BATTALION OIL CORP - Quarter Report: 2019 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, 2019
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 1500, 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 every Interactive Data File required to be submitted 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 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, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer o		Accelerated filer ý		Non-accelerated filer o		Smaller reporting company o Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Trading Symbol		Name of each exchange on which registered

Common Stock par value $0.0001		HK		New York Stock Exchange (NYSE)

At May 6, 2019, 164,256,015 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, 2019 and 2018	5
	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2019 and December 31, 2018	6
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Three Months Ended March 31, 2019 and the Year Ended December 31, 2018	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 2019 and 2018	9
	Notes to Unaudited Condensed Consolidated Financial Statements	10
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	38
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	48
ITEM 4.	Controls and Procedures	49
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	50
ITEM 1A.	Risk Factors	50
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
ITEM 3.	Defaults Upon Senior Securities	51
ITEM 4.	Mine Safety Disclosures	51
ITEM 5.	Other Information	51
ITEM 6.	Exhibits	51
Signatures		54

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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, potential costs to be incurred, future cash flows and borrowings, 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, 2018, as well as the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

•: our ability to continue as a going concern;
•: volatility in commodity prices for oil, natural gas and natural gas liquids;
•: our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and develop our undeveloped acreage positions;
•: our ability to replace our oil and natural gas reserves and production;
•: we have historically had substantial indebtedness and we may incur more debt in the future;
•: higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;
•: the presence or recoverability of estimated oil and natural gas reserves attributable to our properties and the actual future production rates and associated costs of producing those oil and natural gas reserves;
•: our ability to successfully develop our large inventory of undeveloped acreage;
•: our ability to retain key members of senior management, the board of directors, and key technical employees;
•: senior management's ability to execute our plans to meet our goals;
•: access to and availability of water and other treatment materials to carry out fracture stimulations in our resource play;
•: access to adequate gathering systems, processing and treating facilities and transportation take-away capacity to move our production to marketing outlets to sell our production at market prices;
•: the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars;
•: 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;

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•: the possibility that acquisitions may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management's time and energy;
•: our ability to successfully integrate acquired oil and natural gas businesses and operations;
•: competition, including competition for acreage in our resource play;
•: 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 and state regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;
•: our insurance coverage may not adequately cover all losses that we may sustain; and
•: title to the properties in which we have an interest may be impaired by title defects.

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,

	2019			2018
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	45,517		$	43,069
Natural gas		1,461			2,319
Natural gas liquids		4,945			3,712

Total oil, natural gas and natural gas liquids sales		51,923			49,100
Other		(7	)		155

Total operating revenues		51,916			49,255

Operating expenses:
Production:
Lease operating		14,186			4,915
Workover and other		2,646			1,361
Taxes other than income		2,893			3,029
Gathering and other		14,869			6,422
Restructuring		11,271			101
General and administrative		4,608			15,210
Depletion, depreciation and accretion		29,975			15,991
Full cost ceiling impairment		275,239			—
(Gain) loss on sale of oil and natural gas properties		—			3,679
(Gain) loss on sale of Water Assets		885			—

Total operating expenses		356,572			50,708

Income (loss) from operations		(304,656	)		(1,453	)
Other income (expenses):
Net gain (loss) on derivative contracts		(64,799	)		5,903
Interest expense and other		(12,589	)		(7,048	)

Total other income (expenses)		(77,388	)		(1,145	)

Income (loss) before income taxes		(382,044	)		(2,598	)
Income tax benefit (provision)		45,485			—

Net income (loss)	$	(336,559	)	$	(2,598	)



Net income (loss) per share of common stock:
Basic	$	(2.12	)	$	(0.02	)



Diluted	$	(2.12	)	$	(0.02	)



Weighted average common shares outstanding:
Basic		158,549			153,884



Diluted		158,549			153,884

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, 2019			December 31, 2018

Current assets:
Cash and cash equivalents	$	195		$	46,866
Accounts receivable		41,399			35,718
Receivables from derivative contracts		11,223			57,280
Prepaids and other		8,640			4,788

Total current assets		61,457			144,652

Oil and natural gas properties (full cost method):
Evaluated		1,594,171			1,470,509
Unevaluated		927,618			971,918

Gross oil and natural gas properties		2,521,789			2,442,427
Less—accumulated depletion		(943,512	)		(639,951	)

Net oil and natural gas properties		1,578,277			1,802,476

Other operating property and equipment:
Other operating property and equipment		158,188			130,251
Less—accumulated depreciation		(9,942	)		(8,388	)

Net other operating property and equipment		148,246			121,863

Other noncurrent assets:
Receivables from derivative contracts		4,844			12,437
Operating lease right of use assets		4,879			—
Funds in escrow and other		1,135			2,181

Total assets	$	1,798,838		$	2,083,609



Current liabilities:
Accounts payable and accrued liabilities	$	137,016		$	157,848
Liabilities from derivative contracts		20,086			3,768
Current portion of long-term debt		105,000			—
Operating lease liabilities		1,868			—
Asset retirement obligations		—			126

Total current liabilities		263,970			161,742

Long-term debt, net		613,493			613,105
Other noncurrent liabilities:
Liabilities from derivative contracts		7,341			9,139
Asset retirement obligations		6,971			6,788
Operating lease liabilities		3,095			—
Deferred income taxes		50,305			95,791
Commitments and contingencies (Note 10)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 164,320,437 and 160,612,852 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively		16			16
Additional paid-in capital		1,088,545			1,095,367
Retained earnings (accumulated deficit)		(234,898	)		101,661

Total stockholders' equity		853,663			1,197,044

Total liabilities and stockholders' equity	$	1,798,838		$	2,083,609

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)

	Common Stock								Retained Earnings (Accumulated Deficit)

	Common Stock					Additional Paid-In Capital						Stockholders' Equity
	Shares			Amount		Additional Paid-In Capital						Stockholders' Equity
Balances at December 31, 2018		160,613		$	16	$	1,095,367		$	101,661		$	1,197,044
Net income (loss)		—			—		—			(336,559	)		(336,559	)
Long-term incentive plan grants		4,153			—		—			—			—
Long-term incentive plan forfeitures		(193	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		(253	)		—		(406	)		—			(406	)
Stock-based compensation		—			—		(6,416	)		—			(6,416	)

Balances at March 31, 2019		164,320		$	16	$	1,088,545		$	(234,898	)	$	853,663

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) (Continued)

(In thousands)

	Common Stock								Retained Earnings (Accumulated Deficit)

	Common Stock					Additional Paid-In Capital						Stockholders' Equity
	Shares			Amount		Additional Paid-In Capital						Stockholders' Equity
Balances at December 31, 2017		149,379		$	15	$	1,016,281		$	55,702		$	1,071,998
Net income (loss)		—			—		—			(2,598	)		(2,598	)
Common stock issuance		9,200			1		63,479			—			63,480
Offering costs		—			—		(3,044	)		—			(3,044	)
Stock option exercises		42			—		323			—			323
Long-term incentive plan grants		1,922			—		—			—			—
Long-term incentive plan forfeitures		(74	)		—		—			—			—
Stock-based compensation		—			—		4,066			—			4,066

Balances at March 31, 2018		160,469			16		1,081,105			53,104			1,134,225
Net income (loss)		—			—		—			(16,274	)		(16,274	)
Long-term incentive plan grants		320			—		—			—			—
Long-term incentive plan forfeitures		(136	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		(53	)		—		(262	)		—			(262	)
Stock-based compensation		—			—		5,194			—			5,194

Balances at June 30, 2018		160,600			16		1,086,037			36,830			1,122,883
Net income (loss)		—			—		—			(81,837	)		(81,837	)
Long-term incentive plan grants		84			—		—			—			—
Long-term incentive plan forfeitures		(8	)		—		—			—			—
Stock-based compensation		—			—		5,404			—			5,404

Balances at September 30, 2018		160,676			16		1,091,441			(45,007	)		1,046,450
Net income (loss)		—			—		—			146,668			146,668
Long-term incentive plan forfeitures		(43	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		(20	)		—		(39	)		—			(39	)
Stock-based compensation		—			—		3,965			—			3,965

Balances at December 31, 2018		160,613		$	16	$	1,095,367		$	101,661		$	1,197,044

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,

	2019			2018
Cash flows from operating activities:
Net income (loss)	$	(336,559	)	$	(2,598	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		29,975			15,991
Full cost ceiling impairment		275,239			—
(Gain) loss on sale of oil and natural gas properties		—			3,679
(Gain) loss on sale of Water Assets		885			—
Deferred income tax provision (benefit)		(45,485	)		—
Stock-based compensation, net		(6,782	)		3,581
Unrealized loss (gain) on derivative contracts		68,169			(11,113	)
Amortization of deferred loan costs		404			292
Amortization of discount and premium		55			132
Other income (expense)		1,408			106
Change in assets and liabilities:
Accounts receivable		(3,414	)		(5,213	)
Prepaids and other		(2,876	)		108
Accounts payable and accrued liabilities		(17,853	)		(17,547	)

Net cash provided by (used in) operating activities		(36,834	)		(12,582	)

Cash flows from investing activities:
Oil and natural gas capital expenditures		(81,068	)		(127,885	)
Proceeds received from sale of oil and natural gas properties		—			(4,034	)
Acquisition of oil and natural gas properties		(2,809	)		(132,464	)
Other operating property and equipment capital expenditures		(30,553	)		(30,721	)
Proceeds received from sale of other operating property and equipment		—			1,899
Funds held in escrow and other		(1	)		157

Net cash provided by (used in) investing activities		(114,431	)		(293,048	)

Cash flows from financing activities:
Proceeds from borrowings		124,000			206,000
Repayments of borrowings		(19,000	)		—
Debt issuance costs		—			(3,371	)
Common stock issued		—			63,480
Offering costs and other		(406	)		(2,475	)

Net cash provided by (used in) financing activities		104,594			263,634

Net increase (decrease) in cash and cash equivalents		(46,671	)		(41,996	)
Cash and cash equivalents at beginning of period		46,866			424,071

Cash and cash equivalents at end of period	$	195		$	382,075



Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$	(43	)	$	210

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 oil and natural gas assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. 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 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on March 12, 2019. Please refer to the notes in the 2018 Annual Report on Form 10-K when reviewing interim financial results.

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 accruals, 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 predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's unaudited condensed consolidated financial statements.

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

Ability to Continue as a Going Concern

The Company's strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in the Company divesting producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin. The Company's drilling activities since acquiring the assets required significant capital expenditure outlays to replace lost production and related EBITDA. These and other factors adversely impacted the Company's ability

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

to comply with its debt covenants under the Senior Credit Agreement. Anticipating that it might be challenging to comply with the covenants under the Senior Credit Agreement, the Company has periodically sought and obtained amendments and consents from the lenders under the Senior Credit Agreement. Most recently, on May 8, 2019, the Company entered into an amendment to the Senior Credit Agreement in which its lenders waived compliance with the Consolidated Total Net Debt to EBITDA Ratio covenant contained in the Senior Credit Agreement for the three months ended March 31, 2019, while raising the applicable margin on the Company's borrowings and imposing certain reporting and other obligations upon the Company. The waiver extends, as to compliance at March 31, 2019, until August 1, 2019; provided that it may be terminated on July 1, 2019 by the majority lenders in their sole discretion and earlier upon the occurrence of certain other events (an Early Termination). The lenders under the Senior Credit Agreement concurrently redetermined the borrowing base to $225.0 million, a reduction from $275.0 million at December 31, 2018. At March 31, 2019, the Company had borrowings of $105.0 million outstanding under the Senior Credit Agreement. The Company's current internal projections show that it will not be in compliance with the Consolidated Total Net Debt to EBITDA Ratio and the Current Ratio covenants in certain future periods, beginning with the three months ended June 30, 2019. The Company sought amendment of the covenants for the twelve month period following the issuance date of the unaudited condensed consolidated financial statements included in this report, which the lenders did not approve. As a consequence, if the Company fails to comply with the financial covenants under the Senior Credit Agreement for the three months ended June 30, 2019, as projected, or there is an Early Termination, it will be in default under the Senior Credit Agreement. An Event of Default (as defined in the Senior Credit Agreement) would permit the lenders to accelerate any indebtedness outstanding under the Senior Credit Agreement, making it immediately due and payable. If the indebtedness under the Senior Credit Agreement is accelerated, then an Event of Default (as defined in the indenture governing the Company's senior notes) under the senior notes would occur, which, if continued beyond any applicable cure period, would result in the entire principal under the senior notes being due and payable immediately. If the lenders, and subsequently noteholders, accelerate the outstanding indebtedness (the aggregate principal amount of which was approximately $730.0 million as of March 31, 2019), all such indebtedness will become immediately due and payable. The Company currently does not have sufficient liquidity to repay those amounts. In addition, should amounts under the Senior Credit Agreement become due and payable, the Company's derivatives that are in a net liability position could also become due and payable. As a result of the Company's expected inability to comply with its Consolidated Total Net Debt to EBITDA Ratio and its Current Ratio covenants contained in its Senior Credit Agreement within one year from the issuance date of the unaudited condensed consolidated financial statements for the three months ended March 31, 2019, the Company has determined that there are conditions and events that raise substantial doubt about the Company's ability to continue as a going concern.

The Company has engaged advisors to evaluate strategic and financial alternatives and is pursuing options to maintain sufficient liquidity and to address its Senior Credit Agreement covenant compliance, including (i) working with the bank syndicate to amend the Senior Credit Agreement and/or obtain waivers of covenant compliance for future periods, (ii) seeking alternative sources of capital, (iii) divesting assets, (iv) exploring strategic merger and acquisition options and (v) reducing operating costs. There can be no assurance that the Company will be able to comply with the covenants in its Senior Credit Agreement, that the lenders will provide any covenant relief or fail to exercise their right to Early Termination or that the Company will be able to obtain alternative financing on a timely basis and on satisfactory terms, or at all. In addition, no assurance can be given that any such financing,

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

if obtained, will be adequate to meet its capital needs and support its business plans while paying or refinancing the existing debt obligations. If alternative financing cannot be obtained on a timely basis and on satisfactory terms, then the Company's operations would be materially negatively impacted.

Accordingly, the Company classified outstanding borrowings under its Senior Credit Agreement as a current liability on its unaudited condensed consolidated balance sheet as of March 31, 2019. The unaudited condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value.

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. As of March 31, 2019 and December 31, 2018, allowances for doubtful accounts were approximately $0.1 million and $0.2 million, respectively.

Other Operating Property and Equipment

Other operating property and equipment additions are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: gas gathering systems, thirty years; gas treating systems and buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, the lesser of lease term or five years; trailers, seven years; heavy equipment, eight to ten 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 or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

The Company reviews its other operating property and equipment for impairment in accordance with Accounting Standards Codification (ASC) No. 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate other operating property and equipment 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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.

Leases

Effective January 1, 2019, the Company accounts for leases in accordance with ASC No. 842, Leases, (ASC 842). The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset.

The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in "Operating lease right of use assets" and "Operating lease liabilities" on our unaudited condensed consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date.

Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise.

The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company's operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

Variable lease payments associated with the Company's leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as "Gathering and other" or "General and administrative" in our unaudited condensed consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases.

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case-by-case basis.

The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use 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.

The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, a corresponding adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the unaudited condensed consolidated statements of operations.

The Company elected not to recognize right of use assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short-term leases as an expense on a straight-line basis over the lease term. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases.

Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics).

Restructuring

During the three months ended March 31, 2019, four executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, the Company had reductions in its workforce due to a decrease in drilling and developmental activities planned for 2019. Consequently, for the three months ended March 31, 2019, the Company incurred approximately $11.3 million in severance costs which were recorded in "Restructuring" on the unaudited condensed consolidated statements of operations.

Related Party Transactions

Crude Oil Gathering Agreement

On July 27, 2018, a subsidiary of the Company entered into a crude oil gathering agreement with SCM Crude, LLC (SCM) pursuant to which the Company agreed to dedicate, for a term of 15 years, production of crude oil from its currently owned, or later acquired acreage in designated areas in Ward and Winkler Counties, Texas (excluding certain specific wells) for the receipt, gathering and transportation on a gathering system to be designed, engineered and constructed by SCM. In the fourth quarter of 2018, the Company began selling its crude oil to SCM while the gathering system was under construction. The gathering system was completed and placed into service in March 2019. For the three

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

months ended March 31, 2019, the Company earned $39.2 million from SCM under the crude oil gathering agreement and as of March 31, 2019 recorded an $11.2 million receivable from SCM for its crude oil sales.

Certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM. Ares also controls other funds which own in excess of ten percent (10%) of the common stock of the Company. No Ares fund that is a stockholder of the Company has an interest in SCM but one of the Company's directors, who is employed by Ares, also serves on the board of directors of SCM's parent company.

Gas Purchase and Processing Agreement

On November 16, 2017, a subsidiary of the Company entered into a gas purchase and processing agreement with Salt Creek Midstream, LLC (Salt Creek) pursuant to which the Company agreed to dedicate for a term of 15 years, all production from its acreage in Ward County, Texas (that is not otherwise previously dedicated) and certain sections in Winkler County, Texas to a natural gas gathering pipeline and processing facilities to be constructed by Salt Creek. The facilities were completed and placed in service in May 2018. For the three months ended March 31, 2019, the Company earned $0.2 million from Salt Creek under the gas purchase and processing agreement and as of March 31, 2019 recorded a $0.8 million receivable from Salt Creek for its natural gas sales.

Certain funds under the control of Ares are the majority owners and controlling parties of Salt Creek. Ares also controls other funds which own in excess of ten percent (10%) of the stock of the Company. No Ares fund that is a stockholder of the Company has an interest in Salt Creek but one of the Company's directors, who is employed by Ares, and is a director of the Company, also serves on the board of directors of Salt Creek.

Pipeline Testing Services

In February 2019, the Company entered into an agreement with Cima Inspection LLC (Cima), a company specializing in advanced, non-destructive methods of testing pipes and tubing, pursuant to which Cima will inspect various Company gathering and transportation assets. One of the Company's directors owns a minority interest in Cima and currently serves, without compensation, as its chief executive officer. The engagement of Cima was the result of a lengthy process during which Halcón investigated the most cost-effective method of conducting testing on its gathering and transportation assets. Halcón considered the performance and cost of various alternatives and solicited proposals from third parties before determining that Cima's proposal offered the most timely cost efficient solution to the Company's needs. As a result of the relationship of one of the Company's directors with Cima, the process by which the Company determined Cima's proposal to be superior to others, as well as the terms of the agreement, were evaluated and approved by the Audit Committee and the disinterested members of Halcón's board, in a vote that excluded that director in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company's website at www.halconresources.com), and the Company's procedures for the review and approval of transactions with related parties. For the three months ended March 31, 2019, the Company incurred charges of approximately $0.3 million for services provided by Cima. As of March 31, 2019, the Company recorded a $0.2 million payable to Cima. The

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payable is recorded in "Accounts payable and accrued liabilities," on the Company's unaudited condensed consolidated balance sheet.

Charter of Aircraft

In the ordinary course of business, Halcón occasionally chartered a private aircraft for business use. Floyd C. Wilson, Halcón's former Chairman, Chief Executive Officer and President, indirectly owns an aircraft which the Company chartered from time to time. During 2019, fees for the use of Mr. Wilson's aircraft by the Company were based upon comparable costs that the Company would have incurred in chartering the same type and size of aircraft from an independent third party utilizing data from several independent third party aircraft leasing companies. The terms for this use were evaluated and approved by the Audit Committee, and subsequently by the disinterested members of the Company's board upon the recommendation of the Audit Committee, in accordance with the Company's procedures for the review and approval of transactions with related parties. During the three months ended March 31, 2019, the Company paid approximately $0.2 million related to use of the aircraft indirectly owned by Mr. Wilson during 2018. In 2019, the Company terminated all charter arrangements with Mr. Wilson relating to the use of his aircraft.

Recently Issued Accounting Pronouncements

In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective approach as of the adoption date. See "Leases" above and Note 2, "Leases," below for further details.

2. LEASES

Adoption of Accounting Standards Codification 842, Leases

On January 1, 2019, the Company adopted ASC 842 using the modified retrospective approach as of the adoption date. Reporting periods beginning after January 1, 2019 are presented under ASC 842, while prior period amounts are not adjusted and continue to be reported under the accounting

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2. LEASES (Continued)

standards in effect for those periods. The table below details the impact of adoption on the Company's unaudited condensed consolidated balance sheet as of January 1, 2019 (in thousands):

	December 31, 2018		Impact of adoption of ASC 842			January 1, 2019

Other noncurrent assets:
Operating lease right of use assets	$	—	$	5,462		$	5,462
Current liabilities:
Accounts payable and accrued liabilities	$	157,848	$	(85	)	$	157,763
Operating lease liabilities		—		2,103			2,103
Other noncurrent liabilities:
Operating lease liabilities		—		3,444			3,444

Practical Expedients

The Company elected the following practical expedients for transition to, and ongoing accounting under, ASC 842: i) the Company does not separate lease and non-lease components of a contract, ii) the Company does not reassess whether expired or existing contracts contain leases, nor does it reassess the lease classification for expired or existing leases and does not reassess whether previously capitalized initial direct costs would qualify for capitalization under ASC 842, iii) the Company applies a single discount rate to a portfolio of leases with reasonably similar characteristics and iv) the Company does not assess whether existing or expired land easements that were not previously accounted for as leases are or contain a lease under ASC 842.

Leases

The Company leases equipment and office space under operating leases. The operating leases have initial lease terms ranging from 1 to 5 years, some of which include options to extend or renew the leases for one year. Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. The table below summarizes the Company's leases for the three months ended March 31, 2019 (in thousands, except years and discount rate):

	Three Months Ended March 31, 2019

Lease cost
Operating lease costs	$	644
Short-term lease costs		5,718
Variable lease costs		425

Total lease costs	$	6,787



Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	1,229
Right-of-use assets obtained in exchange for new operating lease liabilities		5,462
Weighted-average remaining lease term—operating leases		3.6 years
Weighted-average discount rate—operating leases		4.83	%

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2. LEASES (Continued)

Future minimum lease payments associated with the Company's non-cancellable operating leases for office space and equipment as of March 31, 2019, are presented in the table below (in thousands):

	March 31, 2019

Remaining period in 2019	$	1,672
2020		1,360
2021		876
2022		574
2023		585
Thereafter		345

Total operating lease payments		5,412

Less: discount to present value		449

Total operating lease liabilities		4,963

Less: current operating lease liabilities		1,868

Noncurrent operating lease liabilities	$	3,095

Prior to the adoption of ASC 842, future obligations, including variable nonlease components, associated with the Company's non-cancellable operating leases for office space and equipment as of December 31, 2018, are presented in the table below (in thousands):

	December 31, 2018

2019	$	3,792
2020		2,350
2021		1,899
2022		968
2023		999
Thereafter		599

Total operating lease payments	$	10,607

3. OPERATING REVENUES

Revenue Recognition

Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, that are collected by the Company from a customer, are excluded from revenue. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Because the Company's performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of

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3. OPERATING REVENUES (Continued)

$30.7 million and $26.4 million as of March 31, 2019 and December 31, 2018, respectively, as "Accounts receivable" on the unaudited condensed consolidated balance sheets.

Substantially all of the Company's revenues are derived from its single basin operations, the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. The following table disaggregates the Company's revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company's single basin operations, for the periods indicated (in thousands):

	Three Months Ended March 31,

	2019			2018
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	45,517		$	43,069
Natural gas		1,461			2,319
Natural gas liquids		4,945			3,712

Total oil, natural gas and natural gas liquids sales		51,923			49,100
Other		(7	)		155

Total operating revenues	$	51,916		$	49,255

Oil Sales

The Company generally markets its crude oil production directly to the customer using two methods. Under the first method, crude oil is sold at the wellhead at an index price adjusted for pricing differentials and other deductions. Revenue is recognized at the wellhead, where control of the crude oil transfers to the customer, at the net price received. Under the second method, crude oil is delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, net of transportation costs and other market-related adjustments. Revenue is recognized when control of the crude oil transfers at the delivery point at the net price received.

Settlement statements for the Company's crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded. Payment under the Company's crude oil contracts is typically due on or before the 20^th of the month following the delivery month.

Natural Gas and Natural Gas Liquids Sales

The Company evaluates its natural gas gathering and processing arrangements in place with midstream companies to determine when control of the natural gas is transferred. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity's

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processing plant, the Company is the principal and the midstream entity is the agent in the sale transaction with the third party purchaser of processed commodities. In these instances, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers through the gathering and treating process and presented as "Natural gas" or "Natural gas liquids" and any fees incurred to gather or process the natural gas are presented as "Gathering and other" on the unaudited condensed consolidated statements of operations.

Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity's processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as "Gathering and other" on the unaudited condensed consolidated statement of operations.

Settlement statements for the Company's natural gas and natural gas liquids production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. Historically, differences between the Company's estimates and the actual revenue received have not been material. Payment under the Company's natural gas gathering and processing contracts is typically due on or before the fifth day of the second month following the delivery month.

4. ACQUISITIONS AND DIVESTITURES

Acquisitions

West Quito Draw Properties

On February 6, 2018, a wholly owned subsidiary of the Company entered into a Purchase and Sale Agreement (the Shell PSA) with SWEPI LP (Shell), an affiliate of Shell Oil Company, pursuant to which the Company purchased acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) for a total adjusted purchase price of $198.5 million. The effective date of the acquisition was February 1, 2018, and the Company closed the transaction on April 4, 2018. The Company funded the cash consideration for the acquisition of the West Quito Draw Properties with the net proceeds from the issuance of additional 6.75% senior notes due 2025 and common stock, which are discussed in Note 6, "Debt," and Note 11, "Stockholders' Equity," respectively.

Monument Draw Assets (Ward and Winkler Counties, Texas)

On January 9, 2018, the Company purchased acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) that is prospective for the Wolfcamp and Bone Spring formations from a private company for $108.2 million in cash.

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Divestitures

Water Infrastructure Assets

On December 20, 2018, the Company sold its water infrastructure assets located in the Delaware Basin (the Water Assets) to WaterBridge Resources LLC (the Purchaser) for a total adjusted purchase price of $211.9 million in cash (the Water Infrastructure Divestiture). The effective date of the transaction was October 1, 2018. Additional incentive payments of up to $25.0 million per year for the next five years are available based on the Company's ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. The Company's ability to achieve the incentive thresholds will be driven by, among other things, its development program which will consider future market conditions and is subject to change.

Upon closing, the Company dedicated all of the produced water from its oil and natural gas wells within its Monument Draw, Hackberry Draw and West Quito Draw operating areas to the Purchaser. There are no drilling or throughput commitments associated with the Water Infrastructure Divestiture. The Purchaser will receive a current market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and the Purchaser will receive a market price for the supply of freshwater and recycled produced water to the Company.

The Company recognized a gain of $118.1 million on the sale of the Water Assets on the unaudited condensed consolidated statements of operations in "(Gain) loss on sale of Water Assets." The gain on the sale was reduced during the three months ended March 31, 2019 by approximately $0.9 million as a result of customary post-closing adjustments.

5. 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.

Additionally, 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.

At March 31, 2019, 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, 2019 of the West Texas Intermediate (WTI) crude oil spot price of $63.06 per barrel, adjusted by lease or field for quality, transportation

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5. OIL AND NATURAL GAS PROPERTIES (Continued)

fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended March 31, 2019 of the Henry Hub natural gas price of $3.07 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, 2019 exceeded the ceiling amount by $275.2 million ($217.4 million after taxes) which resulted in a ceiling test impairment charge of that amount for the quarter. The impairment was recorded in "Full cost ceiling test impairment" on the unaudited condensed consolidated statements of operations. The ceiling test impairment was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and the Company's intent to expend capital only on its most economic areas. As such, the Company identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019.

At March 31, 2018, 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, 2018 of the WTI crude oil spot price of $53.49 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, 2018 of the Henry Hub natural gas price of $3.00 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, 2018 did not exceed the ceiling amount.

Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

On September 7, 2017, the Company and certain of its subsidiaries sold of all of the Company's operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of its subsidiaries for a total adjusted sales price of approximately $1.39 billion (the Williston Divestiture). Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017. This gain was reduced by $3.7 million during the three months ended March 31, 2018 as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain (loss) was recorded in "Gain (loss) on sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

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6. DEBT

As of March 31, 2019 and December 31, 2018, the Company's current and long-term debt consisted of the following (in thousands):

	March 31, 2019		December 31, 2018

Senior revolving credit facility⁽¹⁾	$	105,000	$	—
6.75% senior notes due 2025⁽²⁾		613,493		613,105

	$	718,493	$	613,105

(1): Outstanding borrowings under the Company's Senior Credit Agreement as of March 31, 2019 were classified as a current liability. See "Senior Revolving Credit Facility" below for more details.
(2): Amount includes a $7.0 million and $7.2 million unamortized discount at March 31, 2019 and December 31, 2018, respectively, associated with the 2025 Notes. Amount includes a $5.2 million and $5.4 million unamortized premium at March 31, 2019 and December 31, 2018, respectively, associated with the Additional 2025 Notes. Additionally, these amounts are net of $9.7 million and $10.1 million unamortized debt issuance costs at March 31, 2019 and December 31, 2018, respectively. Refer to "6.75% Senior Notes" below for further details.

Senior Revolving Credit Facility

On September 7, 2017, the Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Senior Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the Senior Credit Agreement, the lenders party thereto have agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a current borrowing base of $225.0 million. The maturity date of the Senior Credit Agreement is September 7, 2022. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Amounts outstanding under the Senior Credit Agreement are guaranteed by certain of the Company's direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy. The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a

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Consolidated Total Net Debt to EBITDA Ratio (as defined in the Senior Credit Agreement), which was recently revised by the H2S Consent, the Severance and Office Payments Consent and the Eighth Amendment, as discussed below, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00 to 1.00.

At March 31, 2019, the Company had $105.0 million of indebtedness outstanding and approximately $1.8 million letters of credit outstanding. Under a borrowing base of $225.0 million, the Company had $118.2 million of borrowing capacity available under the Senior Credit Agreement.

On May 8, 2019, the Company entered into the Eighth Amendment (the Eighth Amendment) to the Senior Credit Agreement which, among other things, (i) waives any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increases interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) limits the Company's Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provides for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver will terminate and an Event of Default (as defined in the Senior Credit Agreement) will occur on August 1, 2019 unless certain requirements are satisfied and the lenders opt not to exercise their right to terminate the waiver earlier on July 1, 2019.

On February 28, 2019, the lenders party to the Senior Credit Agreement issued a consent (the Severance and Office Payments Consent) to the Company whereby Severance Payments and Office Payments (as defined in the Severance and Office Payments Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2019.

On February 15, 2019, the Company entered into the Seventh Amendment (the Seventh Amendment) to the Senior Credit Agreement which, among other things, provides for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amends the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA to be (a) 5.00 to 1.0 for the fiscal quarter ending March 31, 2019, (b) 4.75 to 1.0 for the fiscal quarter ending June 30, 2019, (c) 4.5 to 1.0 for the fiscal quarter ending September 30, 2019, (d) 4.25 to 1.0 for the fiscal quarter ending December 31, 2019, and (e) 4.0 to 1.0 for the fiscal quarter ending March 31, 2020 and any fiscal quarter thereafter.

On November 6, 2018, the lenders party to the Senior Credit Agreement issued a consent (the H2S Consent) to the Company whereby H2S Expenses (as defined in the H2S Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019.

After giving effect to the H2S Consent, the Severance and Office Payments Consent, and the waiver contained in the Eighth Amendment, at March 31, 2019, the Company was in compliance with the financial covenants under the Senior Credit Agreement. However, the Company's current internal projections show that it will not be in compliance with the Consolidated Total Net Debt to EBITDA

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

Ratio and the Current Ratio covenants in certain future periods, beginning with the three months ended June 30, 2019. As described in Note 1, "Financial Statement Presentation", the Company classified outstanding borrowings under its Senior Credit Agreement as a current liability within "Current portion of long-term debt" on its unaudited condensed consolidated balance sheet as of March 31, 2019.

6.75% Senior Notes

On February 16, 2017, the Company issued $850.0 million aggregate principal amount of new 6.75% senior notes due 2025 (the 2025 Notes) in a private placement exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (Securities Act), Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year. The 2025 Notes will mature on February 15, 2025. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers' discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the private placement to fund the repurchase and redemption of the outstanding 8.625% senior secured second lien notes, and for general corporate purposes.

The 2025 Notes are governed by an Indenture, dated as of February 16, 2017 (as supplemented, the February 2017 Indenture) by and among the Company, the Guarantors and U.S. Bank National Association, as Trustee, which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors 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. The February 2017 Indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries. Halcón, the issuer of the 2025 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In connection with the sale of the 2025 Notes, on February 16, 2017, the Company, the Guarantors and J.P. Morgan Securities LLC, on behalf of itself and as representative of the initial purchasers, entered into a Registration Rights Agreement (the 2017 Registration Rights Agreement) pursuant to which the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 365 days after closing. The Company completed the exchange offer for the 2025 Notes on February 1, 2018.

On July 25, 2017, the Company concluded a consent solicitation of the holders of the 2025 Notes (the Consent Solicitation) and obtained consents to amend the February 2017 Indenture from approximately 99% of the holders of the 2025 Notes. As supplemented, the February 2017 Indenture exempted, among other things, the Williston Divestiture from certain provisions triggered upon a sale of "all or substantially all of the assets" of the Company. Consenting holders of the 2025 Notes received a consent fee of 2.0% of principal, or $16.9 million. The Company recorded the $16.9 million consent fees paid as a discount on the 2025 Notes.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

On September 7, 2017, the Company commenced an offer to purchase for cash up to $425.0 million of the $850.0 million outstanding aggregate principal amount of its 2025 Notes at 103.0% of principal plus accrued and unpaid interest. The consummation of the Williston Divestiture constituted a "Williston Sale" under the February 2017 Indenture, and the Company was required to make an offer to all holders of the 2025 Notes to purchase for cash an aggregate principal amount up to $425.0 million of the 2025 Notes. The offer to purchase expired on October 6, 2017, with notes representing in excess of $425.0 million of principal amount validly tendered. As a result, on October 10, 2017, the Company repurchased approximately $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest of approximately $4.1 million.

On February 15, 2018, the Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at a price to the initial purchasers of 103.0% of par (the Additional 2025 Notes). The net proceeds from the sale of the Additional 2025 Notes were approximately $202.4 million after deducting initial purchasers' premiums, commissions and estimated offering expenses. The proceeds were used to fund the cash consideration for the acquisition of the West Quito Draw Properties, discussed further in Note 4, "Acquisitions and Divestitures," and for general corporate purposes, including to fund the Company's 2018 drilling program. These notes were issued under the February 2017 Indenture. The Additional 2025 Notes are treated as a single class with, and have the same terms as, the 2025 Notes.

The remaining unamortized discount on the 2025 Notes was $7.0 million at March 31, 2019. The unamortized premium on the Additional 2025 Notes was $5.2 million at March 31, 2019.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. At March 31, 2019 and December 31, 2018, the Company had approximately $10.7 million and $11.1 million, respectively, of unamortized debt issuance costs. The debt issuance costs for the Company's Senior Credit Agreement are presented in "Prepaids and other" and the debt issuance costs for the Company's senior unsecured debt are presented in "Long-term debt, net" on the unaudited condensed consolidated balance sheets.

7. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820, Fair Value Measurements (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's unaudited condensed consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

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.

As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. 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, 2019 and December 31, 2018 (in thousands):

	March 31, 2019

	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	16,067	$	—	$	16,067



Liabilities
Liabilities from derivative contracts	$	—	$	27,427	$	—	$	27,427

	December 31, 2018

	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	69,717	$	—	$	69,717



Liabilities
Liabilities from derivative contracts	$	—	$	12,907	$	—	$	12,907

Derivative contracts listed above as Level 2 include collars, puts, calls, fixed-price swaps and basis swaps 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" on the unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8, "Derivative and Hedging Activities," for additional discussion of derivatives.

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

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

equivalents, accounts receivables and accounts payables approximate their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair values of the Company's fixed interest rate, long-term debt instrument as of March 31, 2019 and December 31, 2018 (excluding discounts, premiums and debt issuance costs) (in thousands):

	March 31, 2019				December 31, 2018

Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
6.75% senior notes	$	625,005	$	376,566	$	625,005	$	458,210

The fair value of the Company's fixed interest debt instrument was calculated using Level 2 criteria. The fair value of the Company's senior notes is based on quoted market prices from trades of such debt.

The 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 9, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

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

It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of March 31, 2019, the Company did not post collateral under any of its derivative contracts as they are secured under the Company's Senior Credit Agreement or are uncollateralized trades.

The Company's crude oil, natural gas and natural gas liquids derivative positions at any point in time may consist of fixed-price swaps, basis swaps, and costless put/call "collars". Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

variable prices for crude oil and natural gas. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) where the product is sold and the relevant price index under which the production is hedged (i.e. Cushing). 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. 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 and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

At March 31, 2019, the Company had 56 open commodity derivative contracts summarized in the following tables: six natural gas collar arrangements, seven natural gas basis swaps, five natural gas liquids swaps, 17 crude oil basis swaps, 15 crude oil collar arrangements, two crude oil puts, two crude oil calls, one crude oil WTI NYMEX roll and one crude oil swap.

At December 31, 2018, the Company had 86 open commodity derivative contracts summarized in the following tables: nine natural gas collar arrangements, seven natural gas basis swaps, six natural gas liquids swaps, 26 crude oil basis swaps, 31 crude oil collar arrangements, two crude oil puts, four crude oil calls and one crude oil WTI NYMEX roll.

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, 2019 and December 31, 2018 (in thousands):

		Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	March 31, 2019		December 31, 2018		Balance sheet location	March 31, 2019			December 31, 2018
Commodity contracts	Current assets—receivables from derivative contracts	$	11,223	$	57,280	Current liabilities—liabilities from derivative contracts	$	(20,086	)	$	(3,768	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		4,844		12,437	Other noncurrent liabilities—liabilities from derivative contracts		(7,341	)		(9,139	)

Total derivatives not designated as hedging contracts under ASC 815		$	16,067	$	69,717		$	(27,427	)	$	(12,907	)

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. 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 (in thousands):

		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	Three Months Ended March 31,
Derivatives not designated as hedging contracts under ASC 815		2019			2018
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(68,169	)	$	11,113
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		3,370			(5,210	)

Total net gain (loss) on derivative contracts		$	(64,799	)	$	5,903

At March 31, 2019 and December 31, 2018, the Company had the following open crude oil, natural gas liquids and natural gas derivative contracts:

			March 31, 2019

					Floors			Ceilings			Basis Differential
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 2019 - June 2019	Basis Swap	Crude Oil		182,000	$—	$	—	$—	$	—	$(1.00) - $(1.18)	$	(1.09	)
April 2019 - June 2019	Collars	Crude Oil		182,000	50.00 - 51.00		50.50	55.00 - 56.00		55.50
April 2019 - September 2019	Basis Swap	Crude Oil		366,000							(6.20) - (7.60)		(6.90	)
April 2019 - December 2019	Basis Swap	Natural Gas		7,012,500							(1.05) - (1.40)		(1.18	)
April 2019 - December 2019	Basis Swap	Crude Oil		1,464,000							(0.98) - (6.50)		(3.95	)
April 2019 - December 2019	Collars	Crude Oil		2,475,000	50.00 - 58.00		53.76	55.20 - 63.00		60.41
April 2019 - December 2019	Collars	Natural Gas		6,600,000	2.52 - 2.70		2.60	3.00 - 3.10		3.01
April 2019 - December 2019	Swap	Natural Gas Liquid		1,100,000	29.08 - 30.15		29.33
April 2019 - December 2019	WTI NYMEX ROLL	Crude Oil		1,375,000	0.35		0.35
April 2019 - December 2019	Swap	Crude Oil		483,967	56.80		56.80
July 2019 - December 2019	Collars	Crude Oil		552,000	50.00 - 55.00		53.00	55.00 - 69.00		61.00
October 2019 - December 2019	Basis Swap	Crude Oil		460,000							3.45 - 4.00		3.72
October 2019 - December 2019	Collars	Crude Oil		92,000	51.00		51.00	56.00		56.00
January 2020 - December 2020	Basis Swap	Crude Oil		3,294,000							2.00 - 4.00		2.95
January 2020 - December 2020	Collars	Crude Oil		549,000	50.00		50.00	70.00		70.00
January 2020 - December 2020	Calls	Crude Oil		2,342,400				70.00		70.00
January 2020 - December 2020	Puts	Crude Oil		915,000	55.00		55.00
January 2020 - December 2020	Swap	Crude Oil		620,549	56.80		56.80
January 2021 - December 2021	Swap	Crude Oil		611,537	56.80		56.80
January 2022 - March 2022	Swap	Crude Oil		152,104	56.80		56.80

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

			December 31, 2018

						Floors			Ceilings			Basis Differential
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 2019 - March 2019	Calls	Crude Oil		1,350,000		$—	$	—	$62.64	$	62.64	$—	$	—
January 2019 - March 2019	Calls	Crude Oil		(1,350,000	)				58.64		58.64
January 2019 - March 2019	Collars	Crude Oil		90,000		46.75		46.75	51.75		51.75
January 2019 - June 2019	Collars	Crude Oil		181,000		51.00		51.00	56.00		56.00
January 2019 - September 2019	Basis Swap	Crude Oil		546,000								(6.20) - (7.60)		(6.90	)
January 2019 - December 2019	Basis Swap	Crude Oil		2,448,000								(0.98) - (6.50)		(2.80	)
January 2019 - December 2019	Basis Swap	Natural Gas		9,307,500								(1.05) - (1.40)		(1.18	)
January 2019 - December 2019	Collars	Crude Oil		3,650,000		50.00 - 58.00		53.87	55.20 - 63.00		60.07
January 2019 - December 2019	Collars	Natural Gas		8,760,000		2.52 - 2.70		2.60	3.00 - 3.10		3.01
January 2019 - December 2019	Swap	Natural Gas Liquids		1,460,000		29.08 - 30.15		29.33
January 2019 - December 2019	WTI NYMEX ROLL	Crude Oil		1,825,000		0.35		0.35
April 2019 - June 2019	Collars	Crude Oil		91,000		50.00		50.00	55.00		55.00
April 2019 - December 2019	Collars	Crude Oil		275,000		55.00		55.00	62.85		62.85
July 2019 - December 2019	Basis Swap	Crude Oil		460,000								(2.40) - (6.50)		(5.68	)
July 2019 - December 2019	Collars	Crude Oil		552,000		50.00 - 55.00		53.00	55.00 - 69.00		61.00
October 2019 - December 2019	Basis Swap	Crude Oil		460,000								3.45 - 4.00		3.72
October 2019 - December 2019	Collars	Crude Oil		92,000		51.00		51.00	56.00		56.00
October 2019 - December 2019	Swap	Natural Gas Liquids		92,000		32.50		32.50
January 2020 - December 2020	Basis Swap	Crude Oil		3,294,000								2.00 - 4.00		2.95
January 2020 - December 2020	Collars	Crude Oil		549,000		50.00		50.00	70.00		70.00
January 2020 - December 2020	Calls	Crude Oil		2,342,400					70.00		70.00
January 2020 - December 2020	Puts	Crude Oil		915,000		55.00		55.00

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, 2019 and December 31, 2018 (in thousands):

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	March 31, 2019			December 31, 2018			March 31, 2019			December 31, 2018
Gross Amounts Presented in the Consolidated Balance Sheet	$	16,067		$	69,717		$	(27,427	)	$	(12,907	)
Amounts Not Offset in the Consolidated Balance Sheet		(12,807	)		(10,263	)		12,807			10,263

Net Amount	$	3,260		$	59,454		$	(14,620	)	$	(2,644	)

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.

9. ASSET RETIREMENT OBLIGATIONS

The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For other operating property 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. ASSET RETIREMENT OBLIGATIONS (Continued)

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 period indicated below (inclusive of the current portion) (in thousands):


Liability for asset retirement obligations as of December 31, 2018	$	6,914
Liabilities settled and divested		(229	)
Additions		186
Accretion expense		100

Liability for asset retirement obligations as of March 31, 2019	$	6,971

10. COMMITMENTS AND CONTINGENCIES

Commitments

As of March 31, 2019, the Company has the following active drilling rig commitments (in thousands):

	March 31, 2019

Remaining period in 2019	$	1,321
2020		—
2021		—
2022		—
2023		—
Thereafter		—

Total	$	1,321

As of March 31, 2019, termination of the Company's active drilling rig commitments would require early termination penalties of $1.1 million, which would be in lieu of paying the remaining active drilling rig commitments of $1.3 million.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS AND CONTINGENCIES (Continued)

As of March 31, 2019, the Company has the following rig termination commitment related to a historical rig contract (in thousands):

	March 31, 2019

Remaining period in 2019	$	—
2020		3,000
2021		—
2022		—
2023		—
Thereafter		—

Total	$	3,000

As of March 31, 2019, the Company has the following purchase commitments related to equipment (in thousands):

	March 31, 2019

Remaining period in 2019	$	7,997
2020		—
2021		—
2022		—
2023		—
Thereafter		—

Total	$	7,997

The Company has entered into various long-term gathering, transportation and sales contracts with respect to production from the Delaware Basin in West Texas. As of March 31, 2019, the Company had in place three long-term crude oil contracts and ten long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging from one to twenty years from the date of first production.

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.

11. STOCKHOLDERS' EQUITY

Common Stock

On February 9, 2018, the Company sold 9.2 million shares of common stock, par value $0.0001 per share, in a public offering at a price of $6.90 per share. The net proceeds to the Company from the

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

offering were approximately $60.4 million, after deducting the underwriters' discounts and offering expenses. The Company used the net proceeds, together with the net proceeds from the issuance of the Additional 2025 Notes, to fund the cash consideration for the acquisition of the West Quito Draw Properties, and for general corporate purposes, including funding the Company's 2018 drilling program.

Warrants

On September 9, 2016, the Company issued 4.7 million new warrants. The warrants can be exercised to purchase 4.7 million shares of the Company's common stock at an exercise price of $14.04 per share. The holders are entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020.

Incentive Plans

On September 9, 2016, the Company's board of directors adopted the 2016 Long-Term Incentive Plan (the Plan). An aggregate of 10.0 million shares of the Company's common stock were available for grant pursuant to awards under the Plan. On April 6, 2017, Amendment No. 1 to the Plan to increase, by 9.0 million shares, the maximum number of shares of common stock that may be issued thereunder, i.e., a maximum of 19.0 million shares, became effective, which was 20 calendar days following the date the Company mailed an information statement to all stockholders of record notifying them of approval of the amendment by written consent of holders of a majority of the Company's outstanding stock. As of March 31, 2019 and December 31, 2018, a maximum of 1.1 million and 4.9 million shares, respectively of the Company's common stock remained reserved for issuance under the Plan.

The Company accounts for stock-based payment accruals under authoritative guidance on stock compensation. The guidance requires all stock-based payments to employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values. The Company has elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited.

For the three months ended March 31, 2019 and 2018 the Company recognized a credit of $6.8 million and expense of $3.6 million, respectively, related to stock-based compensation. Stock-based compensation expense is recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

During the three months ended March 31, 2019, four senior executives departed the Company. In accordance with the terms of these senior executives' employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the three months ended March 31, 2019, the Company recognized an incremental reduction to stock-based compensation expense of $8.4 million associated with these modifications.

Stock Options

From time to time, the Company grants stock options under the Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

No stock options were granted during the three months ended March 31, 2019. At March 31, 2019, the Company had $1.5 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 0.8 years.

During the three months ended March 31, 2018, the Company granted stock options under the Plan covering 1.2 million shares of common stock to employees of the Company. These stock options have an exercise price of $5.65 per share. During the three months ended March 31, 2018, the Company received $0.3 million from the exercise of stock options. At March 31, 2018, the Company had $13.1 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.2 years.

Restricted Stock

From time to time, the Company grants shares of restricted stock to employees and non-employee directors of the Company. Employee shares typically 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.

During the three months ended March 31, 2019, the Company granted 4.2 million shares of restricted stock under the Plan to employees of the Company. These restricted shares were granted at $1.29 per share. At March 31, 2019, the Company had $8.2 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.8 years.

During the three months ended March 31, 2018, the Company granted 1.9 million shares of restricted stock under the Plan to employees of the Company. These restricted shares were granted at $5.65 per share. At March 31, 2018, the Company had $12.5 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.7 years.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. 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,

	2019			2018
Basic:
Net income (loss)	$	(336,559	)	$	(2,598	)



Weighted average basic number of common shares outstanding		158,549			153,884

Basic net income (loss) per share of common stock	$	(2.12	)	$	(0.02	)



Diluted:
Net income (loss)	$	(336,559	)	$	(2,598	)



Weighted average basic number of common shares outstanding		158,549			153,884
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive
Exercise of warrants		Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive

Weighted average diluted number of common shares outstanding		158,549			153,884

Diluted net income (loss) per share of common stock	$	(2.12	)	$	(0.02	)

Common stock equivalents, including stock options, restricted shares and warrants totaling 14.9 million shares for the three months ended March 31, 2019 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, restricted shares and warrants totaling 13.2 million shares for the three months ended March 31, 2018 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following (in thousands):

	March 31, 2019		December 31, 2018

Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	30,705	$	26,432
Joint interest accounts		7,470		7,369
Other		3,224		1,917

	$	41,399	$	35,718



Prepaids and other:
Prepaids	$	3,646	$	3,503
Income tax receivable		1,250		1,250
Debt issuance costs		976		—
Other		2,768		35

	$	8,640	$	4,788



Funds in escrow and other:
Funds in escrow	$	573	$	570
Other		562		1,611

	$	1,135	$	2,181



Accounts payable and accrued liabilities:
Trade payables	$	55,668	$	68,959
Accrued oil and natural gas capital costs		40,492		41,461
Revenues and royalties payable		20,241		20,526
Accrued interest expense		6,343		16,971
Accrued employee compensation		2,729		3,421
Accrued lease operating expenses		11,152		6,292
Other		391		218

	$	137,016	$	157,848

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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, 2019 and 2018 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

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. During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota (the Williston Divestiture) and in the El Halcón area of East Texas. As a result, our properties and drilling activities are currently focused in the Delaware Basin of West Texas, where we have an extensive drilling inventory that we believe offers attractive economics.

During the first three months of 2019, production averaged 17,089 Boe/d compared to average daily production of 10,967 Boe/d during the first three months of 2018. Our average daily oil and natural gas production increased in the first three months of 2019 when compared to the same period in the prior year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. During the first three months of 2019, we participated in the drilling of 9 gross (8.6 net) wells, none of which were dry holes.

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

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could have a material impact upon our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for April 2019 of $61.59 per Bbl, and holding it constant for two months to create a trailing 12-month period of average prices, that is more reflective of recent price trends, our ceiling amount related to the net book value of our oil and natural gas properties would have been reduced and would have generated an additional impairment of $19.6 million ($15.5 million after taxes), holding all other inputs and factors constant. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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Recent Developments

Senior Revolving Credit Facility

On May 8, 2019, we entered into the Eighth Amendment (the Eighth Amendment) to the Senior Credit Agreement which, among other things, (i) waives any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increases interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) limits our Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provides for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver will terminate and an Event of Default (as defined in the Senior Credit Agreement) will occur on August 1, 2019 unless certain requirements are satisfied and the lenders opt not to exercise their right to terminate the waiver earlier on July 1, 2019.

On February 28, 2019, the lenders party to our Senior Credit Agreement issued a consent (the Severance and Office Payments Consent) to us whereby Severance Payments and Office Payments (as defined in the Severance and Office Payments Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2019.

On February 15, 2019, we entered into the Seventh Amendment (the Seventh Amendment) to the Senior Credit Agreement which, among other things, provides for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amends the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA to be (a) 5.00 to 1.0 for the fiscal quarter ending March 31, 2019, (b) 4.75 to 1.0 for the fiscal quarter ending June 30, 2019, (c) 4.5 to 1.0 for the fiscal quarter ending September 30, 2019, (d) 4.25 to 1.0 for the fiscal quarter ending December 31, 2019, and (e) 4.0 to 1.0 for the fiscal quarter ending March 31, 2020 and any fiscal quarter thereafter.

On November 6, 2018, the lenders party to our Senior Credit Agreement issued a consent (the H2S Consent) to us whereby H2S Expenses (as defined in the H2S Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019.

Sale of Water Infrastructure Assets

On December 20, 2018, we sold our water infrastructure assets located in the Delaware Basin (the Water Assets) to WaterBridge Resources LLC (the Purchaser) for an adjusted purchase price of $211.9 million in cash (the Water Infrastructure Divestiture) at closing. The effective date of the transaction was October 1, 2018. Additional incentive payments of up to $25.0 million per year for the next five years are available subject to our ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. Our ability to achieve the incentive thresholds will be driven by, among other things, our development program which will consider future market conditions and is subject to change.

Upon closing, we dedicated all of the produced water from our oil and natural gas wells within our Monument Draw, Hackberry Draw and West Quito Draw operating areas to the Purchaser. There are no drilling or throughput commitments associated with the Water Infrastructure Divestiture. The Purchaser will receive a current market price, subject to annual adjustments for inflation, in exchange

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for the transportation, disposal and treatment of such produced water, and the Purchaser will receive a market price for the supply of freshwater and recycled produced water provided to us.

Capital Resources and Liquidity

Our near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations and borrowings under our Senior Credit Agreement, which has a current borrowing base of $225.0 million. At March 31, 2019, we had $105.0 million of indebtedness outstanding and approximately $1.8 million letters of credit outstanding. Under a borrowing base of $225.0 million, we had $118.2 million of borrowing capacity available under the Senior Credit Agreement. Amounts borrowed under the Senior Credit Agreement will mature on September 7, 2022. 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.

The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Consolidated Total Net Debt to EBITDA Ratio (as defined in the Senior Credit Agreement), which was recently revised by the H2S Consent, the Severance and Office Payments Consent, and the Eighth Amendment, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00. After giving effect to the H2S Consent, the Severance and Office Payments Consent, and the waiver contained in the Eighth Amendment, at March 31, 2019, we were in compliance with the financial covenants under the Senior Credit Agreement.

We have recently, and in the past, obtained amendments and consents 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 as a result of our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin and unforeseen operational challenges. Specifically, on May 8, 2019, we entered into the Eighth Amendment to the Senior Credit Agreement which, among other things, waived any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019. The waiver extends, as to compliance at March 31, 2019, until August 1, 2019; provided that it may be terminated on July 1, 2019 by the majority lenders in their sole discretion and earlier upon the occurrence of certain other events (an Early Termination). On February 28, 2019, the lenders party to the Senior Credit Agreement issued the Severance and Office Payments Consent to the Company whereby Severance Payments and Office Payments (as defined in the Severance and Office Payments Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2019. On February 15, 2019, we entered into the Seventh Amendment which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of (a) 5.00 to 1.0 for the fiscal quarter ending March 31, 2019, (b) 4.75 to 1.0 for the fiscal quarter ending June 30, 2019, (c) 4.5 to 1.0 for the fiscal quarter ending September 30, 2019, (d) 4.25 to 1.0 for the fiscal quarter ending December 31, 2019, and (e) 4.0 to 1.0 for the fiscal quarter ending March 31, 2020 and any fiscal quarter thereafter. On November 7, 2018, we entered into the Fifth Amendment to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the

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Senior Credit Agreement) to EBITDA of (a) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (b) 4.25 to 1.0 for the fiscal quarter ending December 31, 2018 and (c) 4.0 to 1.0 for the fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter. On November 6, 2018, the lenders party to the Senior Credit Agreement issued the H2S Consent to us whereby H2S Expenses (as defined in the Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019. On July 12, 2018, we entered into the Fourth Amendment to the Senior Credit Agreement which provided for an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA (as defined in the Senior Credit Agreement) of (i) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (ii) 5.0 to 1.0 for the fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019, (iii) 4.25 to 1.0 for the fiscal quarter ending September 30, 2019 and (iv) 4.0 to 1.0 for the fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter; provided, however, that if we consummate a sale of all or a material portion of our midstream assets, then the ratio of Consolidated Total Net Debt to EBITDA shall be reduced to 4.0 to 1.0 for each fiscal quarter ending after the fiscal quarter in which such sale is consummated. On February 2, 2018, we entered into the Second Amendment to our Senior Credit Agreement. The Second Amendment, among other things, provides for (i) the use of annualized financial information in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending June 30, 2018, September 30, 2018 and December 31, 2018, (ii) an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of 4.50:1.00 for the fiscal quarter ending June 30, 2018, and a ratio of 4.00:1.00 for any fiscal quarter thereafter, (iii) a waiver of compliance with the covenant relating to the Consolidated Total Net Debt to EBITDA Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2018, and (iv) a waiver of the automatic reduction to the borrowing base that would otherwise result due to the issuance of our additional 6.75% senior notes due 2025.

Our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin. Our drilling activities since acquiring the assets required significant capital expenditure outlays to replace lost production and related EBITDA. These and other factors adversely impacted our ability to comply with our debt covenants under the Senior Credit Agreement by reducing our production, reserves and EBITDA on a current and a pro forma historical basis. Over the short term, our strategy makes us more susceptible to fluctuations in performance and compliance with these covenants more challenging. In addition, we have faced certain operational challenges that have impacted our ability to comply, including recently, elevated levels of H2S in the natural gas produced from our Monument Draw wells and severance payments associated with personnel changes.

Our current internal projections show that we will not be in compliance with our Consolidated Total Net Debt to EBITDA Ratio and our Current Ratio in certain future periods, beginning with the quarter ended June 30, 2019. We sought an amendment of the covenants for the twelve month period following the issuance date of the unaudited condensed consolidated financial statements included in this report, which our lenders did not approve. As a consequence, if we fail to comply with the financial covenants under the Senior Credit Agreement for the three months ended June 30, 2019, as projected, or there is an Early Termination, we will be in default under the Senior Credit Agreement. An Event of Default (as defined in the Senior Credit Agreement) would permit the lenders to accelerate any indebtedness outstanding under the Senior Credit Agreement, making it immediately due and payable. If the indebtedness under the Senior Credit Agreement is accelerated, then an Event of Default (as defined in the indenture governing our senior notes) under our senior notes would occur, which, if continued beyond any applicable cure period, would result in the entire principal under

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the senior notes being due and payable immediately. If our lenders, and subsequently noteholders, accelerate our outstanding indebtedness (the aggregate principal amount of which was approximately $730.0 million as of March 31, 2019), all such indebtedness will become immediately due and payable. We currently do not have sufficient liquidity to repay those amounts. In addition, should amounts under our Senior Credit Agreement become due and payable, our derivatives that are in a net liability position could also become due and payable. As a result of our expected inability to comply with the Consolidated Total Net Debt to EBITDA Ratio and the Current Ratio covenants contained in our Senior Credit Agreement within one year from the issuance date of the unaudited condensed consolidated financial statements for the three months ended March 31, 2019, we have determined that there are conditions and events that raise substantial doubt about our ability to continue as a going concern.

We have engaged advisors to evaluate our strategic and financial alternatives and we are pursuing options to maintain sufficient liquidity and to address our Senior Credit Agreement covenant compliance, including (i) working with our bank syndicate to amend our Senior Credit Agreement and/or obtain waivers of covenant compliance for future periods, (ii) seeking alternative sources of capital, (iii) divesting assets, (iv) exploring strategic merger and acquisition options and (v) reducing operating costs. There can be no assurance that we will be able to comply with the covenants in our Senior Credit Agreement that the lenders will provide any covenant relief or fail to exercise their right to Early Termination or that we will be able to obtain alternative financing on a timely basis and on satisfactory terms, or at all. In addition, no assurance can be given that any such financing, if obtained, will be adequate to meet our capital needs and support our business plans while paying or refinancing our existing debt obligations. If financing cannot be obtained on a timely basis and on satisfactory terms, then our operations would be materially negatively impacted. 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 acquisitions and other activities, which could result in a decrease in our production of oil and natural gas, subject us to forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and force us 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.

Additionally, the indenture governing our senior debt contains covenants limiting our ability to incur indebtedness unless we meet one of two alternative tests or utilize the limited exceptions available. The first test applies to all indebtedness and requires that, after giving effect to the incurrence of additional debt, our fixed charge coverage ratio (which is the ratio of our adjusted consolidated EBITDA (as defined in our indenture) to our adjusted consolidated interest expense over the trailing four fiscal quarters) will be at least 2.00:1.00. 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 indenture) and generally, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $350 million, (ii) the borrowing base in effect under our Senior Credit Agreement, and (iii) 30% of our adjusted consolidated net tangible assets, or ACNTA. ACNTA is defined in our indenture and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to our unevaluated properties. As of March 31, 2019, we were permitted to incur additional indebtedness under the indenture, but may be limited in the future. Lower oil and natural gas prices, among other factors, could reduce our adjusted consolidated EBITDA, as well as our ACNTA, and thus could reduce our ability to incur additional indebtedness.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and the capital markets and evaluate our development plans in light

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of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes. We strive to maintain financial flexibility while pursuing our drilling plans and may continue to access capital markets (if on acceptable terms) as necessary to, among other things, maintain adequate 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 under our Senior Credit Agreement is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our other indebtedness, 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 proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge varies from period to period based on our view of current and future market conditions. 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.

Cash Flow

During the three months ended March 31, 2019, cash and cash equivalents on hand supplemented with borrowings under our Senior Credit Agreement was used to fund our drilling and completion program. Our primary source of cash for the three months ended March 31, 2018 was from financing activities. During the three months ended March 31, 2018, cash generated by financing activities was used to fund the acquisition of acreage in our Monument Draw area, as well as our drilling and completion program. See "Results of Operations" for a review of the impact of prices and volumes on sales.

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

	Three Months Ended March 31,

	2019			2018
Cash flows provided by (used in) operating activities	$	(36,834	)	$	(12,582	)
Cash flows provided by (used in) investing activities		(114,431	)		(293,048	)
Cash flows provided by (used in) financing activities		104,594			263,634

Net increase (decrease) in cash and cash equivalents	$	(46,671	)	$	(41,996	)

Operating Activities. Net cash flows used in operating activities for the three months ended March 31, 2019 and 2018 were $36.8 million and $12.6 million, respectively.

Operating cash flows for the three months ended March 31, 2019 decreased from the comparable prior year period due to increases in our operating expenses, primarily severances paid to executives, natural gas treating costs, and third party water hauling and disposal costs, which were partially offset by increased oil and natural gas revenues and realized settlements on our derivative contracts.

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Operating cash flows for the three months ended March 31, 2018 decreased from the comparable prior year period primarily due to our divestitures in 2017, in which we divested non-core producing properties for primarily undeveloped acreage.

Investing Activities. Net cash flows used in investing activities were approximately $114.4 million and $293.0 million for the three months ended March 31, 2019 and 2018, respectively.

During the three months ended March 31, 2019, we spent $81.1 million on oil and natural gas capital expenditures, of which $76.7 million related to drilling and completion costs. We also spent approximately $30.6 million on capital expenditures related to our other operating property and equipment, primarily to develop our natural gas treating equipment and our oil and natural gas gathering infrastructure.

During the first three months of 2018, we incurred cash expenditures of $132.5 million on acquisition activities, which related to acreage acquisitions in our Monument Draw area. Additionally, we spent $127.9 million on oil and natural gas capital expenditures, of which $122.3 million related to drilling and completion costs. We also spent approximately $30.7 million on capital expenditures related to our other operating property and equipment, primarily to develop our water recycling facilities and gas gathering infrastructure.

Financing Activities. Net cash flows provided by financing activities were $104.6 million and $263.6 million for the three months ended March 31, 2019 and 2018, respectively.

During the three months ended March 31, 2019, net borrowings of $105.0 million under our Senior Credit Agreement were used to fund our drilling and completions program, as well as the development of our natural gas treating infrastructure and our oil and natural gas gathering infrastructure.

During the first three months of 2018, we issued an additional $200.0 million aggregate principal amount of our 6.75% senior notes due 2025. Proceeds from the private placement were approximately $202.5 million after deducting initial purchasers' premiums, commissions and estimated offering expenses. Additionally, we sold 9.2 million shares of common stock in a public offering at a price of $6.90 per share. The net proceeds from the offering were approximately $60.4 million after deducting underwriters' discounts and estimated offering expenses.

Contractual Obligations

There were no material changes outside the ordinary course of business to our commitments under contractual obligations from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

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, 2018.

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Results of Operations

Three Months Ended March 31, 2019 and 2018

We reported net losses of $336.6 million and $2.6 million for the three months ended March 31, 2019 and 2018, respectively. The table included below sets forth financial information for the periods presented.

	Three Months Ended March 31,

In thousands (except per unit and per Boe amounts)	2019			2018			Change
Net income (loss)	$	(336,559	)	$	(2,598	)	$	(333,961	)
Operating revenues:
Oil		45,517			43,069			2,448
Natural gas		1,461			2,319			(858	)
Natural gas liquids		4,945			3,712			1,233
Other		(7	)		155			(162	)
Operating expenses:
Production:
Lease operating		14,186			4,915			9,271
Workover and other		2,646			1,361			1,285
Taxes other than income		2,893			3,029			(136	)
Gathering and other		14,869			6,422			8,447
Restructuring		11,271			101			11,170
General and administrative:
General and administrative		11,390			11,629			(239	)
Stock-based compensation		(6,782	)		3,581			(10,363	)
Depletion, depreciation and accretion:
Depletion—Full cost		28,322			14,462			13,860
Depreciation—Other		1,553			1,466			87
Accretion expense		100			63			37
Full cost ceiling impairment		275,239			—			275,239
(Gain) loss on sale of oil and natural gas properties		—			3,679			(3,679	)
(Gain) loss on sale of Water Assets		885			—			885
Other income (expenses):
Net gain (loss) on derivative contracts		(64,799	)		5,903			(70,702	)
Interest expense and other		(12,589	)		(7,048	)		(5,541	)
Income tax benefit (provision)		45,485			—			45,485
Production:
Oil—MBbls		921			693			228
Natural Gas—Mmcf		1,941			886			1,055
Natural gas liquids—MBbls		293			146			147
Total MBoe⁽¹⁾		1,538			987			551
Average daily production—Boe⁽¹⁾		17,089			10,967			6,122
*Average price per unit⁽²⁾***:
Oil price—Bbl	$	49.42		$	62.15		$	(12.73	)
Natural gas price—Mcf		0.75			2.62			(1.87	)
Natural gas liquids price—Bbl		16.88			25.42			(8.54	)
Total per Boe⁽¹⁾		33.76			49.75			(15.99	)
Average cost per Boe:
Production:
Lease operating	$	9.22		$	4.98		$	4.24
Workover and other		1.72			1.38			0.34
Taxes other than income		1.88			3.07			(1.19	)
Gathering and other		9.67			6.51			3.16
Restructuring		7.33			0.10			7.23
General and administrative:
General and administrative		7.41			11.78			(4.37	)
Stock-based compensation		(4.41	)		3.63			(8.04	)
Depletion		18.41			14.65			3.76

(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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Oil, natural gas and natural gas liquids revenues were $51.9 million and $49.1 million for the three months ended March 31, 2019 and 2018, respectively. For the three months ended March 31, 2019 and 2018, production averaged 17,089 Boe/d and 10,967 Boe/d, respectively. Our average daily oil and natural gas production increased in the first three months of 2019 when compared to the same period in the prior year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. Average realized prices (excluding the effects of hedging arrangements) were $33.76 per Boe and $49.75 per Boe for the three months ended March 31, 2019 and 2018, respectively. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors.

Lease operating expenses were $14.2 million and $4.9 million for the three months ended March 31, 2019 and 2018, respectively. On a per unit basis, lease operating expenses were $9.22 per Boe and $4.98 per Boe for the three months ended March 31, 2019 and 2018, respectively. The increase in lease operating expenses from 2018 levels results from third party water hauling and disposal costs and an increase in our inventory of wells due to our drilling and acquisition activities.

Workover and other expenses were $2.6 million and $1.4 million for the three months ended March 31, 2019 and 2018, respectively. On a per unit basis, workover and other expenses were $1.72 per Boe and $1.38 per Boe for the three months ended March 31, 2019 and 2018, respectively. The increased costs in 2019 relate to an increase in our inventory of wells due to our drilling and acquisition activities.

Taxes other than income were $2.9 million and $3.0 million for the three months ended March 31, 2019 and 2018, respectively. 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 $1.88 per Boe and $3.07 per Boe for the three months ended March 31, 2019 and 2018, respectively.

Gathering and other expenses were $14.9 million and $6.4 million for the three months ended March 31, 2019 and 2018, respectively. Gathering and other expenses include gathering fees paid on our oil and natural gas production, operating expenses on our oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $3.8 million and $1.1 million for the three months ended March 31, 2019 and 2018, respectively, relate to gathering and marketing fees paid on our oil and natural gas production. Approximately $9.9 million and $4.4 million expenses for the three months ended March 31, 2019 and 2018, respectively, relate to operating expenses on our oil and gas gathering infrastructure and in the 2018 period, on our water recycling and disposal facilities. Approximately $8.2 million for the three months ended March 31, 2019 relate to costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties as a consequence of a third party pipeline temporarily going out of service. We have secured capacity on another third party pipeline for a portion of the natural gas produced in this area and have installed treating equipment which will alleviate reliance upon third party services for the removal of hydrogen sulfide from the natural gas produced. We expect these treating costs to decrease substantially after the first quarter of 2019. Also included are $0.8 million and $0.9 million of rig stacking charges for the three months ended March 31, 2019 and 2018, respectively.

During the three months ended March 31, 2019 and 2018, we incurred $11.3 million and $0.1 million, respectively, in restructuring expenses. During the three months ended March 31, 2109, four senior executives resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, we had reductions in our workforce due to a decrease in drilling and developmental

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activities planned for 2019. During the three months ended March 31, 2018, we terminated certain employees in conjunction with our divestitures.

General and administrative expense was $11.4 million and $11.6 million for the three months ended March 31, 2019 and 2018, respectively. On a per unit basis, general and administrative expenses were $7.41 per Boe and $11.78 per Boe for the three months ended March 31, 2019 and 2018, respectively. General administrative expense decreased as compared to the prior year period due to reductions in our workforce.

Stock-based compensation was a credit of $6.8 million and expense of $3.6 million for the three months ended March 31, 2019 and 2018, respectively. During the three months ended March 31, 2019, four senior executives resigned from their positions. In accordance with the terms of these senior executives' employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the three months ended March 31, 2019, we recognized an incremental reduction to stock-based compensation expense of $8.4 million associated with these modifications.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $28.3 million and $14.5 million for the three months ended March 31, 2019 and 2018, respectively. On a per unit basis, depletion expense was $18.41 per Boe and $14.65 per Boe for the three months ended March 31, 2019 and 2018, respectively. The increase in the depletion rate per Boe from the 2018 level is primarily attributable to increases in our depletable base as a result of our developmental drilling activities since the first quarter of 2018.

Under the full cost 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 charge of $275.2 million ($217.4 million after taxes) for the three months ended March 31, 2019. The ceiling test impairment was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and our intent to expend capital only on our most economic areas. As such, we identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019. Changes in commodity prices, 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.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves at the time of the transaction. Accordingly, we recognized a gain on the sale of the oil and natural gas properties associated with the Williston Divestiture of $3.7 million during the three months ended March 31, 2018, as a result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

On December 20, 2018, we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $211.9 million and we recognized a $118.1 million gain on the sale.

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The gain on the sale was reduced during the three months ended March 31, 2019 by approximately $0.9 million as a result of customary post-closing adjustments.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At March 31, 2019, we had a $16.1 million derivative asset, $11.2 million of which was classified as current and we had a $27.4 million derivative liability, $20.1 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $64.8 million ($68.2 million net unrealized loss and $3.4 million net realized gain on settled and early terminated contracts) for the three months ended March 31, 2019 compared a net derivative gain of $5.9 million ($11.1 million net unrealized gain and $5.2 million net realized loss on settled contracts), in the same period in 2018.

Interest expense and other was $12.6 million and $7.0 million for the three months ended March 31, 2019 and 2018, respectively. Interest expense increased during the three months ended March 31, 2019 as compared to the prior year period due to the issuance of additional 6.75% senior notes in February 2018 as well as fees paid in 2019 associated with consents and amendments to our Senior Credit Agreement.

We recorded an income tax benefit of $45.5 million for the three months ended March 31, 2019, resulting from the reduction to the deferred tax liability generated by the impact of the ceiling test impairment on oil and gas properties and the deferred tax asset created by the tax loss from operations. The 12% effective tax rate for the three months ended March 31, 2019 differs from the 21% statutory rate because of non-deductible executive compensation and non-deductible realized built in losses.

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, including price differentials between the NYMEX commodity price and the index price at the location where our production is sold. 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, fixed-price swaps and basis swaps. The total volumes that 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 anticipated production for the next 18 to 24 months, when derivative contracts are available at terms (or prices) acceptable to us. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with

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counterparties that are creditworthy institutions deemed by management as competitive market makers. As of March 31, 2019, we did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 8, "Derivative and Hedging Activities" for additional information.

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under ASC 825, Financial Instruments (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 7, "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, 2019, the principal amount of our debt was $730.0 million, of which approximately 86% bears interest at a weighted average fixed interest rate of 6.75% per year. The remaining 14% of our total debt at March 31, 2019 bears interest at floating and variable interest rates that, at our option, are tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At March 31, 2019, the weighted average interest rate on our variable rate debt was 7.00% per year. If the balance of our variable interest rate at March 31, 2019 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $0.7 million per year.

Item 4. Controls and Procedures

Under the supervision and with the participation of our management, including our Principal Executive Officer and our 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, 2019. On the basis of this review, our management, including our Principal 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 Principal 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 three months ended March 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of our business. While the outcome and impact of currently pending legal proceedings cannot be determined, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on our condensed 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, 2018, except as described below.

Uncertainty about our ability to remain in compliance with all of the restrictive covenants contained in our Senior Credit Agreement raises substantial doubt about our ability to continue as a going concern.

On May 8, 2019, we entered into an amendment of our Senior Credit Agreement in which our lenders waived our compliance with the Consolidated Total Net Debt to EBITDA Ratio covenant contained in our Senior Credit Agreement for the three months ended March 31, 2019. The waiver extends, as to compliance at March 31, 2019, until August 1, 2019; provided that it may be terminated on July 1, 2019 by the majority lenders in their sole discretion and earlier upon the occurrence of certain other events (an Early Termination). Our current internal projections show that we will not be in compliance with our Consolidated Total Net Debt to EBITDA Ratio and our Current Ratio covenants in certain future periods, beginning with the quarter ended June 30, 2019. We sought an amendment of the covenants for the twelve month period following the issuance date of the unaudited condensed consolidated financial statements included in this report, which our lenders did not approve. As a consequence, if we fail to comply with the financial covenants under the Senior Credit Agreement for the three months ended June 30, 2019, as projected, or there is an Early Termination we will be in default under the Senior Credit Agreement. An Event of Default (as defined in the Senior Credit Agreement) would permit the lenders to accelerate any indebtedness outstanding under the Senior Credit Agreement, making it immediately due and payable. If the indebtedness under the Senior Credit Agreement is accelerated, then an Event of Default (as defined in the indenture governing our senior notes) under our senior notes would occur, which, if continued beyond any applicable cure period, would result in the entire principal under the senior notes being due and payable immediately. If our lenders, and subsequently noteholders, accelerate our outstanding indebtedness (the aggregate principal amount of which was approximately $730.0 million as of March 31, 2019), all such indebtedness will become immediately due and payable. We currently do not have sufficient liquidity to repay those amounts. In addition, should amounts under our Senior Credit Agreement become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable.

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Senior Credit Agreement, that the lenders will provide any covenant relief or fail to exercise their right to Early Termination or that we will be able to obtain alternative financing on a timely basis and on satisfactory terms, or at all. In addition, no assurance can be given that any such financing, if obtained, will be adequate to meet our capital needs and support our business plans while paying or refinancing our existing debt obligations. If financing cannot be obtained on a timely basis and on satisfactory terms, then our operations would be materially negatively impacted.

The condensed consolidated financial statements included in this report have been prepared assuming that we will continue as a going concern and do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and reported amounts of income and expenses could be required and could be material. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, "Financial Statement Presentation" for more information.

If we become unable to continue as a going concern, we may find it necessary to file a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in order to provide us additional time to identify an appropriate solution to our financial situation and implement a plan of reorganization aimed at improving our capital structure.

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 2019	—	$	—	—	—
February 2019	61,527		1.79	—	—
March 2019	191,074		1.55	—	—

(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 acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

On May 8, 2019, the Company and the lenders under the Company's Senior Credit Agreement entered into the Eighth Amendment (the Eighth Amendment) to the Senior Credit Agreement which, among other things, (i) waives any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increases interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) limits the Company's Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provides for periodic reporting of projected cash flows and

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accounts payable agings to the lenders. Under the Eighth Amendment, the waiver will terminate and an Event of Default (as defined in the Senior Credit Agreement) will occur on August 1, 2019 unless certain requirements are satisfied and the lenders opt not to exercise their right to terminate the waiver earlier on July 1, 2019. The foregoing description of the Eighth Amendment does not purport to be complete. The Eighth Amendment is filed with this report as Exhibit 10.1.7 and is incorporated by reference into this report in its entirety.

Item 6. Exhibits

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


	3.1		Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated September 9, 2016 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed September 9, 2016).

	3.2		Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed May 7, 2015).

	3.2.1		Amendment No. 1 to the Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed September 9, 2016).

	10.1		Amended and Restated Senior Secured Revolving Credit Agreement, dated as of September 7, 2017, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 11, 2017).

	10.1.1		Second Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of February 2, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed February 8, 2018).

	10.1.2		Third Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 1, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1.2 of our Quarterly Report on Form 10-Q filed May 2, 2018).

	10.1.3		Fourth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of July 12, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 17, 2018).

	10.1.4		Fifth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 7, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 9, 2018).

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10.1.5		Sixth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 16, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 20, 2018).

10.1.6		Seventh Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of February 15, 2019, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed February 21, 2019).

10.1.7	*	Eighth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 8, 2019, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders.

31.1	*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer

31.2	*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer

32	*	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer

101.INS	*	XBRL Instance Document

101.SCH	*	XBRL Taxonomy Extension Schema Document

101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	*	XBRL Taxonomy Extension Definition Document

101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document

*: Attached hereto.
†: Indicates management contract or compensatory plan or arrangement.

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SIGNATURES

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


	HALCÓN RESOURCES CORPORATION
May 9, 2019	By:	/s/ DAVID S. ELKOURI
		Name:	David S. Elkouri
		Title:	Principal Executive Officer
May 9, 2019	By:	/s/ QUENTIN R. HICKS
		Name:	Quentin R. Hicks
		Title:	Executive Vice President, Chief Financial Officer and Treasurer