BATTALION OIL CORP - Quarter Report: 2019 June (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 June 30, 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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		HKRS		OTC Pink

At August 5, 2019, 164,039,916 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 and Six Months Ended June 30, 2019 and 2018	5
	Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2019 and December 31, 2018	6
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Three and Six Months Ended June 30, 2019 and the Year Ended December 31, 2018	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 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	41
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	57
ITEM 4.	Controls and Procedures	58
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	59
ITEM 1A.	Risk Factors	59
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
ITEM 3.	Defaults Upon Senior Securities	65
ITEM 4.	Mine Safety Disclosures	65
ITEM 5.	Other Information	65
ITEM 6.	Exhibits	65
Signatures		67

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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, are forward-looking statements, and include statements 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, our financial position, business strategy and other plans and objectives for future operations. Forward-looking statements may sometimes be 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:

•: the potential adverse impact of the restructuring transactions on our operations, management, and employees and the risks associated with operating our business during the restructuring process;
•: our ability to satisfy the conditions set forth in the Restructuring Support Agreement and consummate the Plan outlined in the Restructuring Support Agreement or another plan of reorganization;
•: risks and uncertainties associated with chapter 11 proceedings;
•: our ability to reduce the level of our debt and lower our cash interest obligations through consummation of the Plan or otherwise;
•: volatility in commodity prices for oil, 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;
•: we have 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;
•: our ability to replace our oil and natural gas reserves and production;
•: 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, sand, and other treatment materials to carry out fracture stimulations in our completion operations;

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•: our ability to secure adequate sour gas treating and/or sour gas take-away capacity in our Monument Draw area sufficient to handle production volumes;
•: 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;
•: 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 June 30,						Six Months Ended June 30,

	2019			2018			2019			2018
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	53,232		$	48,756		$	98,749		$	91,825
Natural gas		(1,655	)		1,560			(194	)		3,879
Natural gas liquids		4,297			4,991			9,242			8,703

Total oil, natural gas and natural gas liquids sales		55,874			55,307			107,797			104,407
Other		504			108			497			263

Total operating revenues		56,378			55,415			108,294			104,670

Operating expenses:
Production:
Lease operating		13,473			5,314			27,659			10,229
Workover and other		1,368			1,956			4,014			3,317
Taxes other than income		3,308			3,226			6,201			6,255
Gathering and other		11,041			5,956			25,910			12,378
Restructuring		654			27			11,925			128
General and administrative		12,519			14,255			17,127			29,465
Depletion, depreciation and accretion		40,425			16,096			70,400			32,087
Full cost ceiling impairment		664,383			—			939,622			—
(Gain) loss on sale of oil and natural gas properties		—			2,225			—			5,904
(Gain) loss on sale of Water Assets		2,897			—			3,782			—

Total operating expenses		750,068			49,055			1,106,640			99,763

Income (loss) from operations		(693,690	)		6,360			(998,346	)		4,907
Other income (expenses):
Net gain (loss) on derivative contracts		17,010			(12,100	)		(47,789	)		(6,197	)
Interest expense and other		(14,470	)		(10,534	)		(27,059	)		(17,582	)

Total other income (expenses)		2,540			(22,634	)		(74,848	)		(23,779	)

Income (loss) before income taxes		(691,150	)		(16,274	)		(1,073,194	)		(18,872	)
Income tax benefit (provision)		50,306			—			95,791			—

Net income (loss)	$	(640,844	)	$	(16,274	)	$	(977,403	)	$	(18,872	)



Net income (loss) per share of common stock:
Basic	$	(4.03	)	$	(0.10	)	$	(6.15	)	$	(0.12	)



Diluted	$	(4.03	)	$	(0.10	)	$	(6.15	)	$	(0.12	)



Weighted average common shares outstanding:
Basic		159,050			157,943			158,801			155,925



Diluted		159,050			157,943			158,801			155,925

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)

	June 30, 2019			December 31, 2018

Current assets:
Cash and cash equivalents	$	2,238		$	46,866
Accounts receivable		34,251			35,718
Receivables from derivative contracts		10,648			57,280
Prepaids and other		12,075			4,788

Total current assets		59,212			144,652

Oil and natural gas properties (full cost method):
Evaluated		2,113,296			1,470,509
Unevaluated		439,604			971,918

Gross oil and natural gas properties		2,552,900			2,442,427
Less—accumulated depletion		(1,646,116	)		(639,951	)

Net oil and natural gas properties		906,784			1,802,476

Other operating property and equipment:
Other operating property and equipment		191,277			130,251
Less—accumulated depreciation		(12,045	)		(8,388	)

Net other operating property and equipment		179,232			121,863

Other noncurrent assets:
Receivables from derivative contracts		4,820			12,437
Operating lease right of use assets		4,290			—
Funds in escrow and other		1,135			2,181

Total assets	$	1,155,473		$	2,083,609



Current liabilities:
Accounts payable and accrued liabilities	$	111,909		$	157,848
Liabilities from derivative contracts		11,814			3,768
Current portion of long-term debt, net		801,887			—
Operating lease liabilities		1,625			—
Asset retirement obligations		—			126

Total current liabilities		927,235			161,742

Long-term debt, net		—			613,105
Other noncurrent liabilities:
Liabilities from derivative contracts		4,248			9,139
Asset retirement obligations		7,085			6,788
Operating lease liabilities		2,748			—
Deferred income taxes		—			95,791
Commitments and contingencies (Note 10)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 164,123,186 and 160,612,852 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively		16			16
Additional paid-in capital		1,089,883			1,095,367
Retained earnings (accumulated deficit)		(875,742	)		101,661

Total stockholders' equity		214,157			1,197,044

Total liabilities and stockholders' equity	$	1,155,473		$	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
Net income (loss)		—			—		—			(640,844	)		(640,844	)
Long-term incentive plan grants		11			—		—			—			—
Long-term incentive plan forfeitures		(166	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		(42	)		—		(20	)		—			(20	)
Stock-based compensation		—			—		1,358			—			1,358

Balances at June 30, 2019		164,123		$	16	$	1,089,883		$	(875,742	)	$	214,157

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)

	Six Months Ended June 30,

	2019			2018
Cash flows from operating activities:
Net income (loss)	$	(977,403	)	$	(18,872	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		70,400			32,087
Full cost ceiling impairment		939,622			—
(Gain) loss on sale of oil and natural gas properties		—			5,904
(Gain) loss on sale of Water Assets		3,782			—
Deferred income tax provision (benefit)		(95,791	)		—
Stock-based compensation, net		(5,757	)		7,818
Unrealized loss (gain) on derivative contracts		57,405			26,761
Amortization and write-off of deferred loan costs		977			651
Amortization of discount and premium		111			183
Other income (expense)		(35	)		109
Change in assets and liabilities:
Accounts receivable		5,874			331
Prepaids and other		(6,547	)		(1,612	)
Accounts payable and accrued liabilities		(19,536	)		(9,782	)

Net cash provided by (used in) operating activities		(26,898	)		43,578

Cash flows from investing activities:
Oil and natural gas capital expenditures		(139,160	)		(251,961	)
Proceeds received from sale of oil and natural gas properties		1,247			1,779
Acquisition of oil and natural gas properties		(2,809	)		(332,901	)
Other operating property and equipment capital expenditures		(64,576	)		(53,242	)
Proceeds received from sale of other operating property and equipment		—			1,899
Funds held in escrow and other		(5	)		155

Net cash provided by (used in) investing activities		(205,303	)		(634,271	)

Cash flows from financing activities:
Proceeds from borrowings		244,000			206,000
Repayments of borrowings		(56,000	)		—
Debt issuance costs		—			(4,005	)
Common stock issued		—			63,480
Offering costs and other		(427	)		(2,983	)

Net cash provided by (used in) financing activities		187,573			262,492

Net increase (decrease) in cash and cash equivalents		(44,628	)		(328,201	)
Cash and cash equivalents at beginning of period		46,866			424,071

Cash and cash equivalents at end of period	$	2,238		$	95,870



Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$	(31	)	$	2,047

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 2018 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.

Ability to Continue as a Going Concern

On August 7, 2019, the Company and its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to pursue a pre-packaged plan of reorganization (the Plan). The Company expects to continue operations in the normal course during the pendency of the chapter 11 proceedings. Prior to filing the bankruptcy petitions, on August 2, 2019, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company's 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). See Note 14, "Subsequent Events," for more information.

The Company's debt agreements provide that the commencement of a voluntary proceeding in bankruptcy is an event of default leading to the automatic acceleration of the associated obligations. Accordingly, the filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code accelerated the Company's obligations under all of its outstanding debt instruments, although any efforts to enforce payment obligations thereunder have been automatically stayed by, and the creditors' rights of enforcement are subject to, the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Accordingly, the Company classified all of its outstanding debt as a current liability on its unaudited condensed consolidated balance sheet as of June 30, 2019.

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 the Company's management, 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 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.

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 June 30, 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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 the unaudited condensed consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases.

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, an 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.

Restructuring

During the six months ended June 30, 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 incurred costs to fill executive positions created by these resignations and had reductions in its workforce due to a decrease in drilling and developmental activities planned for 2019. Consequently, for the three and six months ended June 30, 2019, the Company incurred $0.7 million and

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

approximately $11.9 million, respectively, in severance costs which were recorded in "Restructuring" on the unaudited condensed consolidated statements of operations.

Income Taxes

For the three and six months ended June 30, 2019, the Company utilized the discrete effective tax rate method, as allowed by ASC 740, Income Taxes, to calculate its interim income tax provision. The discrete method is applied when it is not possible to reliably estimate the annual effective tax rate. The Company believes the use of the discrete method is more appropriate than the annual effective tax rate method at this time because of the uncertainties caused by the Company's filing of a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code. The uncertainties include, but are not limited to, the 1) level of capital spending in future periods and its impact on production and future ceiling impairment analysis 2) the expected allocation of income for the year between the pre- and post-emergence periods, and 3) the expected level of interest expense and restructuring expenses for the year.

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 and six months ended June 30, 2019, the Company recorded revenue of $28.3 million and $64.4 million, respectively, from SCM under the crude oil gathering agreement. As of June 30, 2019, the Company recorded a $10.3 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 and six months ended June 30, 2019, the Company recorded revenue of $0.6 million and $2.2 million, respectively, from Salt Creek under the gas purchase and processing agreement. As of June 30, 2019, the Company recorded a $0.5 million receivable from Salt Creek for its natural gas sales.

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 as its chief executive officer. For the three and six months ended June 30, 2019, the Company incurred charges of approximately $0.3 million and $0.6 million, respectively, for services provided by Cima. As of June 30, 2019, the Company recorded a $0.1 million payable to Cima.

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 2018, 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. In the first quarter of 2019, the Company terminated all charter arrangements with Mr. Wilson relating to the use of his aircraft. During the six months ended June 30, 2019, the Company paid approximately $0.2 million, related to use of the aircraft indirectly owned by Mr. Wilson during 2018.

Recently Issued Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (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,

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2. LEASES (Continued)

while prior period amounts are not adjusted and continue to be reported under the accounting 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

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2. LEASES (Continued)

instances, variable payments. The table below summarizes the Company's leases for the six months ended June 30, 2019 (in thousands, except years and discount rate):

	Six Months Ended June 30, 2019

Lease cost
Operating lease costs	$	1,288
Short-term lease costs		9,666
Variable lease costs		771

Total lease costs	$	11,725



Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	1,290
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	%

Future minimum lease payments associated with the Company's non-cancellable operating leases for office space and equipment as of June 30, 2019, are presented in the table below (in thousands):

	June 30, 2019

Remaining period in 2019	$	1,028
2020		1,360
2021		876
2022		574
2023		585
Thereafter		345

Total operating lease payments		4,768

Less: discount to present value		395

Total operating lease liabilities		4,373

Less: current operating lease liabilities		1,625

Noncurrent operating lease liabilities	$	2,748

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2. LEASES (Continued)

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 $25.2 million and $26.4 million as of June 30, 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 June 30,					Six Months Ended June 30,

	2019			2018		2019			2018
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	53,232		$	48,756	$	98,749		$	91,825
Natural gas		(1,655	)		1,560		(194	)		3,879
Natural gas liquids		4,297			4,991		9,242			8,703

Total oil, natural gas and natural gas liquids sales		55,874			55,307		107,797			104,407
Other		504			108		497			263

Total operating revenues	$	56,378		$	55,415	$	108,294		$	104,670

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3. OPERATING REVENUES (Continued)

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 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.

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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.

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 $211.0 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 years from 2019 to 2023 were 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. In August 2019, the Company and the Purchaser agreed to terminate the incentive payments provision.

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.

For the year ended December 31, 2018, the Company recognized a gain of $119.0 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 six months ended June 30, 2019 by approximately $3.8 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,

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5. OIL AND NATURAL GAS PROPERTIES (Continued)

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 June 30, 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 June 30, 2019 of the West Texas Intermediate (WTI) crude oil spot price of $61.45 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2019 of the Henry Hub natural gas price of $3.018 per million British thermal units (MMBtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2019 exceeded the ceiling amount by $664.4 million which resulted in a ceiling test impairment charge of that amount for the quarter. The ceiling test impairment at June 30, 2019 was primarily driven by the Company's continued focus on its most economic area, Monument Draw. Accordingly, the Company transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019, the majority of which is associated with the Company's Hackberry Draw area. At March 31, 2019, the Company recorded a full cost ceiling impairment of $275.2 million. The ceiling test impairment at March 31, 2019 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. The impairments were recorded in "Full cost ceiling test impairment" on the unaudited condensed consolidated statements of operations.

At June 30, 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 June 30, 2018 of the WTI crude oil spot price of $57.67 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2018 of the Henry Hub natural gas price of $2.92 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 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.

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5. OIL AND NATURAL GAS PROPERTIES (Continued)

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 $5.9 million during the six months ended June 30, 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.

6. DEBT

As of June 30, 2019 and December 31, 2018, the Company's debt consisted of the following (in thousands):

	*June 30, 2019⁽¹⁾***		December 31, 2018

Senior revolving credit facility	$	188,000	$	—
6.75% senior notes due 2025⁽²⁾		613,887		613,105

	$	801,887	$	613,105

(1): The Company's debt balance as of June 30, 2019 was classified as a current liability. See Note 14," Subsequent Events," for more details.
(2): Amount includes a $6.7 million and $7.2 million unamortized discount at June 30, 2019 and December 31, 2018, respectively, associated with the 2025 Notes. Amount includes a $5.0 million and $5.4 million unamortized premium at June 30, 2019 and December 31, 2018, respectively, associated with the Additional 2025 Notes. Additionally, these amounts are net of $9.4 million and $10.1 million unamortized debt issuance costs at June 30, 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 agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a borrowing base of $225.0 million as of June 30, 2019. On July 29, 2019, the Company borrowed approximately $16.2 million, resulting in the Company having an aggregate $223.2 million of indebtedness outstanding under the Senior Credit Agreement. The maturity date of the Senior Credit

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6. DEBT (Continued)

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 Consolidated Total Net Debt to EBITDA Ratio (each as defined in the Senior Credit Agreement) and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00 to 1.00.

On May 9, 2019, the Company entered into the Eighth Amendment, Consent and Waiver to Amended and Restated Senior Secured Credit Agreement (the Eighth Amendment) which, among other things, (i) temporarily 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, (ii) increased interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) reduced the Company's Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provided for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver would have terminated and an Event of Default (as defined in the Senior Credit Agreement) would have occurred on August 1, 2019. On July 31, 2019, the Company entered into the Waiver to Amended and Restated Senior Secured Credit Agreement, pursuant to which the termination date for the waiver granted by the Eighth Amendment was extended to August 8, 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

On February 15, 2019, the Company entered into the Seventh Amendment (the Seventh 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 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 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.

At June 30, 2019, the Company had $188.0 million of indebtedness outstanding and approximately $1.8 million letters of credit outstanding.

The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 1, "Financial Statement Presentation," constituted an event of default under the Senior Credit Agreement that accelerated the Company's obligations and terminated the lenders' commitments under the Senior Credit Agreement. During the chapter 11 proceedings, amounts outstanding under the Senior Credit Agreement will bear interest at a rate per annum equal to 2.0% plus the applicable interest rate in effect. Refer to Note 14, "Subsequent Events," for a discussion of the Company's debtor-in-possession and exit financing facilities.

6.75% Senior Notes

On February 16, 2017, the Company issued $850.0 million aggregate principal amount of new 6.75% senior unsecured 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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

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 wholly-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.

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 $6.7 million at June 30, 2019. The unamortized premium on the Additional 2025 Notes was $5.0 million at June 30, 2019.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

Indenture. Refer to Note 14, "Subsequent Events," for a discussion of the Company's debtor-in-possession and exit financing facilities.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. For the six months ended June 30, 2019, the Company expensed $0.2 million of debt issuance costs in conjunction with a decrease in the borrowing base under the Senior Credit Agreement. At June 30, 2019 and December 31, 2018, the Company had approximately $10.1 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 "Funds in escrow and other" within total assets on the unaudited condensed consolidated balance sheets, and the debt issuance costs for the Company's senior unsecured debt are presented in "Current portion of long-term debt, net" and "Long-term debt, net" within total liabilities on the unaudited condensed consolidated balance sheets.

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 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

liabilities that were accounted for at fair value as of June 30, 2019 and December 31, 2018 (in thousands):

	June 30, 2019

	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	15,468	$	—	$	15,468



Liabilities
Liabilities from derivative contracts	$	—	$	16,062	$	—	$	16,062

	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 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 debt instruments as of June 30, 2019 and December 31, 2018 (excluding discounts, premiums and debt issuance costs) (in thousands):

	June 30, 2019				December 31, 2018

Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
6.75% senior notes	$	625,005	$	193,095	$	625,005	$	458,210

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

The fair value of the Company's fixed interest rate debt instruments was calculated using Level 1 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 June 30, 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 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 not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivatives and Hedging (ASC 815) and ASC 820 and included in the unaudited condensed consolidated balance

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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 (in thousands):

		Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	June 30, 2019		December 31, 2018		Balance sheet location	June 30, 2019			December 31, 2018
Commodity contracts	Current assets—receivables from derivative contracts	$	10,648	$	57,280	Current liabilities—liabilities from derivative contracts	$	(11,814	)	$	(3,768	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		4,820		12,437	Other noncurrent liabilities—liabilities from derivative contracts		(4,248	)		(9,139	)

Total derivatives not designated as hedging contracts under ASC 815		$	15,468	$	69,717		$	(16,062	)	$	(12,907	)

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 June 30,					Amount of gain or (loss) recognized in income on derivative contracts for the Six Months Ended June 30,

	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2019		2018			2019			2018
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	10,764	$	(37,874	)	$	(57,405	)	$	(26,761	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		6,246		25,774			9,616			20,564

Total net gain (loss) on derivative contracts		$	17,010	$	(12,100	)	$	(47,789	)	$	(6,197	)

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

At June 30, 2019 and December 31, 2018, the Company had the following open crude oil, natural gas liquids and natural gas derivative contracts:

			June 30, 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
July 2019 - September 2019	Basis Swap	Crude Oil		184,000	$—	$	—	$—	$	—	$(6.20) - $(7.60)	$	(6.90	)
July 2019 - September 2019	Collars	Crude Oil		184,000	55.00		55.00	62.85 - 63.00		62.93
July 2019 - December 2019	Basis Swap	Crude Oil		736,000							(0.98) - (6.50)		(3.95	)
July 2019 - December 2019	Basis Swap	Natural Gas		4,692,000							(1.05) - (1.40)		(1.18	)
July 2019 - December 2019	Collars	Crude Oil		1,472,000	50.00 - 55.85		52.48	55.00 - 61.70		58.61
July 2019 - December 2019	Collars	Natural Gas		4,416,000	2.52 - 2.70		2.60	3.00 - 3.10		3.01
July 2019 - December 2019	Swap	Natural Gas Liquids		644,000	29.08 - 29.50		29.21
July 2019 - December 2019	WTI NYMEX ROLL	Crude Oil		920,000	0.35		0.35
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	Swap	Crude Oil		366,000	60.00		60.00
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

			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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at June 30, 2019 and December 31, 2018 (in thousands):

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	June 30, 2019			December 31, 2018			June 30, 2019			December 31, 2018
Gross Amounts Presented in the Consolidated Balance Sheet	$	15,468		$	69,717		$	(16,062	)	$	(12,907	)
Amounts Not Offset in the Consolidated Balance Sheet		(11,967	)		(10,263	)		11,967			10,263

Net Amount	$	3,501		$	59,454		$	(4,095	)	$	(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.

The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 1, "Financial Statement Presentation," constituted an event of default under the Company's derivatives contracts that gives the counterparties the option to terminate such contracts. Certain parties elected to terminate their contracts in August 2019 and the Company received approximately $0.1 million to settle a portion of the outstanding positions while other positions were novated for fees totaling $0.5 million. The remaining derivative contracts, including the novated positions, are secured on a super-priority parri passu basis with the Company's Senior Credit Agreement during the bankruptcy process. These derivative contracts are expected to stay in place following the Company's chapter 11 proceedings.

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 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. ASSET RETIREMENT OBLIGATIONS (Continued)

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		198
Accretion expense		202

Liability for asset retirement obligations as of June 30, 2019	$	7,085

10. COMMITMENTS AND CONTINGENCIES

Commitments

As of June 30, 2019, the Company has the following rig termination commitment related to a historical rig contract (in thousands):


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

Total	$	3,000

As of June 30, 2019, the Company has the following purchase commitments related to equipment (in thousands):


Remaining period in 2019	$	7,272
2020		—
2021		—
2022		—
2023		—
Thereafter		—

Total	$	7,272

The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of June 30, 2019, the Company had in place three long-term crude oil contracts and eleven long-term natural gas contracts in this area and the sales price 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 these areas for periods ranging from one to twenty years from the date of first production.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS AND CONTINGENCIES (Continued)

Contingencies

On February 26, 2019, a subsidiary of the Company, Halcón Energy Properties, Inc. (HEPI), filed notice of appeal from a judgment entered by The Court of Common Pleas of Mercer County, Pennsylvania in a litigation matter captioned Vodenichar, et al., v. Halcón Energy Properties, Inc. et al., No. 2013-0512, arising from a dispute over whether the subsidiary complied with the terms of a letter of intent related to the leasing of acreage, pursuant to which HEPI was ordered to pay $9,107,053.57 (including interest and costs). Such appeal is currently pending in the Superior Court of Pennsylvania, Western District (Case No. 347 WDA 2019).

On August 7, 2019, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas to pursue a pre-packaged plan of reorganization. The Company expects to continue operations in the normal course during the pendency of the chapter 11 proceedings. Prior to filing the bankruptcy petitions, on August 2, 2019, the Halcón Entities entered into a Restructuring Support Agreement with the Unsecured Senior Noteholders. See Note 14, "Subsequent Events," for more information.

In addition to the above, 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 our 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 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 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 adopted the 2016 Long-Term Incentive Plan (the Incentive Plan). An aggregate of 10.0 million shares of the Company's common stock were available for grant pursuant to awards under the Incentive Plan. On April 6, 2017, Amendment No. 1 to the Incentive 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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

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 June 30, 2019 and December 31, 2018, a maximum of 5.8 million and 4.9 million shares, respectively, of the Company's common stock remained reserved for issuance under the Incentive 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 and six months ended June 30, 2019, the Company recognized an expense of $1.0 million and a credit of $5.8 million, respectively, related to stock-based compensation. For the three and six months ended June 30, 2018, the Company recognized an expense of $4.2 million and $7.8 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 six months ended June 30, 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 six months ended June 30, 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 Incentive 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.

No stock options were granted during the six months ended June 30, 2019. At June 30, 2019, the Company had $0.9 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 0.6 years.

During the six months ended June 30, 2018, the Company granted stock options under the Incentive Plan covering 1.2 million shares of common stock to employees of the Company. These stock options have an exercise price of $5.65. During the six months ended June 30, 2018, the Company received $0.3 million from the exercise of stock options. At June 30, 2018, the Company had $9.9 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.0 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

During the six months ended June 30, 2019, the Company granted 4.2 million shares of restricted stock under the Incentive Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $1.29 to $1.40 with a weighted average price of $1.29 per share. At June 30, 2019, the Company had $6.5 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.6 years.

During the six months ended June 30, 2018, the Company granted 2.2 million shares of restricted stock under the Incentive Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $4.00 to $5.65 with a weighted average price of $5.53. At June 30, 2018, the Company had $11.0 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.5 years.

12. EARNINGS PER COMMON SHARE

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

	Three Months Ended June 30,						Six Months Ended June 30,

	2019			2018			2019			2018
Basic:
Net income (loss)	$	(640,844	)	$	(16,274	)	$	(977,403	)	$	(18,872	)



Weighted average basic number of common shares outstanding		159,050			157,943			158,801			155,925

Basic net income (loss) per share of common stock	$	(4.03	)	$	(0.10	)	$	(6.15	)	$	(0.12	)



Diluted:
Net income (loss)	$	(640,844	)	$	(16,274	)	$	(977,403	)	$	(18,872	)



Weighted average basic number of common shares outstanding		159,050			157,943			158,801			155,925
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of warrants		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			Anti-dilutive			Anti-dilutive

Weighted average diluted number of common shares outstanding		159,050			157,943			158,801			155,925

Diluted net income (loss) per share of common stock	$	(4.03	)	$	(0.10	)	$	(6.15	)	$	(0.12	)

Common stock equivalents, including stock options, restricted shares and warrants totaling 15.7 million and 15.3 million shares for the three and six months ended June 30, 2019, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. EARNINGS PER COMMON SHARE (Continued)

Common stock equivalents, including stock options, restricted shares and warrants totaling 14.9 million and 14.0 million shares for the three and six months ended June 30, 2018, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

13. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

	June 30, 2019		December 31, 2018

Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	25,208	$	26,432
Joint interest accounts		5,512		7,369
Other		3,531		1,917

	$	34,251	$	35,718



Prepaids and other:
Prepaids	$	3,493	$	3,503
Income tax receivable		1,250		1,250
Funds in escrow		6,557		—
Other		775		35

	$	12,075	$	4,788



Funds in escrow and other:
Funds in escrow	$	576	$	570
Other		559		1,611

	$	1,135	$	2,181



Accounts payable and accrued liabilities:
Trade payables	$	50,568	$	68,959
Accrued oil and natural gas capital costs		13,339		41,461
Revenues and royalties payable		17,942		20,526
Accrued interest expense		19,310		16,971
Accrued employee compensation		2,713		3,421
Accrued lease operating expenses		7,859		6,292
Other		178		218

	$	111,909	$	157,848

14. SUBSEQUENT EVENTS

Restructuring Support Agreement

On August 2, 2019, the Halcón Entities entered into a Restructuring Support Agreement with the Unsecured Senior Noteholders. On August 3, 2019, the Halcón Entities commenced a solicitation for acceptance of the Plan. On August 7, 2019, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. SUBSEQUENT EVENTS (Continued)

District of Texas to effect an accelerated pre-packaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement.

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

•: borrowings outstanding under the Senior Credit Agreement, plus unpaid interest and fees, will be repaid in full, in cash, including by a refinancing;
•: the Unsecured Senior Noteholders will receive their pro rata share of 91% of the common stock of reorganized Halcón (New Common Shares) issued pursuant to the Plan and the right to participate in the Senior Noteholder Rights Offerings (defined below);
•: the Company's general unsecured claims are unimpaired; and
•: the existing common stockholders will receive their pro rata share of 9% of the New Common Shares issued pursuant to the Plan, together with Warrants (defined below) to purchase common stock of reorganized Halcón and the right to participate in the Existing Equity Interests Rights Offering (defined below and, collectively, the Existing Equity Total Consideration); provided, however, that registered holders of existing common stock with fewer than or equal to 2,000 shares of common stock will instead receive cash in an amount equal to the inherent value of such holder's pro rata share of the Existing Equity Total Consideration (the Existing Equity Cash Out).

Each of the foregoing percentages of equity in the reorganized company is subject to dilution by New Common Shares issued in connection with (i) a management incentive plan, (ii) the Warrants, (iii) the Equity Rights Offerings (defined below), and (iv) the Backstop Commitment Premium (defined below).

As a component of the Restructuring Support Agreement (i) each Unsecured Senior Noteholder will be offered the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of $150,150,000 (the Senior Noteholder Rights Offering) and (ii) each existing common stockholder will be offered (subject to the Existing Equity Cash Out) the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of up to $14,850,000 (the Existing Equity Interests Rights Offering, and together with the Senior Noteholder Rights Offering, the Equity Rights Offerings), in each case, at a price per share equal to a 26% discount to the value of the New Common Shares based on the lesser of the total enterprise value of the reorganized company as set forth in the Disclosure Statement and an assumed total enterprise value of $425 million. Certain of the Unsecured Senior Noteholders will backstop the Senior Noteholder Rights Offering and will receive as consideration (the Backstop Commitment Premium) either (i) New Common Shares equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering subject to dilution by New Common Shares issued in connection with a management incentive plan and the Warrants or (ii) a cash payment equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering if the backstop agreement is terminated. The proceeds of the Equity Rights Offerings will be used by the Company to (i) provide additional liquidity for working capital and general corporate purposes, (ii) pay all reasonable and documented restructuring expenses, and (iii) fund Plan distributions.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. SUBSEQUENT EVENTS (Continued)

Under the Restructuring Support Agreement, each existing common stockholder (subject to the Existing Equity Cash Out) will be issued a series of warrants exercisable in cash for a three year period subsequent to the effective date of the Plan (Warrants). The Warrants will be issued in three series with three distinct strike prices, which will be based upon stipulated rate-of-return levels achieved by the Unsecured Senior Noteholders. Each series of Warrants represents 10%, and cumulatively representing 30%, of the New Common Shares issued pursuant to the Plan.

Debtor-in-Possession Financing

In connection with the chapter 11 proceedings and pursuant to an order of the Bankruptcy Court dated August 8, 2019 (the Interim Order), the Company anticipates that it will enter into a Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) with the Unsecured Senior Noteholders party thereto from time to time as lenders (the DIP Lenders) and Wilmington Trust, National Association, as administrative agent.

Under the DIP Credit Agreement, the DIP Lenders will make available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility, and the loans thereunder, the DIP Loans), of which $25.0 million will be available as an initial draw and the remainder of which will be available to the Company as a single delayed draw term loan following the entry of the final DIP orders of the Bankruptcy Court. The DIP Loans will, subject to the terms set forth in the DIP Credit Agreement and the Exit Credit Agreement (as defined below), be rolled over or converted into, or otherwise refinanced with a $750.0 million exit senior secured reserve-based revolving credit facility (the Exit Facility), which will be evidenced by a senior secured revolving credit agreement (the Exit Credit Agreement), by and among the Company, as borrower, the lenders party thereto from time to time, and BMO Harris Bank N.A., as administrative agent.

The Company anticipates using the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and the making of certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with the Company's budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

The maturity date of the DIP Facility will be the earlier of (i) six months from the date of execution and (ii) the effective date of a plan of reorganization that is confirmed pursuant to an order entered by the Bankruptcy Court.

The DIP Loans will bear interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 5.50% or (ii) an alternative base rate plus an applicable margin of 4.50%, in each case, as selected by the Company. Any undrawn delayed draw term loans will be subject to an undrawn fee at a rate per annum equal to 1.00%.

The DIP Facility will be secured by (i) a junior secured perfected security interest on all assets that secure the Senior Credit Facility and (ii) a senior secured perfected security interest on all unencumbered assets of the Company and any subsidiary guarantors. The security interests and liens will be further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. SUBSEQUENT EVENTS (Continued)

The DIP Credit Agreement will contain certain customary (i) representations and warranties; (ii) affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments and swap agreements; and (iii) 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; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

A hearing before the Bankruptcy Court to consider approval of the DIP Facility on a final basis will be scheduled for a later date.

Exit Financing

In connection with the Restructuring Support Agreement and the chapter 11 proceedings, the Company has received an underwritten commitment from BMO Harris Bank, N.A. for a $750 million Exit Facility, effective upon the Company's emergence from the chapter 11 proceedings, which will be arranged by BMO Capital Markets Corp. The Exit Facility will have an expected initial borrowing base of $275 million. A portion of the Exit Facility, in the amount of $50 million, will be available for the issuance of letters of credit. The proceeds of the Exit Facility will be used to refinance indebtedness that the Company incurs during the pendency of the chapter 11 proceedings under the DIP Facility, for working capital and other general corporate purposes, to issue letters of credit, for transaction fees and expenses and for fees related to the Company's emergence from the chapter 11 proceedings.

Loans extended under the Exit Credit Agreement will bear interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 2.00% to 3.00% or (ii) an alternative base rate plus an applicable margin of 1.00% to 2.00%, in each case, at the election of the Company and based on the borrowing base utilization percentage under the Exit Facility. Any undrawn amounts under the Exit Facility will be subject to a commitment fee at a rate per annum equal to 0.375% to 0.500%, based on the borrowing base utilization percentage.

The maturity date of the Exit Facility will be five years from the date of execution of the Exit Credit Agreement. The Company will be able, at its option, to prepay any borrowing outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Credit Agreement). The Company may also be required to make mandatory prepayments of the loans under the Exit Facility in connection with certain borrowing base deficiencies.

Amounts outstanding under the Exit Credit Agreement will be guaranteed by the Company's direct and indirect material domestic subsidiaries and secured by a security interest in substantially all of the assets of the Company and such guarantors.

The Exit Credit Agreement will contain certain customary representations and warranties and affirmative and negative covenants.

The Exit Credit Agreement will contain certain financial covenants, including the maintenance of (i) a Total Net Leverage Ratio (to be defined in the Exit Credit Agreement) not to exceed 4.00:1.00 and (ii) a Current Ratio (to be defined in the Exit Credit Agreement) not to be less than 1.00:1.00, in

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. SUBSEQUENT EVENTS (Continued)

each case commencing with the first full fiscal quarter ending after the date of the Exit Credit Agreement.

The Exit Credit Agreement will also contain certain customary 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 Exit Facility is subject to customary closing conditions and approval by the Bankruptcy Court, which has not been obtained at this time.

The terms of the Exit Facility are set forth in a senior secured revolving credit facility commitment letter (the Exit Commitment Letter), and the foregoing description of the Exit Facility is qualified by reference to the full text of the Exit Commitment Letter, a copy of which was filed as Exhibit 10.3 to the Company's Current Report on Form 8-K, filed on August 5, 2019, and is incorporated herein by reference.

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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 and six months ended June 30, 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 (the El Halcón Divestiture). 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 six months of 2019, production averaged 17,575 Boe/d compared to average daily production of 11,873 Boe/d during the first six months of 2018. Our average daily oil and natural gas production increased in the first six 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. For the six months ended June 30, 2019, we drilled 12 gross (11.2 net) wells, completed 9 gross (8.7 net) wells, and put online 11 gross (10.7 net) wells.

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 July 1, 2019 of $59.09 per barrel, 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 test limitation would have generated an additional impairment of $62.3 million ($49.2 million after taxes, before valuation allowance), 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

Restructuring Support Agreement

On August 2, 2019, we entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of our 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). On August 3, 2019, we commenced a solicitation for acceptance of a pre-packaged plan of reorganization (the Plan). On August 7, 2019, we filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to effect an accelerated pre-packaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement.

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

•: borrowings outstanding under the Senior Credit Agreement, plus unpaid interest and fees, will be repaid in full, in cash, including by a refinancing;
•: the Unsecured Senior Noteholders will receive their pro rata share of 91% of the common stock of reorganized Halcón (New Common Shares) issued pursuant to the Plan and the right to participate in the Senior Noteholder Rights Offerings (defined below);
•: our general unsecured claims are unimpaired; and
•: the existing common stockholders will receive their pro rata share of 9% of the New Common Shares issued pursuant to the Plan, together with Warrants (defined below) to purchase common stock of reorganized Halcón and the right to participate in the Existing Equity Interests Rights Offering (defined below and, collectively, the Existing Equity Total Consideration); provided, however, that registered holders of existing common stock with fewer than or equal to 2,000 shares of common stock will instead receive cash in an amount equal to the inherent value of such holder's pro rata share of the Existing Equity Total Consideration (the Existing Equity Cash Out).

As a component of the Restructuring Support Agreement (i) each Unsecured Senior Noteholder will be offered the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of $150,150,000 (the Senior Noteholder Rights Offering) and (ii) each existing common stockholder will be offered (subject to the Existing Equity Cash Out) the right to purchase its pro rata share of New Common Shares for an aggregate purchase price of up to $14,850,000 (the Existing Equity Interests Rights Offering, and together with the Senior Noteholder Rights Offering, the Equity Rights Offerings), in each case, at a price per share equal to a 26% discount to the value of the New Common Shares based on the lesser of the total enterprise value of the reorganized company as set forth in the Disclosure Statement and an assumed total enterprise value of $425 million. Certain of the Unsecured Senior Noteholders will backstop the Senior Noteholder Rights Offering and will receive as consideration (the Backstop Commitment Premium) either (i) New Common Shares equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering subject to dilution by New Common Shares issued in connection with a management incentive plan and the Warrants or (ii) a cash payment equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering if the backstop agreement is terminated. We will use the proceeds of the Equity Rights Offerings to (i) provide

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additional liquidity for working capital and general corporate purposes, (ii) pay all reasonable and documented restructuring expenses, and (iii) fund Plan distributions.

Senior Revolving Credit Facility

On May 9, 2019, we entered into the Eighth Amendment, Consent and Waiver to Amended and Restated Senior Secured Credit Agreement (the Eighth Amendment) which, among other things, (i) temporarily 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, (ii) increased interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) reduced our Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provided for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver would have terminated and an Event of Default (as defined in the Senior Credit Agreement) would have occurred on August 1, 2019. On July 31, 2019, we entered into the Waiver to Amended and Restated Senior Secured Credit Agreement, pursuant to which the termination date for the waiver granted by the Eighth Amendment was extended to August 8, 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, 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 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.

The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described above constituted an event of default under the Senior Credit Agreement that accelerated our obligations and terminated the lenders' commitments under the Senior Credit Agreement. During the chapter 11 proceedings, amounts outstanding under the Senior Credit Agreement will bear interest at a rate per annum equal to 2.0% plus the applicable interest rate in effect.

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Debtor-in-Possession Financing

In connection with the chapter 11 proceedings and pursuant to an order of the Bankruptcy Court dated August 8, 2019 (the Interim Order), we anticipate that we will enter into a Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) with the Unsecured Senior Noteholders party thereto from time to time as lenders (the DIP Lenders) and Wilmington Trust, National Association, as administrative agent.

Under the DIP Credit Agreement, the DIP Lenders will make available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility, and the loans thereunder, the DIP Loans), of which $25.0 million will be available as an initial draw and the remainder of which will be availabe to us as a single delayed draw term loan following the entry of the final DIP orders of the Bankruptcy Court. The DIP Loans will, subject to the terms set forth in the DIP Credit Agreement and the Exit Credit Agreement (as defined below), be rolled over or converted into, or otherwise refinanced with a $750 million exit senior secured reserve-based revolving credit facility (the Exit Facility), which will be evidenced by a senior secured revolving credit agreement (the Exit Credit Agreement), by and among us, as borrower, the lenders party thereto from time to time, and BMO Harris Bank N.A., as administrative agent.

We anticipate using the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and the making of certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with our budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

The DIP Loans will bear interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 5.50% or (ii) an alternative base rate plus an applicable margin of 4.50%, in each case, as selected by us. Any undrawn delayed draw term loans will be subject to an undrawn fee at a rate per annum equal to 1.00%.

The DIP Facility will be secured by (i) a junior secured perfected security interest on all assets that secure the Senior Credit Facility and (ii) a senior secured perfected security interest on all unencumbered assets of us and any subsidiary guarantors. The security interests and liens will be further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

A hearing before the Bankruptcy Court to consider approval of the DIP Facility on a final basis will be scheduled for a later date.

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Exit Financing

In connection with the Restructuring Support Agreement and the chapter 11 proceedings, we have received an underwritten commitment from BMO Harris Bank, N.A. for a $750 million Exit Facility, effective upon our emergence from the chapter 11 proceedings, which will be arranged by BMO Capital Markets Corp. The Exit Facility will have an expected initial borrowing base of $275 million. A portion of the Exit Facility, in the amount of $50 million, will be available for the issuance of letters of credit. The proceeds of the Exit Facility will be used to refinance indebtedness that we incur during the pendency of the chapter 11 proceedings under the DIP Facility, for working capital and other general corporate purposes, to issue letters of credit, for transaction fees and expenses and for fees related to our emergence from the chapter 11 proceedings.

Loans extended under the Exit Credit Agreement will bear interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 2.00% to 3.00% or (ii) an alternative base rate plus an applicable margin of 1.00% to 2.00%, in each case, at the election of us and based on the borrowing base utilization percentage under the Exit Facility. Any undrawn amounts under the Exit Facility will be subject to a commitment fee at a rate per annum equal to 0.375% to 0.500%, based on the borrowing base utilization percentage.

The maturity date of the Exit Facility will be five years from the date of execution of the Exit Credit Agreement. We will be able, at our option, to prepay any borrowing outstanding under the Exit Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Exit Credit Agreement). We may also be required to make mandatory prepayments of the loans under the Exit Facility in connection with certain borrowing base deficiencies.

Amounts outstanding under the Exit Credit Agreement will be guaranteed by our direct and indirect material domestic subsidiaries and secured by a security interest in substantially all of the assets of us and such guarantors.

The Exit Credit Agreement will contain certain customary representations and warranties and affirmative and negative covenants.

Restructuring Activities

In July 2019, we, in an effort to improve efficiencies and go forward costs, made the decision to consolidate into one corporate office to be located in Houston, Texas. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions. The plan includes ultimately closing the office in Denver, Colorado. The timing of the transition is anticipated to happen before the end of the year.

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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 $211.0 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 years from 2019 to 2023 were available subject to our ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. In August 2019, we and the purchaser agreed to terminate the incentive payments.

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 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, borrowings under our Senior Credit Agreement, which has been drawn to approximately $223.2 million as of July 29, 2019, and our DIP and Exit Facilities, subject to their finalization and Bankruptcy Court approval. As noted above, the filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code constituted an event of default under the Senior Credit Agreement that accelerated our obligations and terminated the lenders' commitments under the Senior Credit Agreement.

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. Our strategy makes us more susceptible to fluctuations in performance and compliance with these covenants more challenging. In addition, we have encountered certain operational challenges that have impacted our ability to comply, including recently, elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells and severance payments associated with personnel changes.

We have in the past obtained amendments to the covenants under our Senior Credit Agreement under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. The basis for these amendment and waiver requests is similar to those described above, i.e., the potential for us to fall out of compliance as a result of our strategic decisions. As part of our plan to manage liquidity risks, we have scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties, entered into a Restructuring Support Agreement to restructure our indebtedness and, on August 7, 2019, filed a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas to pursue a pre-packaged plan of reorganization. However, we may not be able to obtain confirmation of the Plan in the Restructuring Support Agreement because there can be no assurance that the Plan (or any other plan of reorganization) will be approved by the Bankruptcy Court. Additionally, although the Plan is designed to minimize the length of our chapter 11 proceedings, it is impossible to predict the amount of time that we may spend in bankruptcy. If

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protracted, the chapter 11 proceedings will involve additional expenses, require significant time and effort of management, and may negatively impact our relationships with vendors, suppliers, employees and customers, all of which may adversely affect our liquidity, financial condition and results of operations.

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 evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes. We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain adequate borrowing capacity, 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 such transactions and maintain or increase our borrowing base 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 six months ended June 30, 2019, cash and cash equivalents on hand supplemented with borrowings under our Senior Credit Agreement were used to fund our drilling and completion program. During the six months ended June 30, 2018, cash generated by financing activities was used to fund the acquisitions of acreage in our Monument Draw and West Quito Draw areas, 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):

	Six Months Ended June 30,

	2019			2018
Cash flows provided by (used in) operating activities	$	(26,898	)	$	43,578
Cash flows provided by (used in) investing activities		(205,303	)		(634,271	)
Cash flows provided by (used in) financing activities		187,573			262,492

Net increase (decrease) in cash and cash equivalents	$	(44,628	)	$	(328,201	)

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Operating Activities. Net cash flows used in operating activities for the six months ended June 30, 2019 were $26.9 million. Net cash flows provided by operating activities were $43.6 million for the six months ended June 30, 2018.

Operating cash flows for the six months ended June 30, 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 slightly offset by increased oil and natural gas revenues due to an increase in our production.

Operating cash flows for the six months ended June 30, 2018 decreased from the comparable prior year period primarily due to our divestitures in 2017, in which we divested non-core producing properties in other areas for primarily undeveloped acreage in the Delaware Basin. This decrease was partially offset by $30.8 million of proceeds related to a monetization of basis swaps that occurred in the six months ended June 30, 2018.

Investing Activities. Net cash flows used in investing activities were approximately $205.3 million and $634.3 million for the six months ended June 30, 2019 and 2018, respectively.

During the six months ended June 30, 2019, we spent $139.2 million on oil and natural gas expenditures, of which $131.7 million related to drilling and completion costs. We also spent approximately $64.6 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 six months of 2018, we incurred cash expenditures of $332.9 million on acquisition activities, the majority of which related to the acquisition of the West Quito Draw Properties and the purchase of the Northern Tract of the Ward County Assets. Additionally, we spent $252.0 million on oil and natural gas capital expenditures, of which $234.4 million related to drilling and completion costs. We also spent approximately $53.2 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 $187.6 million and $262.5 million for the six months ended June 30, 2019 and 2018, respectively.

During the six months ended June 30, 2019, net borrowings of $188.0 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 six 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 $202.4 million after deducting initial purchasers' premiums, commissions and 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 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

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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, except as described below.

Income Taxes

We utilized the discrete effective tax rate method as allowed by ASC 740, Income Taxes, to calculate our interim income tax provision for the three and six months ended June 30, 2019. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, "Financial Statement Presentation," for details.

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Results of Operations

Three Months Ended June 30, 2019 and 2018

We reported a net loss of $640.8 million $16.3 million for the three months ended June 30, 2019 and 2018, respectively. The table included below sets forth financial information for the periods presented.

	Three Months Ended June 30,

In thousands (except per unit and per Boe amounts)	2019			2018			Change
Net income (loss)	$	(640,844	)	$	(16,274	)	$	(624,570	)
Operating revenues:
Oil		53,232			48,756			4,476
Natural gas		(1,655	)		1,560			(3,215	)
Natural gas liquids		4,297			4,991			(694	)
Other		504			108			396
Operating expenses:
Production:
Lease operating		13,473			5,314			8,159
Workover and other		1,368			1,956			(588	)
Taxes other than income		3,308			3,226			82
Gathering and other		11,041			5,956			5,085
Restructuring		654			27			627
General and administrative:
General and administrative		11,494			10,018			1,476
Stock-based compensation		1,025			4,237			(3,212	)
Depletion, depreciation and accretion:
Depletion—Full cost		38,221			14,288			23,933
Depreciation—Other		2,102			1,740			362
Accretion expense		102			68			34
Full cost ceiling impairment		664,383			—			664,383
(Gain) loss on sale of oil and natural gas properties		—			2,225			(2,225	)
(Gain) loss on sale of Water Assets		2,897			—			2,897
Other income (expenses):
Net gain (loss) on derivative contracts		17,010			(12,100	)		29,110
Interest expense and other		(14,470	)		(10,534	)		(3,936	)
Income tax benefit (provision)		(50,306	)		—			(50,306	)
Production:
Oil—MBbls		939			795			144
Natural Gas—Mmcf		2,516			1,083			1,433
Natural gas liquids—MBbls		285			187			98
Total MBoe(1)		1,643			1,162			481
Average daily production—Boe/d(1)		18,055			12,769			5,286
*Average price per unit(2)***:
Oil price—Bbl	$	56.69		$	61.33		$	(4.64	)
Natural gas price—Mcf		(0.66	)		1.44			(2.10	)
Natural gas liquids price—Bbl		15.08			26.69			(11.61	)
Total per Boe(1)		34.01			47.60			(13.59	)
Average cost per Boe:
Production:
Lease operating	$	8.20		$	4.57		$	3.63
Workover and other		0.83			1.68			(0.85	)
Taxes other than income		2.01			2.78			(0.77	)
Gathering and other		6.72			5.13			1.59
Restructuring		0.40			0.02			0.38
General and administrative:
General and administrative		7.00			8.62			(1.62	)
Stock-based compensation		0.62			3.65			(3.03	)
Depletion		23.26			12.30			10.96

(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 $55.9 million and $55.3 million for the three months ended June 30, 2019 and 2018, respectively. For the three months ended June 30, 2019 and 2018, production averaged 18,055 Boe/d and 12,769 Boe/d, respectively. Our average daily oil and natural gas production increased in the three months ended June 30, 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 $34.01 per Boe and $47.60 per Boe for the three months ended June 30, 2019 and 2018, respectively. The amount we realized 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, quality of production, basis differentials and other factors.

Lease operating expenses were $13.5 million and $5.3 million for the three months ended June 30, 2019 and 2018, respectively. On a per unit basis, lease operating expenses were $8.20 per Boe and $4.57 per Boe for the three months ended June 30, 2019 and 2018, respectively. The increase in lease operating expenses from 2018 levels results from higher third party water hauling and disposal costs resulting from our Water Infrastructure Divestiture and an increase in our inventory of wells due to our drilling and acquisition activities.

Workover and other expenses were $1.4 million and $2.0 million for the three months ended June 30, 2019 and 2018, respectively. On a per unit basis, workover and other expenses were $0.83 per Boe and $1.68 per Boe for the three months ended June 30, 2019 and 2018, respectively. The decrease in workover expenses in 2019 as compared to the prior period relate to recent strides in improving well and completion designs and a decrease in the number of workovers performed.

Taxes other than income were $3.3 million and $3.2 million for the three months ended June 30, 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 $2.01 per Boe and $2.78 per Boe for the three months ended June 30, 2019 and 2018, respectively.

Gathering and other expenses were $11.0 million and $6.0 million for the three months ended June 30, 2019 and 2018, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our Company owned oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $3.3 million and $1.4 million of expenses incurred for the three months ended June 30, 2019 and 2018, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Approximately $7.6 million and $4.4 million of expenses for the three months ended June 30, 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. Included in the three months ended June 30, 2019 and 2018 are $1.9 million and $0.3 million, respectively, of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties. In April 2019, we installed an H2S treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating. Also included are $0.1 million of rig stacking charges for the three months ended June 30, 2018.

Restructuring expense was approximately $0.7 million and $27,000 during the three months ended June 30, 2019 and 2018, respectively. During 2019, we incurred costs to fill executive positions as a result of resignations earlier in the year and we had a reduction in our workforce due to a decrease in drilling and developmental activities planned for the year. Costs in 2018 represent severance costs and accelerated stock-based compensation expense related to the termination of certain employees in conjunction with our divestitures.

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General and administrative expense was approximately $11.5 million and $10.0 million for the three months ended June 30, 2019 and 2018, respectively. The increase in general and administrative expenses results from increases in professional fees associated with the efforts to restructure our indebtedness totaling $2.5 million, offset by a reduction in our payroll and employee related benefits costs of $0.7 million due to a reduction in our workforce. On a per unit basis, general and administrative expenses were $7.00 per Boe and $8.62 per Boe for the three months ended June 30, 2019 and 2018, respectively.

Stock-based compensation expense was $1.0 million and $4.2 million for the three months ended June 30, 2019 and 2018, respectively. Stock-based compensation expense decreased in the current period due to a reduction in our workforce.

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 $38.2 million and $14.3 million for the three months ended June 30, 2019 and 2018, respectively. On a per unit basis, depletion expense was $23.26 per Boe and $12.30 per Boe for the three months ended June 30, 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 transfers of unevaluated property to the full cost pool.

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 $2.2 million during the three months ended June 30, 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 $211.0 million. During the year ended December 31, 2018, we recognized an initial $119.0 million gain on the sale. This gain on the sale was reduced during the three months ended June 30, 2019 and March 31, 2019 by approximately $2.9 million and $0.9 million, respectively, as a result of customary post-closing adjustments.

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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 June 30, 2019, we had a $15.5 million derivative asset, $10.6 million of which was classified as current and we had a $16.1 million derivative liability, $11.8 million of which was classified as current associated with these contracts. We recorded a net derivative gain of $17.0 million ($10.8 million net unrealized gain and $6.2 million net realized gain on settled and early terminated contracts) for the three months ended June 30, 2019 compared to a net derivative loss of $12.1 million ($37.9 million net unrealized loss and $25.8 million net realized gain on settled and early terminated contracts), in the same period in 2018.

Interest expense and other was $14.5 million and $10.5 million for the three months ended June 30, 2019 and 2018, respectively. Interest expense increased during the three months ended June 30, 2019 as compared to the prior year period due to higher outstanding borrowings under our Senior Credit Agreement, as well as fees paid in 2019 associated with consents and amendments to our Senior Credit Agreement.

We recorded an income tax benefit of $50.3 million using the discrete effective rate method for the three months ended June 30, 2019, resulting from the reduction to the deferred tax liability generated by the impact of the ceiling test impairment on oil and natural gas properties and the deferred tax asset created by the tax loss from operations. The 7.3% effective tax rate for the three months ended June 30, 2019 differs from the 21% statutory rate because of non-deductible executive compensation, non-deductible realized built in losses, and valuation allowances on deferred tax assets.

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Six Months Ended June 30, 2019 and 2018

We reported a net loss of $977.4 million and $18.9 million for the six months ended June 30, 2019 and 2018, respectively. The table included below sets forth financial information for the periods presented.

	Six Months Ended June 30,

In thousands (except per unit and per Boe amounts)	2019			2018			Change
Net income (loss)	$	(977,403	)	$	(18,872	)	$	(958,531	)
Operating revenues:
Oil		98,749			91,825			6,924
Natural gas		(194	)		3,879			(4,073	)
Natural gas liquids		9,242			8,703			539
Other		497			263			234
Operating expenses:
Production:
Lease operating		27,659			10,229			17,430
Workover and other		4,014			3,317			697
Taxes other than income		6,201			6,255			(54	)
Gathering and other		25,910			12,378			13,532
Restructuring		11,925			128			11,797
General and administrative:
General and administrative		22,884			21,647			1,237
Stock-based compensation		(5,757	)		7,818			(13,575	)
Depletion, depreciation and accretion:
Depletion—Full cost		66,543			28,750			37,793
Depreciation—Other		3,655			3,206			449
Accretion expense		202			131			71
Full cost ceiling impairment		939,622			—			939,622
(Gain) loss on sale of oil and natural gas properties		—			5,904			(5,904	)
(Gain) loss on sale of Water Assets		3,782			—			3,782
Other income (expenses):
Net gain (loss) on derivative contracts		(47,789	)		(6,197	)		(41,592	)
Interest expense and other		(27,059	)		(17,582	)		(9,477	)
Income tax benefit (provision)		95,791			—			95,791
Production:
Oil—MBbls		1,860			1,488			372
Natural Gas—Mmcf		4,457			1,969			2,488
Natural gas liquids—MBbls		578			333			245
Total MBoe(1)		3,181			2,149			1,032
Average daily production—Boe(1)		17,575			11,873			5,702
*Average price per unit(2)***:
Oil price—Bbl	$	53.09		$	61.71		$	(8.62	)
Natural gas price—Mcf		(0.04	)		1.97			(2.01	)
Natural gas liquids price—Bbl		15.99			26.14			(10.15	)
Total per Boe(1)		33.89			48.58			(14.69	)
Average cost per Boe:
Production:
Lease operating	$	8.70		$	4.76		$	3.94
Workover and other		1.26			1.54			(0.28	)
Taxes other than income		1.95			2.91			(0.96	)
Gathering and other		8.15			5.76			2.39
Restructuring		3.75			0.06			3.69
General and administrative:
General and administrative		7.19			10.07			(2.88	)
Stock-based compensation		(1.81	)		3.64			(5.45	)
Depletion		20.92			13.38			7.54

(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 $107.8 million and $104.4 million for the six months ended June 30, 2019 and 2018, respectively. For the six months ended June 30, 2019 and 2018, production averaged 17,575 Boe/d and 11,873 Boe/d, respectively. Our average daily oil and natural gas production increased in the first six 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 $33.89 per Boe and $48.58 per Boe for the six months ended June 30, 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, quality of production, basis differentials and other factors.

Lease operating expenses were $27.7 million and $10.2 million for the six months ended June 30, 2019 and 2018, respectively. On a per unit basis, lease operating expenses were $8.70 per Boe and $4.76 per Boe for the six months ended June 30, 2019 and 2018, respectively. The increase in lease operating expenses from 2018 levels results from higher third party water hauling and disposal costs resulting from our Water Infrastructure Divestiture and an increase in our inventory of wells due to our drilling and acquisition activities.

Workover and other expenses were $4.0 million and $3.3 million for the six months ended June 30, 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. On a per unit basis, workover and other expenses were $1.26 per Boe and $1.54 per Boe for the six months ended June 30, 2019 and 2018, respectively.

Taxes other than income were $6.2 million and $6.3 million for the six months ended June 30, 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 $1.95 per Boe and $2.91 per Boe for the three months ended June 30, 2019 and 2018, respectively.

Gathering and other expenses were $25.9 million and $12.4 million for the six months ended June 30, 2019 and 2018, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our Company owned oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $7.0 million and $2.4 million for the six months ended June 30, 2019 and 2018, respectively, relate to gathering and market fees paid to third parties on our oil and natural gas production. Approximately $17.5 million and $8.9 million of expenses for the six months ended June 30, 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. Included in the six months ended June 30, 2019 and 2018 are $11.1 million and $0.3 million, respectively, of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties. In April 2019, we installed an H2S treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating. Also included are $0.8 million and $1.1 million of rig stacking charges for the six months ended June 30, 2019 and 2018, respectively.

Restructuring expense was approximately $11.9 million and $0.1 million during the six months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 2019, 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 incurred costs to fill executive positions created by these resignations and we had reductions in our workforce due to a decrease in drilling and developmental activities planned for 2019. During the six months ended June 30, 2018, we terminated certain employees in conjunction with our divestitures.

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General and administrative expense was $22.9 million and $21.6 million for the six months ended June 30, 2019 and 2018, respectively. The increase in general and administrative expenses results from increases in professional fees associated with the efforts to restructure our indebtedness totaling $2.9 million, offset by a reduction in our payroll and employee related benefits costs of $1.5 million due to a reduction in our workforce. On a per unit basis, general and administrative expenses were $7.19 per Boe and $10.07 per Boe for the six months ended June 30, 2019 and 2018, respectively.

Stock-based compensation expense was a credit of $5.8 million and expense of $7.8 million for the six months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 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 six months ended June 30, 2019, we recognized an incremental reduction to stock-based compensation expense of $8.4 million associated with these modifications. Stock-based compensation expense also decreased in the current period due to a reduction in our workforce.

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 $66.5 million and $28.8 million for the six months ended June 30, 2019 and 2018, respectively. On a per unit basis, depletion expense was $20.92 per Boe and $13.38 per Boe for the six months ended June 30, 2019 and 2018, respectively. The increase in the depletion rate per Boe from 2018 levels is primarily attributable to increases in our depletable base as a result of our transfers of unevaluated property to the full cost pool.

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 $939.6 million for the six months ended June 30, 2019. The ceiling test impairment at June 30, 2019 was primarily driven by our continued focus on our most economic area, Monument Draw. Accordingly, we transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019, the majority of which is associated with our Hackberry Draw area. At March 31, 2019, we recorded a full cost ceiling impairment of $275.2 million. The ceiling test impairment at March 31, 2019 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 Willison Divestiture was accounted for 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 $5.9 million during the six months ended June 30, 2018, as a result of customary post-closing adjustments. The carrying value of the properties sold was

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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 $211.0 million. During the year ended December 31, 2018, we recognized an initial $119.0 million gain on the sale. This gain on the sale was reduced during the six months ended June 30, 2019 by approximately $3.8 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 June 30, 2019, we had a $15.5 million derivative asset, $10.6 million of which was classified as current and we had a $16.1 million derivative liability, $11.8 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $47.8 million ($57.4 million net unrealized loss and $9.6 million net realized gain on settled and early terminated contracts) for the six months ended June 30, 2019 compared to a net derivative loss of $6.2 million ($26.8 million net unrealized gain and $20.6 million net realized gain on settled and early terminated contracts), in the same period in 2018.

Interest expense and other was $27.1 million and $17.6 million for the six months ended June 30, 2019 and 2018, respectively. Interest expense increased during the six months ended June 30, 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 $95.8 million using the discrete effective rate method for the six months ended June 30, 2019, resulting from the reduction to the deferred tax liability generated by the impact of the ceiling test impairment on oil and natural gas properties and the deferred tax asset created by the tax loss from operations. The 8.9% effective tax rate for the six months ended June 30, 2019 differs from the 21% statutory rate because of non-deductible executive compensation, non-deductible realized built in losses, and valuation allowances on deferred tax assets.

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, natural gas and natural gas liquids 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 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

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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 counterparties that are creditworthy institutions deemed by management as competitive market makers. As of June 30, 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 June 30, 2019, the principal amount of our debt was $813.0 million, of which approximately 77% bears interest at a weighted average fixed interest rate of 6.75% per year. The remaining 23% of our total debt at June 30, 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 June 30, 2019, the weighted average interest rate on our variable rate debt was 8.0% per year. If the balance of our variable interest rate at June 30, 2019 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $1.5 million per year.

Item 4. Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of June 30, 2019. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.

We did not have any change in our internal controls over financial reporting during the three months ended June 30, 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

Information regarding legal proceedings to which we are a party is set forth in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 10, "Commitments and Contingencies," which is incorporated herein by reference.

Item 1A. Risk Factors

There have been no changes to the risk factors described in our 2018 Annual Report on Form 10-K, for the fiscal year ended December 31, 2018, except as described below.

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

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

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

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

•: our ability to prosecute, confirm and consummate the Plan or another plan of reorganization with respect to the chapter 11 proceedings;
•: the high costs of bankruptcy proceedings and related fees;
•: our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
•: our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;
•: our ability to maintain contracts that are critical to our operations;
•: our ability to execute our business plan in the current depressed commodity price environment;
•: the ability to attract, motivate and retain key employees;
•: the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

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•: the ability of third parties to seek and obtain court approval to convert the chapter 11 proceedings to chapter 7 proceedings; and
•: the actions and decisions of our creditors and other third parties who have interests in our chapter 11 proceedings that may be inconsistent with our plans.

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

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

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

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

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

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

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

Our capital structure will be significantly altered under the Plan. Under fresh-start reporting rules that may apply to us upon the effective date of the Plan (or any alternative plan of reorganization), our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from chapter 11 would not be comparable to the financial condition and

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results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

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

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

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

We depend on the continued presence of key personnel for critical management decisions.

Retaining and understanding historical knowledge from our key personnel is critical to allowing the new management team to more effectively progress our business plan. As part of the restructuring, there were a number of positions that were consolidated and/or replaced. While it is important to have the new team focused on the future, retaining and understanding the decisions that were made in the past allows for a more seamless transition into the future. Anytime personnel are replaced, there is a risk that there may be a loss of service, albeit temporary, that could result in an adverse effect on the business.

Our oil and natural gas activities are subject to various risks which are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in, the prospects in which we have or will acquire an interest. Such risks and hazards include:

•: human error, accidents and other events beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;
•: blowouts, fires, adverse weather events, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;
•: accidental leaks of natural gas, including gas with high levels of hydrogen sulfide (H2S), and other hydrocarbons or toxic or hazardous materials in the environment as a result of human

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error or the malfunction of equipment or facilities, which can result in personal injury and loss of life, pollution, damage to equipment and suspension of operations;

•: well-on-well interference that may reduce recoveries;
•: unavailability of materials and equipment;
•: engineering and construction delays;
•: unanticipated transportation costs and delays;
•: unfavorable weather conditions;
•: hazards resulting from unusual or unexpected geological or environmental conditions;
•: changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;
•: fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and
•: the availability of alternative fuels and the price at which they become available.

Some of these risks may be exacerbated by other risks that we face. For instance, certain of our wells produce high levels of H2S, a highly toxic, naturally-occurring gas frequently associated with oil and natural gas production. Safely handling H2S gas requires highly skilled operations and field personnel as well as specialized infrastructure, treating facilities, disposal facilities, and/or third party sour gas takeaway. If we are unable to attract and retain qualified and highly skilled personnel, whether as a result of uncertainty associated with our restructuring in bankruptcy or otherwise, our ability to effectively manage this and other risks may be adversely impacted. Additionally, if we are unable to obtain specialized infrastructure and/or successfully operate treating facilities or obtain regulatory approvals for new disposal facilities or secure adequate sour gas takeaway capacity from third parties, our ability to effectively manage the H2S levels we see in our gas production may be adversely impacted. As a result, our production, revenues, operating costs and liabilities and expenses may be materially and adversely affected and may differ materially from those anticipated by us.

Trading in our securities is highly speculative and poses substantial risks. Under the Plan, the holders of our existing common stock will receive their pro rata share of 9% of our common stock following effectiveness of the Plan, subject to certain exceptions, which interest would be further diluted by the Warrants, management incentive plan and equity offerings contemplated in the Plan.

The Plan, as contemplated in the Restructuring Support Agreement, provides that our outstanding unsecured notes will be converted into common stock of the reorganized Company and that the holders of our existing common stock will receive their pro rata share of 9% of the common stock of the reorganized Company upon the our emergence from chapter 11 subject to the Existing Equity Cash Out. If the Plan as contemplated in the Restructuring Support Agreement is confirmed, another 7.5% - 10% of the common stock in the reorganized Company will be reserved for issuance as awards under a post-restructuring management incentive plan, another 10% per series of Warrants, cumulateively representing 30%, of the common stock in the reorganized Company will be reserved for the issuance of Warrants and for the Backstop Commitment Premium. Issuances of common stock (or securities convertible into or exercisable for common stock) in connection with the foregoing will dilute the voting power of the outstanding common stock and may adversely affect the trading price of such common stock.

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

Under the Plan, the composition of our Board of Directors may change significantly. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine our future. As a result, our future strategy and plans may differ materially from those of the past.

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

The holders of Senior Note Claims are expected to acquire a significant ownership interest in the New Common Shares pursuant to the Prepackaged Plan, the Rights Offerings and the Backstop Commitment Agreement. If such holders were to act as a group, such holders would be in a position to control the outcome of all actions requiring stockholder approval, including the election of directors, without the approval of other stockholders. This concentration of ownership could also facilitate or hinder a negotiated change of control of the Reorganized Debtors and, consequently, have an impact upon the value of the New Common Shares and the Warrants.

Notice of NYSE delisting our common stock, which could materially impair the liquidity and value of our common stock.

On July 22, 2019, we were notified by the New York Stock Exchange (NYSE) that due to "abnormally low" trading price levels, pursuant to Section 802.01D of the NYSE Listed Company Manual, the NYSE has determined to commence delisting proceedings to delist our common stock and warrants exercisable for common stock. Trading in our securities was suspended on July 22, 2019. The NYSE will apply to the Securities and Exchange Commission to delist the common stock upon completion of all applicable procedures.

As of July 23, 2019, our common stock and warrants commenced trading on the OTC Pink marketplace under the symbols "HKRS" and "HKRSW", respectively. The OTC Pink is a significantly more limited market than the NYSE, and quotation on the OTC Pink may result in a less liquid market available for existing and potential stockholders to trade the common stock and warrants and could further depress the trading price of the common stock. We can provide no assurance that our common stock or warrants will continue to trade on this market, whether broker-dealers will continue to provide public quotes of our common stock and warrants on this market, whether the trading volume of our common stock and warrants will be sufficient to provide for an efficient trading market or whether quotes for our common stock and warrants may be blocked by OTC Markets Group in the future.

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

Under federal income tax law, a corporation is generally permitted to offset net taxable income in a given year with net operating losses carried forward from prior years. We had net operating loss carryforwards (NOLs) of approximately $2.6 billion as of December 31, 2018; as previously reported, and subject to the following, we believe that only $975 million of the net operating loss carryforwards may be available for use, considering section 382 limitations currently asserted to be in effect, subject to our continued analysis.

Our ability to utilize our net operating loss carryforwards and other tax attributes to offset future taxable income and to reduce our federal income tax liability is subject to certain requirements and restrictions. If we experienced an "ownership change" or if we do experience an "ownership change"

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during or in connection with the restructuring process, as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards and other tax attributes may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an "ownership change" if one or more stockholders owning 5% or more of a corporation's common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over a prescribed testing period. Under section 382 and section 383 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an "ownership change", the amount of its net operating losses and other tax attributes that may be utilized to offset future taxable income generally is subject to an annual limitation. Based on information collected to date, we believe we may have experienced an "ownership change" as of December 31, 2018, which would result in significant impairment in our ability to utilize our NOLs and tax attributes. We are, however, continuing to assess relevant information to determine whether we did, in fact, experience such an ownership change.

Whether or not the net operating loss carryforwards and other tax attributes are subject to limitation under section 382, our net operating losses and other tax attributes are expected to be further reduced by the amount of discharge of indebtedness arising in our chapter 11 case under section 108 of the Internal Revenue Code.

We have requested the Bankruptcy Court approve potential restrictions on certain transfers of our stock to limit the risk of an "ownership change" prior to our emergence from restructuring in our chapter 11 proceedings. We anticipate that the implementation of our plan of reorganization will result in an "ownership change." If so, our NOLs and other tax attributes may become further impaired, depending on our determination as to whether an ownership change has already occurred and depending on the impact of special tax law rules under section 382(l)(5) and section 382(l)(6), applicable to an "ownership change" that occurs as part of a chapter 11 plan. Given those special rules, in connection with our chapter 11 filing, we put holders of claims against us on notice that we plan to analyze whether we can qualify for the special rule of section 382(l)(5) and whether qualification under that rule would yield significant additional value, and if so that we would request the bankruptcy court to order, if and to the extent necessary, the divestiture of claims acquired after the chapter 11 petition was filed.

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

April 2019	7,479	$	1.41	—	—
May 2019	34,569		0.29	—	—
June 2019	148		0.21	—	—

(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.

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Item 3. Defaults Upon Senior Securities

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

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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


2.1		Joint Prepackaged Chapter 11 Plan (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed August 7, 2019).

2.2		Disclosure Statement for Joint Prepackaged Chapter 11 Plan (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K filed August 7, 2019).

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		Eighth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 9, 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 10.1.7 of our Quarterly Report on Form 10-Q filed May 9, 2019).

10.2	*	Offer letter with Richard H. Little dated June 10, 2019.

10.3		Restructuring Support Agreement with certain noteholders dated August 2, 2019 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed August 5, 2019).

10.4		Backstop Commitment Agreement with certain noteholders dated August 2, 2019 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed August 5, 2019).

10.5		Exit Commitment Letter with BMO Harris Bank, N.A., and BMO Capital Markets Corp. dated August 2, 2019 (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed August 5, 2019).

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10.6		Waiver to Amended and Restated Senior Secured Credit Agreement dated as of July 31, 2019 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed August 1, 2019).

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
August 8, 2019	By:	/s/ RICHARD H. LITTLE
		Name:	Richard H. Little
		Title:	Chief Executive Officer
August 8, 2019	By:	/s/ QUENTIN R. HICKS
		Name:	Quentin R. Hicks
		Title:	Executive Vice President, Chief Financial Officer and Treasurer