange.

On or before July 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.750% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2020 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the equity offering. In addition, at any time prior to July 15, 2016, the Company may redeem some or all of the 2020 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess , if any of (a) the present value at such time of (i) the redemption price of such note at July 15, 2016, plus (ii) any required interest payments due on the notes through July 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

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 $8.6 million at March 31, 2014. 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 $10.6 million at March 31, 2014.

The indenture governing the 2020 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes to incur

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4. LONG-TERM DEBT (Continued)

indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

8.0% Convertible Note

On February 8, 2012, the Company issued the 2017 Note in the principal amount of $275.0 million together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. The 2017 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 and matures on February 8, 2017. 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 2017 Note, all or any portion of the interest due on the 2017 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 during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. The Company did not elect to pay-in-kind interest for the quarterly payments due subsequent to September 30, 2012. As of February 8, 2014, holders of the 2017 Note became entitled to convert at their election each $4.50 of principal and accrued but unpaid interest into one share of the Company's common stock. The 2017 Note is a senior unsecured obligation of the Company.

The Company allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, the Company recorded a discount of $43.6 million to be amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $28.3 million at March 31, 2014.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

Promissory Notes

On December 28, 2012, the Company completed the acquisition of certain oil and natural gas properties in Brazos County, Texas for approximately $83.7 million, before and subject to, customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. During the three months ended March 31, 2013, the Company completed its review of the properties and paid approximately $62.4 million during the period for properties deemed to have clear title and no defects. In addition, notice was given to the sellers of the Company's assertion of title and environmental defects amounting to $12.9 million for the remaining properties. During the three months ended September 30, 2013, the title and environmental defects were cured by the sellers and the Company paid the remaining portion of the purchase price.

In conjunction with the issuance of the promissory notes in December 2012, the Company recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. The Company expensed the discount during the first quarter of 2013.

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. During the first three months of 2014, the Company capitalized approximately $0.1 million in costs associated with the issuance of the additional 2020 Notes. At March 31, 2014 and December 31, 2013, the Company had approximately $62.4 million and $64.3 million, respectively, of unamortized debt issuance costs.

5. FAIR VALUE MEASUREMENTS

Pursuant to 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, 2014 and December 31, 2013. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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5. FAIR VALUE MEASUREMENTS (Continued)

There were no transfers between fair value hierarchy levels for the three months ended March 31, 2014.

	March 31, 2014

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	15,457	$	—	$	15,457




Liabilities
Liabilities from derivative contracts	$	—	$	51,124	$	2,784	$	53,908

	December 31, 2013

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	24,762	$	—	$	24,762




Liabilities
Liabilities from derivative contracts	$	—	$	34,376	$	2,816	$	37,192

Derivative contracts listed above as Level 2 include collars, swaps and put options 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 markets prices and implied volatility factors related to changes in the forward curves. See Note 6, "Derivative and Hedging Activities" for additional discussion of derivatives.

Derivative contracts listed above as Level 3 include extendable collars that are carried at fair value. The significant unobservable inputs for these Level 3 contracts include unpublished forward strip prices

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5. FAIR VALUE MEASUREMENTS (Continued)

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 (in thousands):

	Significant Unobservable Inputs (Level 3)

	March 31, 2014			December 31, 2013
Beginning Balance	$	(2,816	)	$	—
Net gain (loss) on derivative contracts		32			(2,816	)
Settlements		—			—
Purchase of derivative contracts		—			—
Buy out of derivative contracts		—			—


Ending Balance	$	(2,784	)	$	(2,816	)




Change in unrealized gains (losses) included in earnings related to derivatives still held at March 31, 2014 and December 31, 2013	$	32		$	(2,816	)

As of March 31, 2014 and December 31, 2013, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a 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. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in the Company's Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

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 receivable and accounts payable approximates 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, 2014 and December 31, 2013 (excluding discounts, premiums and deferred premiums on derivative contracts):

	March 31, 2014				December 31, 2013

	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
9.25% $400 million senior notes	$	400,000	$	416,924	$	400,000	$	407,432
8.875% $1.35 billion senior notes		1,350,000		1,401,975		1,350,000		1,390,500
9.75% $1.15 billion senior notes		1,150,000		1,242,000		1,150,000		1,197,438
8.0% $289.7 million convertible note		289,669		393,423		289,669		368,418


	$	3,189,669	$	3,454,322	$	3,189,669	$	3,363,788

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. FAIR VALUE MEASUREMENTS (Continued)

The fair value of the Company's fixed interest debt instruments was calculated using Level 2 criteria at March 31, 2014 and December 31, 2013. 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.

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

6. DERIVATIVE AND HEDGING ACTIVITIES

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to economically hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company 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. Historically, the Company has also entered into interest rate swaps to mitigate exposure to market rate fluctuations. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company's policy to enter into derivative contracts, including interest rate derivatives, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in its Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Company's Senior Credit Agreement.

At March 31, 2014 and December 31, 2013, the Company's crude oil and natural gas derivative positions consisted of swaps, swaptions, costless put/call "collars," extendable costless collars and put options. 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. 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. A sold put option limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. The Company has elected to not 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 all payments

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

At March 31, 2014, the Company had 90 open commodity derivative contracts summarized in the following tables: 11 natural gas collar arrangements, 58 crude oil collar arrangements, two crude oil three-way collars, one crude oil put option, and eight crude oil swaps, eight crude oil swaptions and two crude oil extendable collars.

At December 31, 2013, the Company had 86 open commodity derivative contracts summarized in the following tables: 10 natural gas collar arrangements, 52 crude oil collar arrangements, five crude oil three-way collars, one crude oil put option, eight crude oil swaps, eight crude oil swaptions and two crude oil extendable collars.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013:

		Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	March 31, 2014		December 31, 2013		Balance sheet location	March 31, 2014			December 31, 2013
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	1,214	$	2,028	Current liabilities—liabilities from derivative contracts	$	(32,890	)	$	(17,859	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		14,243		22,734	Other noncurrent liabilities—liabilities from derivative contracts		(21,018	)		(19,333	)


Total derivatives not designated as hedging contracts under ASC 815		$	15,457	$	24,762		$	(53,908	)	$	(37,192	)

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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		2014			2013
		(In thousands)
Commodity contracts:
Unrealized gain (loss) oncommodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(26,916	)	$	(16,799	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		(6,740	)		(1,623	)


Total net gain (loss) on derivative contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(33,656	)	$	(18,422	)

At March 31, 2014 and December 31, 2013, the Company had the following open crude oil and natural gas derivative contracts:

			March 31, 2014

					Floors				Ceilings				Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500	$	95.00	$	95.00	$	98.20 - 101.00	$	99.13	$	70.00	$	70.00
April 2014 - June 2014	Collars	Crude Oil		364,000		90.00		90.00		96.50 - 99.50		98.00
April 2014 - December 2014	Collars	Crude Oil		5,706,250		85.00 - 95.00		88.67		93.60 - 108.45		96.27
April 2014 - December 2014	Collars	Natural Gas		8,937,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015⁽¹⁾	Collars	Crude Oil		5,475,000		82.50 - 90.00		86.00		90.00 - 100.25		94.34
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015⁽²⁾	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
July 2015 - December 2015	Collars	Crude Oil		644,000		85.00		85.00		90.00 - 90.50		90.16
January 2016 - December 2016	Collars	Natural Gas		732,000		4.00		4.00		4.22		4.22
January 2016 - December 2016⁽³⁾	Swaps	Crude Oil		2,196,000		88.00 - 88.87		88.30

⁽¹⁾: Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 732,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 366,000 Bbls for the year ended December 31, 2016.
⁽²⁾: Includes an outstanding crude oil swap of which may be extended at a price of $91.25 per Bbl for 732,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 366,000 Bbls for the year ended December 31, 2016.
⁽³⁾: Includes an outstanding crude oil swap which may be extended 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 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 at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

			December 31, 2013

					Floors				Ceilings				Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
January 2014 - March 2014	Three-Way Collars	Crude Oil		144,000	$	95.00	$	95.00	$	98.60 - 109.50	$	100.03	$	70.00	$	70.00
January 2014 - June 2014	Collars	Crude Oil		724,000		90.00		90.00		96.50 - 99.50		98.00
January 2014 - December 2014	Collars	Crude Oil		7,573,750		85.00 - 95.00		88.67		93.60 - 108.45		96.22
January 2014 - December 2014	Collars	Natural Gas		11,862,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500		95.00		95.00		98.20 - 101.00		99.13		70.00		70.00
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015⁽¹⁾	Collars	Crude Oil		5,110,000		82.50 - 90.00		86.07		90.00 - 100.25		94.65
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015⁽²⁾	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
January 2016 - December 2016⁽³⁾	Swaps	Crude Oil		2,190,000		88.00 - 88.87		88.30

⁽¹⁾: Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2016.
⁽²⁾: Includes an outstanding crude oil swap which may be extended at a price of $91.25 per Bbl for 730,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 365,000 Bbls for the year ended December 31, 2016.
⁽³⁾: Includes an outstanding crude oil swap which may be extended 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 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 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, 2014 and December 31, 2013 in accordance with ASU 2011-11 and ASU 2013-01:

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
	(In thousands)						(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	15,457		$	24,762		$	(53,908	)	$	(37,192	)
Amounts Not Offset in the Consolidated Balance Sheet		(14,625	)		(20,036	)		14,235			19,507


Net Amount	$	832		$	4,726		$	(39,673	)	$	(17,685	)

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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. ASSET RETIREMENT OBLIGATIONS

The Company records an asset retirement obligation (ARO) 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, 2014 (in thousands, inclusive of the current portion):


Liability for asset retirement obligations as of December 31, 2013	$	39,257
Liabilities settled and divested		(2,019	)
Additions		1,104
Accretion expense		479
Revisions in estimated cash flows		154


Liability for asset retirement obligations as of March 31, 2014	$	38,975

8. COMMITMENTS AND CONTINGENCIES

Commitments

The Company leases corporate office space in Houston, Texas; Tulsa, Oklahoma; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $1.9 million and $2.5 million for the three months ended March 31, 2014 and 2013, respectively. 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 2017. Early termination of the drilling rig commitments would result in termination penalties approximating $42.3 million, which would be in lieu of the remaining $79.7 million of drilling rig commitments as of March 31, 2014. As of March 31, 2014, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2013, as disclosed in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013, approximating $66.6 million in the aggregate, and containing various expiration dates through 2024.

The Company has entered into various long-term gathering, transportation and sales contracts in its Bakken / Three Forks formations in North Dakota. As of March 31, 2014, the Company had in place nine long-term crude oil contracts and two 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 five to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. The Company believes that there are sufficient available reserves and supplies in the Bakken / Three Forks formations to meet its commitments.

Additionally, as of March 31, 2014, the Company had one long-term natural gas transportation contract and one long-term natural gas gathering contract in the Woodbine formation in East Texas.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. COMMITMENTS AND CONTINGENCIES (Continued)

The rate under the transportation contract was negotiated based on market rates and the contract term is five years from the date of first production. Under the gathering contract, the Company has committed substantially all of its natural gas production from specific wells in the area, until a contracted volume amount is reached, in exchange for the construction of a gathering system. The contract term is five years from the date of first production.

Historically, the Company has been able to meet its delivery commitments.

On December 20, 2013, the Company entered into a carry and earning agreement, as amended (the Agreement), with an independent third party (the Seller) associated with the acquisition of certain properties prospective for the Tuscaloosa Marine Shale, primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The Agreement requires the Company to fund up to $189.4 million (the Carry Amount) in exchange for approximately 117,870 net acres. The Company paid $62.5 million of the Carry Amount at closing on February 28, 2014. The Carry Amount is to be used by the Seller to fund wells prospective for the Tuscaloosa Marine Shale to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, the Company will also receive a 5% working interest in the Carry Wells. The commitment period is from January 1, 2014 through August 31, 2017, and is capped at $120.0 million through December 31, 2014 and up to the full $189.4 million through August 31, 2017. Any amount of the commitment not spent or subject to an approval for expenditure by the Seller on or before August 31, 2017 shall be forfeited.

Contingencies

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

9. 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 from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. The Company used the net proceeds from the offering to repay a portion of the outstanding borrowings under its Senior Credit Agreement.

Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Company's Board of Directors, cumulative dividends at the rate of 5.75% per annum (the dividend rate) on the Liquidation Preference per share of the Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, in common stock of the Company or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year. On March 3, 2014, the Company paid cumulative, declared dividends of $5.0 million by issuing approximately 1.4 million

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

shares of common stock reflected as a non-cash dividend. As of March 31, 2014, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $1.7 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 as described below.

Each share of Series A Preferred Stock is convertible, at the holder's option at any time, initially into approximately 162.4431 shares of common stock of the Company (which is equivalent to an initial conversion price of approximately $6.16 per share), subject to specified adjustments as set forth in the Series A Designation. Based on the initial conversion rate, approximately 56.0 million shares of common stock of the Company would be 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.

If the Company undergoes a fundamental change (as defined in the Series A Designation) 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 292.3977 shares of common stock of the Company per share of the Series A Preferred Stock (subject to adjustment in the same manner as the conversion rate).

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

Common Stock

On August 13, 2013, the Company completed the issuance and sale of 43.7 million shares of its common stock in an underwritten public offering. The shares of common stock sold have been 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 automatically effective on May 16, 2013. The net proceeds to the Company from the offering of common stock were approximately $215.2 million, after deducting the

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

underwriting discount and estimated offering expenses. The Company used the net proceeds from the offering to repay a portion of the then outstanding borrowings under its Senior Credit Agreement.

On January 17, 2013, with stockholder approval, the Company filed a Certificate of Amendment of the Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to increase its authorized common stock by approximately 333.3 million shares for a total of 670.0 million authorized shares of common stock.

Warrants

In February 2012, in conjunction with the issuance of the 2017 Notes, the Company issued warrants to purchase 36.7 million shares of the Company's common stock at an exercise price of $4.50 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 entitle the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

In August 2012, as part of the Company's acquisition of GeoResources by merger, the Company assumed outstanding GeoResources common stock warrants. At the date of the merger 0.6 million GeoResources warrants were outstanding and were converted to 1.2 million Halcón warrants (the August 2012 Warrants). Each GeoResources warrant was converted into an August 2012 Warrant to acquire one share of Halcón common stock (Share Portion) at an exercise price of $8.40 per share of common stock and the right to receive $20 in cash per equivalent assumed share (Cash Portion) at an exercise price of $0.82 per $1.00 received. The August 2012 Warrants contained substantially the same terms of the original GeoResources warrants with adjustments to the exercise price and addition of the Cash Portion to reflect the impact of the consideration per share in the merger. The August 2012 Warrants expired on June 9, 2013. The August 2012 Warrants were reflected as a current liability in the unaudited condensed consolidated balance sheets at March 31, 2013 and were recorded at fair value. Changes in fair value were recognized in "Interest expense and other, net" in the unaudited condensed consolidated statements of operations.

Incentive Plan

On May 8, 2006, the Company's stockholders first approved its 2006 Long-Term Incentive Plan (the Plan). On May 23, 2013, shareholders last approved an increase in authorized shares under the Plan from 11.5 million to 41.5 million. As of March 31, 2014 and December 31, 2013, a maximum of 13.2 million and 25.7 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 Topic 718. The guidance requires all share-based payments to employees and directors, including grants of performance units, stock options, and restricted stock, to be recognized in the financial statements based on their fair values.

For the three months ended March 31, 2014 and 2013, the Company recognized $4.3 million and $2.3 million, respectively, of share-based compensation expense as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

Performance Share Units

During the three months ended March 31, 2014, the Company granted performance share units (PSU) under the Plan covering 1.6 million shares of common stock to senior management of the Company. The PSU provide 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 utilize $4.00 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 $4.00, the PSU will vest and represent the right to receive 50% of the number of shares of common stock underlying the PSU. At $7.00, the PSU will vest and represent the right to receive the full number of shares of common stock underlying the PSU; and at $10.00, 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 vest and represent the right to receive a proportionate number of shares, e.g., 75% of the number of shares of common stock underlying the PSU if the average market price at such time is $5.50, 150% of the number of shares of common stock underlying the PSU if the average market price at such time is $8.50, and so forth. The Company has reserved for issuance under the Plan the maximum right to receive upon vest of the PSU, or 3.2 million shares of common stock. At March 31, 2014, the Company had $4.8 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 2.9 years.

Stock Options

During the three months ended March 31, 2014, the Company granted stock options under the Plan covering 6.1 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $3.67 to $4.33 with a weighted average exercise price of $3.67. 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, 2014, the Company had $20.4 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.6 years.

During the three months ended March 31, 2013, the Company granted stock options under the Plan covering 1.5 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $6.36 to $8.23 with a weighted average exercise price of $7.20. 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, 2013, the unrecognized compensation expense related to stock options totaled $14.4 million and will be recognized on the graded-vesting method over the requisite service periods.

During the three months ended March 31, 2013, the Company's Board of Directors approved an increase in authorized shares under the Plan from 11.5 million to 41.5 million, subject to stockholder approval. As a result, stock options granted to executive officers and certain other participants covering 4.4 million shares during the three months ended March 31, 2013 were pending stockholder approval on May 23, 2013 because these grants would have caused the Company to exceed the limit of shares

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

available under the Plan. These awards were subject to forfeiture in the event that stockholder approval was not obtained and therefore the Company did not record any expense associated with the amortization of these awards in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2013.

Restricted Stock

During the three months ended March 31, 2014, the Company granted 3.6 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $3.67 to $4.33 with a weighted average price of $3.67. 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, 2014, the Company had $19.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.7 years.

During the three months ended March 31, 2013, the Company granted 2.8 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $6.36 to $7.26 with a weighted average price of $7.10. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant. At March 31, 2013, the Company had $20.1 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.8 years.

Treasury Stock

During the three months ended March 31, 2013, the Company granted 2.8 million shares of restricted stock under the Plan to directors and employees of the Company of which 1.2 million shares were issued out of treasury stock. In addition, the Company retired 0.4 million shares from treasury stock representing shares that were repurchased for taxes tendered upon vesting of stock based compensation awards in prior years. As of March 31, 2013, the Company had no issued shares held in treasury.

10. INCOME TAXES

Under guidance contained in Topic 740 of the ASC, deferred taxes are determined by applying the provisions of enacted tax laws and rates for the jurisdictions in which the Company operates to the estimated future tax effects of the differences between the tax basis of assets and liabilities and their reported amounts in the Company's financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

In assessing the need for a valuation allowance on our deferred tax assets, the Company considers possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. A significant item of objective negative evidence considered was the cumulative three-year book loss driven primarily by ceiling test write-downs in 2013. Based upon the evaluation of the available

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. INCOME TAXES (Continued)

evidence the Company continued to record a full valuation allowance against its net deferred tax assets as of March 31, 2014.

The Company recorded no income tax expense or benefit on a pre-tax loss of $73.0 million for the three months ended March 31, 2014 due to the valuation allowance. For the three months ended March 31, 2013, the Company recorded a tax provision of $3.3 million on pre-tax income of $8.8 million. The effective tax rate for the three months ended March 31, 2014 was 0.0% compared to 37.6% for the three months ended March 31, 2013. The significant difference in the effective tax rate is due to the full valuation allowance that was established during the fourth quarter of 2013.

During the first quarter of 2014, the Internal Revenue Service commenced an audit of GeoResources, Inc.'s tax returns for the tax years ending December 31, 2010 through August 1, 2012. The audit is ongoing as of the date of this filing.

11. 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,

	2014			2013
	(In thousands, except per share amounts)
Basic:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465




Weighted average basic number of common shares outstanding		413,521			346,139


Basic net income (loss) per share of common stock	$	(0.19	)	$	0.02




Diluted:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465




Weighted average basic number of common shares outstanding		413,521			346,139
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			14,411
Exercise of August 2012 Warrants		—			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			1,255
Vesting of performance share units		—			—
Conversion of 2017 Notes		Anti-dilutive			Anti-dilutive
Conversion of preferred stock		—			21,760
Conversion of Series A Preferred Stock		Anti-dilutive			—


Weighted average diluted number of common shares outstanding		413,521			383,565


Diluted net income (loss) per share of common stock	$	(0.19	)	$	0.01

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. EARNINGS PER COMMON SHARE (Continued)

Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock, totaling 173.2 million shares for the three months ended March 31, 2014 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, and convertible debt, totaling 70.6 million shares were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive for the three months ended March 31, 2013.

12. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:

	March 31, 2014		December 31, 2013

	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	169,640	$	129,355
Joint interest accounts		137,957		170,907
Affiliated partnership		302		500
Other		1,405		11,756


	$	309,304	$	312,518




Prepaids and other:
Prepaids	$	5,974	$	5,636
Income tax receivable		5,404		10,404
Other		58		58


	$	11,436	$	16,098




Accounts payable and accrued liabilities:
Trade payables	$	86,708	$	87,661
Accrued oil and natural gas capital costs		314,094		292,472
Revenues and royalties payable		128,598		124,222
Accrued interest expense		75,177		82,570
Accrued employee compensation		4,960		2,272
Accrued lease operating expenses		24,980		21,469
Drilling advances from partners		16,314		24,882
Accounts payable to affiliated partnership		939		679
Other		433		362


	$	652,203	$	636,589

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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, 2014 and 2013 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, 2013.

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. During 2013 and 2014, 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 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, the Eagle Ford formation in East Texas and the Tuscaloosa Marine Shale formation in Louisiana and Mississippi, as well as several other areas.

Our average daily oil and natural gas production increased 41% in the first three months of 2014 compared to the same period in the prior year. During the first three months of 2014, we averaged 36,622 barrels of oil equivalent (Boe) per day compared to average daily production of 26,022 Boe/d during the first three months of 2013. The increase in production compared to the prior year period was driven primarily by operated drilling results and increased production volumes associated with the development of properties we acquired in 2012 in the Bakken / Three Forks and the Eagle Ford formation in East Texas (which we refer to as "El Halcón"). These areas collectively accounted for an increase of approximately 16,100 Boe/d. This increase was partially offset by production decreases from our divestiture of non-core properties during 2013. During the first three months of 2014, we participated in the drilling of 67 gross (30.1 net) wells, all of which were completed and capable of production.

Recent Developments

Amendment to the Senior Credit Agreement and Borrowing Base

On March 21, 2014, we entered into the Seventh Amendment to our Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment increased the borrowing base under our Senior Credit Agreement to $800.0 million in connection with the annual spring redetermination and also provided us additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

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Capital Resources and Liquidity

Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from potential non-core asset divestitures, proceeds from potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $800.0 million. 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 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 unsecured 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 minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of i) not less than 2.0 to 1.0 through December 31, 2014 (pursuant to the Seventh Amendment), and ii) not less than 2.5 to 1.0 for subsequent periods. We are 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 unsecured 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 the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination. At March 31, 2014, under the borrowing base of $800.0 million, we had $348.0 million indebtedness outstanding under our Senior Credit Agreement, $1.2 million of letters of credit outstanding and $450.8 million of borrowing capacity, of which approximately $332 million was available to us under the indebtedness limitations in our indentures.

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 adjusted consolidated net tangible assets as determined 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 aggressive drilling plans also impact our near-term ability to comply with our debt covenants, particularly the interest coverage test under our Senior Credit Agreement and the fixed charge coverage ratio under our indentures by reducing our production and reserves on a current and, for purposes of covenant calculations, a pro forma historical basis, while drilling takes time to replace these losses. Of course, over the longer term, we expect that our strategy and our investments will result in increased production and reserves, lower lease operating costs and more abundant drilling opportunities. As a consequence, we constantly 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.

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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. During 2013, we obtained amendments to the calculation of the interest coverage ratio covenant under our Senior Credit Agreement allowing us to annualize our quarterly EBITDA because, among other things, we anticipated that our strategic decision to divest our Eagle Ford shale producing properties and invest in the acquisition and drilling of undeveloped acreage would have caused us to fall below the interest coverage ratio. We requested reduction in the minimum required interest coverage ratio of 2.0 to 1.0 for 2014 and that request was granted on March 21, 2014, as noted above under "Recent Developments." The basis for the amendment request is similar to previously requested waivers described above, i.e., the potential for us to fall out of compliance primarily as a result of our strategic decision to divest producing properties, invest extensively in undeveloped acreage and the long lead times associated with replacing lost production through our drilling program. 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, are actively considering various joint venture opportunities to finance development of our Tuscaloosa Marine Shale properties, and 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 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, the 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 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.

We strive to maintain financial flexibility while pursuing our drilling plans and evaluating potential acquisitions, and will therefore likely continue to access capital markets (if on acceptable terms) as necessary 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.

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Cash Flow

Our primary sources of cash for the three months ended March 31, 2014 were from operating and financing activities and for the three months ended March 31, 2013 were from financing activities. In the first three months of 2014, borrowings on our Senior Credit Agreement were the primary driver of the net cash provided by financing activities. The increase in cash received from operations, coupled with the cash from financing activities, were offset by cash used in investing activities to fund our drilling program and acquire additional leasehold interests. Operating cash flow increases were substantially driven by the significant increase in production volumes, namely from our Bakken and El Halcón areas, as compared to the three months ended March 31, 2013 and, to a lesser extent, higher commodity prices. Fluctuations in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See "Results of Operations" below for a review of the impact of prices and volumes on sales.

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

	Three Months Ended March 31,

	2014			2013
	(In thousands)
Cash flows provided by (used in) operating activities	$	159,500		$	45,710
Cash flows provided by (used in) investing activities		(509,498	)		(445,024	)
Cash flows provided by (used in) financing activities		347,530			397,610


Net increase (decrease) in cash	$	(2,468	)	$	(1,704	)

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2014 and 2013, was $159.5 million and $45.7 million, respectively.

The $159.5 million of operating cash flows for the three months ended March 31, 2014 primarily reflect the impact of increased production from our acquisitions and developmental drilling activities which drove a 44% increase in revenues, as compared to the prior year period, and outpaced related operating expenses.

Investing Activities. The primary driver of cash used in investing activities is capital spending, specifically drilling and completions coupled with the acquisition of unevaluated leasehold acreage in our target areas. Net cash used in investing activities was approximately $509.5 million and $445.0 million for the three months ended March 31, 2014 and 2013, respectively.

During the first three months of 2014, we incurred cash expenditures of $432.8 million on oil and natural gas capital expenditures, of which $328.6 million related to drilling and completion costs and the remainder was primarily associated with leasing, acquisitions and seismic data. We participated in the drilling of 67 gross (30.1 net) wells, all of which were completed and capable of production. We also spent $62.5 million related to a carried interest in the Tuscaloosa Marine Shale. We spent an additional $16.0 million on other operating property and equipment capital expenditures, of which $13.2 million pertained to pipelines and related infrastructure projects, and the remainder was spent on leasehold improvements, computers and software.

During the first three months of 2013, we incurred cash expenditures of $380.1 million on oil and natural gas capital expenditures. We participated in the drilling of 53 gross (13.7 net) wells of which 52 gross (12.7 net) wells were completed and capable of production and one gross (1.0 net) well was a dry hole. We spent an additional $36.3 million on other operating property and equipment capital expenditures; of which $30.9 million pertained to pipelines and related infrastructure projects and the

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remainder was spent on leasehold improvements, computers and software primarily in our corporate office in Houston, Texas.

Financing Activities. Net cash flows provided by financing activities were $347.5 million and $397.6 million for the three months March 31, 2014 and 2013, respectively. The primary drivers of cash provided by financing activities for the three months ended March 31, 2014 were borrowings on our Senior Credit Agreement.

On January 14, 2013, we completed the issuance of an additional $600.0 million aggregate principal amount of our 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees and expenses) and were used to repay all of the then outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program.

Contractual Obligations

We lease corporate office space in Houston, Texas; Tulsa, Oklahoma; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $1.9 million and $2.5 million for the three months ended March 31, 2014 and 2013, respectively. 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 2017. Early termination of the drilling rig commitments would result in termination penalties approximating $42.3 million, which would be in lieu of the remaining $79.7 million of drilling rig commitments as of March 31, 2014. As of March 31, 2014, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2013 disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, approximating $66.6 million in the aggregate, and containing various expiration dates through 2024.

We have entered into various long-term gathering, transportation and sales contracts in the Bakken / Three Forks formations in North Dakota. As of March 31, 2014, we had in place nine long-term crude oil contracts and two 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 five to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. We believe that there are sufficient available reserves and supplies in the Bakken / Three Forks formations to meet our commitments.

Additionally, as of March 31, 2014, we had one long-term natural gas transportation contract and one long-term natural gas gathering contract in the Woodbine formation in East Texas. The rate under the transportation contract was negotiated based on market rates and the contract term is five years from the date of first production. Under the gathering contract, we have committed substantially all of our natural gas production from specific wells in the area, until a contracted volume amount is reached, in exchange for the construction of a gathering system. The contract term is five years from the date of first production.

Historically, we have been able to meet our delivery commitments.

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, 2013.

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Results of Operations

Three Months Ended March 31, 2014 and 2013

We reported a net loss $73.0 million for the three months ended March 31, 2014 compared to net income of $5.5 million for the three months ended March 31, 2013. 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)	2014			2013			Change
Net income (loss)	$	(72,964	)	$	5,465		$	(78,429	)
Operating revenues:
Oil		256,029			180,827			75,202
Natural gas		9,409			5,669			3,740
Natural gas liquids		8,759			3,828			4,931
Other		952			530			422
Operating expenses:
Production:
Lease operating		36,638			25,304			11,334
Workover and other		2,789			1,624			1,165
Taxes other than income		24,160			17,436			6,724
Gathering and other		5,073			333			4,740
Restructuring		987			671			316
General and administrative:
General and administrative		28,466			29,262			(796	)
Share-based compensation		4,332			2,335			1,997
Depletion, depreciation and accretion:
Depletion—Full cost		117,246			79,891			37,355
Depreciation—Other		2,183			1,071			1,112
Accretion expense		479			896			(417	)
Full cost ceiling impairment		61,165			—			61,165
Other income (expenses):
Net gain (loss) on derivative contracts		(33,656	)		(18,422	)		(15,234	)
Interest expense and other, net		(30,939	)		(4,850	)		(26,089	)
Income tax (provision) benefit		—			(3,294	)		3,294
Production:
Crude oil—MBbls		2,806			1,931			875
Natural gas—Mmcf		1,792			1,811			(19	)
Natural gas liquids—MBbls		191			109			82
Total MBoe⁽¹⁾		3,296			2,342			954
Average daily production—Boe⁽¹⁾		36,622			26,022			10,600
*Average price per unit⁽²⁾***:
Crude oil price—Bbl	$	91.24		$	93.64		$	(2.40	)
Natural gas price—Mcf		5.25			3.13			2.12
Natural gas liquids price—Bbl		45.86			35.12			10.74
Total per Boe⁽¹⁾		83.19			81.27			1.92
Average cost per Boe:
Production:
Lease operating	$	11.12		$	10.80		$	0.32
Workover and other		0.85			0.69			0.16
Taxes other than income		7.33			7.44			(0.11	)
Gathering and other		1.54			0.14			1.40
Restructuring		0.30			0.29			0.01
General and administrative:
General and administrative		8.64			12.49			(3.85	)
Share-based compensation		1.31			1.00			0.31
Depletion		35.57			34.11			1.46

⁽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, 2014, oil, natural gas and natural gas liquids revenues increased $83.9 million from the same period in 2013. The increase was primarily due to increased production volumes associated with the development of properties in the Bakken / Three Forks and El Halcón areas. These areas collectively accounted for an increase of approximately 16,100 Boe/d and $124.2 million of incremental revenues. This increase was partially offset by production decreases due to our divestitures of non-core properties. Realized average prices per Boe increased $1.92 per Boe to $83.19 per Boe due to the higher natural gas and natural gas liquids prices, partially offset by lower average oil prices.

Lease operating expenses increased $11.3 million for the three months ended March 31, 2014, primarily due to $23.1 million of costs incurred on acquired properties and an increase in production within these areas as we continue to carry out our development plan. This increase was partially offset by our divestiture of non-core properties in 2013 which, historically, had higher operating costs. Lease operating expenses were $11.12 per Boe for the three months ended March 31, 2014, compared to $10.80 per Boe for the same period in 2013.

Workover expenses increased $1.2 million for the three months ended March 31, 2014 compared to the same period in 2013 primarily due to $1.3 million of expenses associated with acquired properties and an increase in activity in these areas. This increase was partially offset by decreased workover expenses on our existing properties.

Taxes other than income increased $6.7 million for the three months ended March 31, 2014 as compared to the same period in 2013 primarily due to $10.2 million of taxes associated with increased production as we continue to carry out our development plan. This increase was partially offset by a decrease in production associated with non-core properties we divested in the second half of 2013. 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 $7.33 per Boe and $7.44 per Boe for the three months ended March 31, 2014 and 2013, respectively. The decrease on a per Boe basis is attributed to lower ad valorem tax expense in 2014 due to the non-core properties we divested in the second half of 2013.

Gathering and other expenses for the three months ended March 31, 2014 and 2013 were $5.1 million and $0.3 million, respectively. In 2014, approximately $1.2 million of these expenses were attributable to midstream infrastructure that we developed in our El Halcón, Woodbine and Utica / Point Pleasant operating areas and approximately $3.6 million related to gathering and other fees paid on our oil and natural gas production.

In conjunction with our divestitures of certain non-core properties, we incurred approximately $1.0 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas for the three months ended March 31, 2014. In March 2012, we announced our intention to close the Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the Restructuring). As part of the Restructuring, we offered certain severance and retention benefits to affected employees. We incurred $0.7 million in costs associated with the Restructuring for the three months ended March 31, 2013.

General and administrative expense for the three months ended March 31, 2014 decreased $0.8 million to $28.5 million as compared to the same period in 2013. The decrease in general and administrative expenses is attributed to decreases in professional fees and office expenses amounting to $3.2 million and $1.4 million, respectively. These were partially offset by increases in transaction costs and payroll and related employee benefit costs of approximately $3.2 million. On a per unit basis, general and administrative expenses were $8.64 per Boe and $12.49 per Boe, for the three months ended March 31, 2014 and 2013, respectively.

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Share-based compensation expense for the three months ended March 31, 2014 was $4.3 million, an increase of $2.0 million compared to the same period in 2013. The increase in share-based compensation expense results from additional awards to employees and directors since the prior year period.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume as of the beginning of the period for the evaluated properties. Depletion expense increased $37.4 million to $117.2 million for the three months ended March 31, 2014 compared to the same period in 2013, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $35.57 per Boe for the three months ended March 31, 2014 compared to $34.11 per Boe for the three months ended March 31, 2013. The increase in depletion expense and the depletion rate per Boe is primarily due to the increase in production volumes associated with the development of our properties.

Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded accretion expense of $0.5 million for the three months ended March 31, 2014, compared to $0.9 million for the same period in 2013. The decrease in accretion expense is attributable to the non-core properties we divested in the second half of 2013.

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 $61.2 million for the three months ended March 31, 2014. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. We have also, in the past, entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations. At March 31, 2014, we had a $15.5 million derivative asset, $1.2 million of which was classified as current, and we had a $53.9 million derivative liability, $32.9 million of which was classified as current. We recorded a net derivative loss of $33.7 million ($26.9 million net unrealized loss and $6.8 million net realized loss on settled contracts and premium costs) for the three months ended March 31, 2014 compared to a net derivative loss of $18.4 million ($16.8 million net unrealized loss and $1.6 million net realized loss), in the same period in 2013.

Interest expense increased $26.1 million for the three months ended March 31, 2014 from the same period in 2013. Capitalized interest for the three months ended March 31, 2014 and 2013 was $46.8 million and $52.8 million, respectively. This decrease in capitalized interest was driven by decreases in our unevaluated properties since March 31, 2013. Interest expense subject to capitalization increased to $78.7 million in the three months ended March 31, 2014 from $57.4 million in the comparable prior year period. The increase in interest subject to capitalization is attributed to the issuance of our 2022 Notes and our additional 2020 Notes since March 31, 2013.

We recorded no income tax benefit or expense for the three months ended March 31, 2014 due to the valuation allowance compared to an income tax provision of $3.3 million due to our income before

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taxes of $8.8 million in the comparable prior year period. The effective tax rate for the three months ended March 31, 2014 was 0.0% compared to 37.6% for the three months ended March 31, 2013. The change in effective tax rate is due to the valuation allowance recorded against our net deferred tax assets as of March 31, 2014.

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 put options. The total volumes which we hedge through the use of our 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. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. 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, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender or an affiliate of a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, "Derivative and Hedging Activities" for additional information.

We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Historically, we entered into interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At March 31, 2014 and 2013, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

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

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under ASC 825, Financial Instruments (ASC 825) are determined at discrete points in time based on relevant market information. These

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estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 5, "Fair Value Measurements" for additional information.

Interest Rate Sensitivity

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

At March 31, 2014, total long-term debt was approximately $3.5 billion of which approximately 90% bears interest at a weighted average fixed interest rate of 9.2% per year. The remaining 10% of our total debt balance at March 31, 2014 bears interest at floating or market interest rates that, at our option, are tied to prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At March 31, 2014, the weighted average interest rate on our variable rate debt was 2.5% per year. If the balance of our variable rate debt at March 31, 2014 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.2 million per quarter.

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, 2014. 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control—Integrated Framework (the 2013 Framework). Originally issued in 1992 (the 1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of March 31, 2014, we continued to utilize the 1992 Framework and will transition to the 2013 Framework by the end of 2014.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There have been no changes to the risk factors described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, except as described below.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state, tribal and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or in the future plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

From time to time, for example, legislation has been proposed in Congress to amend the federal Safe Drinking Water Act to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA is conducting a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. In December 2012, the EPA issued a progress report describing its ongoing study, and announcing its expectation that a final draft report will be released for public comment and peer review in 2014. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing, including, for example, a federal Bureau of Land Management rulemaking for hydraulic fracturing practices on federal and Indian lands that has resulted in a May 2013 proposal that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. These activities could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Certain states, including North Dakota, Ohio, Pennsylvania, and Texas where we conduct operations, likewise are considering or have adopted more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic monitoring, waste disposal and water use. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have extended to bans on hydraulic fracturing. On December 19, 2013, the Pennsylvania Supreme Court overturned several portions of Pennsylvania's law regulating hydraulic fracturing, allowing local governments in Pennsylvania to regulate hydraulic fracturing through local land use regulations. Other local jurisdictions, including Dallas, Texas and several cities in Colorado, have adopted restrictions on hydraulic fracturing, and anti-hydraulic fracturing activists are seeking more such controls.

The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively

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prevent the extraction of oil and gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

In the United States, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the Obama Administration is attempting to address climate change through a variety of administrative actions. The EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and required reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA extended the reporting obligation to oil and natural gas facilities. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting beginning in September 2012. Beyond measuring and reporting, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, the President released a Strategy to Reduce Methane Emissions that includes consideration of both voluntary programs and targeted regulations for the oil and gas sector. Towards that end, the EPA has released five draft white papers on methane and volatile organic compound emissions and mitigation measures for natural gas compressors, hydraulically fractured oil wells, pneumatic devices, well liquids unloading facilities and natural gas production and transmission facilities. The EPA is seeking responses to the white papers and intends to use this process to determine how best to pursue additional emission reductions from the oil and gas sector. Also as part of the President's strategy, the federal Bureau of Land Management is expected to propose standards for reducing venting and flaring on public lands.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls or other compliance costs, and reduce demand for our products.

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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 2014	6,271	$	3.43	—	—
February 2014	95,372		3.81	—	—
March 2014	916		3.82	—	—

⁽¹⁾: All of the shares were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards. The acquisitions 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

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

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


		2.1*		Agreement of Sale and Purchase by and among Halcón Energy Properties, Inc., Halcón Field Services, LLC, HK Energy, LLC, Halcón Operating Co, Inc., HK Energy Operating, LLC, and Halcón Resources Operating, Inc., and New Gulf Resources, LLC, dated February 25, 2014.
		3.1		Amended and Restated Certificate of Incorporation of RAM Energy Resources, Inc. dated February 8, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed February 9, 2012).
		3.2		Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of February 10, 2012 (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed February 9, 2012).
		3.3		Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated March 2, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed March 5, 2012).
		3.4		Certificate of Elimination of 8% Automatically Convertible Preferred Stock dated November 30, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 4, 2012).
		3.5		Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated December 5, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 11, 2012).
		3.6		Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated January 17, 2013 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed January 23, 2013).
		3.7		Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of May 23, 2013 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed May 29, 2013).
		3.8		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).
		3.9		Certificate of Elimination of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed June 18, 2013).
		3.10		Fourth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed November 6, 2012).
		4.1		Convertible Promissory Note dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 9, 2012).

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		4.2		Warrant Certificate dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed February 9, 2012).
		4.3		Registration Rights Agreement dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed February 9, 2012).
		4.4		Indenture dated as of July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 9.75% Senior Notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 17, 2012).
		4.5		Registration Rights Agreement dated July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed July 17, 2012).
		4.6		First Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 2, 2012).
		4.7		Second Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed August 2, 2012).
		4.8		Registration Rights Agreement dated as of August 1, 2012, among CH4 Energy II, LLC, PetroMax Leon, LLC and Petro Texas LLC and Halcón Resources Corporation (subsequently joined by U.S. King King LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 7, 2012).
		4.9		Registration Rights Agreement dated March 5, 2012, between Halcón Resources Corporation and Barclays Capital, Inc. as lead placement agent for the benefit of the initial holders named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed March 5, 2012).
		4.10		Registration Rights Agreement dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed November 7, 2012).
		4.11		Indenture dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 8.875% Senior Notes due 2021 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed November 7, 2012).
		4.12		First Supplemental Indenture dated December 6, 2012, among Halcón Williston I, LLC and Halcón Williston II, LLC, the existing guarantors, Halcón Resources Corporation, the parties named therein as subsidiary guarantors and U.S. Bank National Association, as trustee, relating to the 8.875% senior notes due 2021 (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed December 11, 2012).

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		4.13		Third Supplemental Indenture dated December 6, 2012, among Halcón Resources Corporation and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.4 of our Current Report on Form 8-K filed December 11, 2012).
		4.14		Registration Rights Agreement dated December 6, 2012, between Halcón Resources Corporation and Petro-Hunt Holdings LLC and Pillar Holdings LLC (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed December 11, 2012).
		4.15		First Amendment to Registration Rights Agreement dated December 6, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed December 11, 2012).
		4.16		Registration Rights Agreement, dated as of January 14, 2013, between Halcón Resources Corporation and Wells Fargo Securities, LLC, on behalf of the initial purchasers named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed January 15, 2013).
		4.17		Waiver, dated July 3, 2013, relating to Registration Rights Agreement dated December 6, 2012 by and among Halcón Resources Corporation and Petro-Hunt Holdings, LLC and Pillar Holdings, LLC (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 10, 2013).
		4.18		Indenture dated as of August 13, 2013, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 9.25% Senior Notes due 2022 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 13, 2013).
		4.19		Registration Rights Agreement dated as of August 13, 2013, among Halcón Resources Corporation and BMO Capital Markets Corp., on behalf of the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed August 13, 2013).
		4.20		Registration Rights Agreement, dated as of December 19, 2013, between Halcón Resources Corporation and Barclays Capital Inc. and Wells Fargo Securities, LLC as the initial purchasers (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed December 20, 2013).
		10.1		Seventh Amendment to Senior Revolving Credit Agreement, dated as of March 21, 2014, among Halcón Resources Corporation, as borrower, each of the lenders 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 27, 2014).
		10.2†		Employment Agreement between Charles E. Cusack, III and Halcón Resources Corporation dated November 8, 2012 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed March 27, 2014).
		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

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		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 8, 2014	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer
May 8, 2014	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
May 8, 2014	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Vice President and Chief Accounting Officer