BATTALION OIL CORP - Quarter Report: 2018 September (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 September 30, 2018
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number: 001-35467

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


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

1000 Louisiana Street, Suite 1500, Houston, TX 77002
(Address of principal executive offices)

(832) 538-0300
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.


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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

At November 2, 2018, 160,669,329 shares of the Registrant's Common Stock were outstanding.

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		Page

PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements (Unaudited)	5
	Condensed Consolidated Statements of Operations (Unaudited) for the Three Months and Nine Months Ended September 30, 2018 and 2017	5
	Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2018 and December 31, 2017	6
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Nine Months Ended September 30, 2018 and the Year Ended December 31, 2017	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2018 and 2017	9
	Notes to Unaudited Condensed Consolidated Financial Statements	10
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	40
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	56
ITEM 4.	Controls and Procedures	57
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	58
ITEM 1A.	Risk Factors	58
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
ITEM 3.	Defaults Upon Senior Securities	59
ITEM 4.	Mine Safety Disclosures	59
ITEM 5.	Other Information	59
ITEM 6.	Exhibits	59
Signatures		61

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Special note regarding forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, potential costs to be incurred, future cash flows and borrowings, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2017, 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:

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

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•: the potential for production decline rates for our wells to be greater than we expect;
•: 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;
•: title to the properties in which we have an interest may be impaired by title defects; and
•: senior management's ability to execute our plans to meet our goals.

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 September 30,						Nine Months Ended September 30,

	2018			2017			2018			2017
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	53,918		$	88,256		$	145,743		$	319,472
Natural gas		1,407			2,886			5,286			15,051
Natural gas liquids		5,920			5,448			14,623			16,779

Total oil, natural gas and natural gas liquids sales		61,245			96,590			165,652			351,302
Other		350			363			613			1,386

Total operating revenues		61,595			96,953			166,265			352,688

Operating expenses:
Production:
Lease operating		5,275			17,798			15,504			58,822
Workover and other		1,478			3,644			4,795			22,213
Taxes other than income		3,557			6,846			9,812			29,149
Gathering and other		18,404			10,886			30,782			34,640
Restructuring		—			1,275			128			2,080
General and administrative		19,731			39,195			49,196			86,966
Depletion, depreciation and accretion		20,310			35,940			52,397			100,788
(Gain) loss on sale of oil and natural gas properties		1,331			(491,830	)		7,235			(727,520	)

Total operating expenses		70,086			(376,246	)		169,849			(392,862	)

Income (loss) from operations		(8,491	)		473,199			(3,584	)		745,550
Other income (expenses):
Net gain (loss) on derivative contracts		(60,406	)		(22,415	)		(66,603	)		28,139
Interest expense and other		(12,940	)		(19,330	)		(30,522	)		(63,808	)
Gain (loss) on extinguishment of debt		—			(29,167	)		—			(86,065	)

Total other income (expenses)		(73,346	)		(70,912	)		(97,125	)		(121,734	)

Income (loss) before income taxes		(81,837	)		402,287			(100,709	)		623,816
Income tax benefit (provision)		—			17,000			—			5,000

Net income (loss)		(81,837	)		419,287			(100,709	)		628,816
Non-cash preferred dividend		—			—			—			(48,007	)

Net income (loss) available to common stockholders	$	(81,837	)	$	419,287		$	(100,709	)	$	580,809



Net income (loss) per share of common stock:
Basic	$	(0.52	)	$	2.85		$	(0.64	)	$	4.56



Diluted	$	(0.52	)	$	2.82		$	(0.64	)	$	4.52



Weighted average common shares outstanding:
Basic		158,011			146,944			156,628			127,458



Diluted		158,011			148,490			156,628			128,410

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)

	September 30, 2018			December 31, 2017

Current assets:
Cash and cash equivalents	$	137		$	424,071
Accounts receivable		46,764			36,416
Receivables from derivative contracts		16,553			677
Prepaids and other		10,969			10,628

Total current assets		74,423			471,792

Oil and natural gas properties (full cost method):
Evaluated		1,362,136			877,316
Unevaluated		982,922			765,786

Gross oil and natural gas properties		2,345,058			1,643,102
Less—accumulated depletion		(617,075	)		(570,155	)

Net oil and natural gas properties		1,727,983			1,072,947

Other operating property and equipment:
Other operating property and equipment		188,321			101,282
Less—accumulated depreciation		(9,136	)		(4,092	)

Net other operating property and equipment		179,185			97,190

Other noncurrent assets:
Receivables from derivative contracts		2,794			—
Funds in escrow and other		1,915			1,691

Total assets	$	1,986,300		$	1,643,620



Current liabilities:
Accounts payable and accrued liabilities	$	141,377		$	131,087
Liabilities from derivative contracts		86,176			19,248
Current portion of asset retirement obligation		149			—

Total current liabilities		227,702			150,335

Long-term debt, net		667,726			409,168
Other noncurrent liabilities:
Liabilities from derivative contracts		37,459			7,751
Asset retirement obligations		6,963			4,368
Commitments and contingencies (Note 9)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 160,676,356 and 149,379,491 shares issued and outstanding as of September 30, 2018 and December 31, 2017, respectively		16			15
Additional paid-in capital		1,091,441			1,016,281
Retained earnings (accumulated deficit)		(45,007	)		55,702

Total stockholders' equity		1,046,450			1,071,998

Total liabilities and stockholders' equity	$	1,986,300		$	1,643,620

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, 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

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)

	Preferred Stock					Common Stock								Retained Earnings (Accumulated Deficit)

	Preferred Stock					Common Stock					Additional Paid-In Capital						Stockholders' Equity
	Shares			Amount		Shares			Amount		Additional Paid-In Capital						Stockholders' Equity
Balances at December 31, 2016		—		$	—		92,991		$	9	$	592,663		$	(479,984	)	$	112,688
Net income (loss)		—			—		—			—		—			189,352			189,352
Sale of preferred stock		6			—		—			—		352,048			—			352,048
Preferred beneficial conversion feature		—			—		—			—		48,007			—			48,007
Offering costs		—			—		—			—		(11,829	)		—			(11,829	)
Long-term incentive plan forfeitures		—			—		(41	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(2	)		—		(17	)		—			(17	)
Stock-based compensation		—			—		—			—		8,539			—			8,539

Balances at March 31, 2017		6			—		92,948			9		989,411			(290,632	)		698,788
Net income (loss)		—			—		—			—		—			20,177			20,177
Conversion of preferred stock		(6	)		—		55,180			6		(6	)		—			—
Offering costs		—			—		—			—		(90	)		—			(90	)
Long-term incentive plan grants		—			—		2,022			—		—			—			—
Long-term incentive plan forfeitures		—			—		(48	)		—		—			—			—
Stock-based compensation		—			—		—			—		13,154			—			13,154

Balances at June 30, 2017		—			—		150,102			15		1,002,469			(270,455	)		732,029
Net income (loss)		—			—		—			—		—			419,287			419,287
Long-term incentive plan forfeitures		—			—		(143	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(293	)		—		(1,828	)		—			(1,828	)
Stock-based compensation		—			—		—			—		12,500			—			12,500

Balances at September 30, 2017		—			—		149,666			15		1,013,141			148,832			1,161,988
Net income (loss)		—			—		—			—		—			(93,130	)		(93,130	)
Long-term incentive plan forfeitures		—			—		(266	)		—		—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(21	)		—		(150	)		—			(150	)
Stock-based compensation		—			—		—			—		3,290			—			3,290

Balances at December 31, 2017		—		$	—		149,379		$	15	$	1,016,281		$	55,702		$	1,071,998

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)

	Nine Months Ended September 30,

	2018			2017
Cash flows from operating activities:
Net income (loss)	$	(100,709	)	$	628,816
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		52,397			100,788
(Gain) loss on sale of oil and natural gas properties		7,235			(727,520	)
Stock-based compensation, net		12,241			33,548
Unrealized loss (gain) on derivative contracts		77,524			(11,010	)
Amortization of deferred loan costs		1,022			1,306
Amortization of discount and premium		235			2,358
Loss (gain) on extinguishment of debt		—			86,065
Accrued settlements on derivative contracts		3,292			(673	)
Other income (expense)		(1,978	)		(4,132	)
Change in assets and liabilities:
Accounts receivable		(7,498	)		37,950
Prepaids and other		(341	)		(5,231	)
Accounts payable and accrued liabilities		(6,711	)		(40,043	)

Net cash provided by (used in) operating activities		36,709			102,222

Cash flows from investing activities:
Oil and natural gas capital expenditures		(369,304	)		(218,880	)
Proceeds received from sale of oil and natural gas properties		1,647			1,901,578
Acquisition of oil and natural gas properties		(333,470	)		(916,676	)
Acquisition of other operating property and equipment		—			(25,538	)
Other operating property and equipment capital expenditures		(79,389	)		(25,474	)
Proceeds received from sale of other operating property and equipment		2,236			21,291
Funds held in escrow and other		153			1,459

Net cash provided by (used in) investing activities		(778,127	)		737,760

Cash flows from financing activities:
Proceeds from borrowings		293,000			1,349,000
Repayments of borrowings		(32,000	)		(1,497,826	)
Cash payments to Noteholders		—			(70,903	)
Debt issuance costs		(4,013	)		(17,220	)
Preferred stock issued		—			400,055
Common stock issued		63,480			—
Offering costs and other		(2,983	)		(13,765	)

Net cash provided by (used in) financing activities		317,484			149,341

Net increase (decrease) in cash and cash equivalents		(423,934	)		989,323
Cash and cash equivalents at beginning of period		424,071			24

Cash and cash equivalents at end of period	$	137		$	989,347



Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$	2,519		$	(28,481	)
Accretion of non-cash preferred dividend		—			48,007

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

Halcón Resources Corporation (Halcón or the Company) is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company's entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company's management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on March 1, 2018. Please refer to the notes in the 2017 Annual Report on Form 10-K when reviewing interim financial results.

Use of Estimates

The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of 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, including estimates of the fair values of assets acquired and liabilities assumed in connection with the Pecos County Acquisition and the fair value of assets sold in connection with the Williston Divestiture and the El Halcón Divestiture (see Note 3, "Acquisitions and Divestitures, " for information on the Pecos County Acquisition, the Williston Divestiture and the El Halcón Divestiture), including the gains on sales recorded 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 September 30, 2018 and December 31, 2017, allowances for doubtful accounts were approximately $0.1 million and $0.7 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 and water gathering systems, thirty years; water disposal and recycling facilities, gas treating systems and buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, the lesser of the lease term or five years; trailers, seven years; heavy equipment, eight to ten years and leasehold improvements, lease term. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

The Company reviews its other operating property and equipment for impairment in accordance with Accounting Standards Codification (ASC) No. 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the 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.

Income Taxes

On December 22, 2017, Staff Accounting Bulletin No. 118 (SAB 118) was issued to address the application of accounting principles generally accepted in the United States in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Cuts Job Act of 2017. In accordance with SAB 118, the Company has determined that the $280.9 million income tax provision and corresponding decrease in the Company's valuation allowance was a provisional amount and a reasonable estimate for the year ended December 31, 2017. Any

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

subsequent adjustments to these amounts will be recorded to current tax benefit (provision) in the fourth quarter of 2018, when the analysis is complete.

Related Party Transactions

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 natural gas 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 nine months ended September 30, 2018, the Company received zero and $0.4 million from Salt Creek under the gas purchase and processing agreement.

Certain funds under the control of Ares Management LLC (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 common 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, also serves on the board of directors of Salt Creek's parent company.

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. The gathering system is expected to be operational by December 31, 2018.

The agreement with SCM was the culmination of a lengthy process during which the Company analyzed the most effective method of gathering and transportation of its future oil production in these areas. During the course of its investigation, the Company considered a variety of alternatives and solicited and received numerous third party proposals. The Company received and evaluated proposals from eleven companies covering some or all of its oil production in the region and determined that among the proposals it received, SCM's was superior for economic and strategic reasons.

Because certain funds under the control of Ares are the majority owners and controlling parties of SCM, the Audit Committee of the board of directors of the Company and the disinterested members of the Company's board of directors evaluated and approved (in a vote that excluded the Company director who is employed by Ares) the process by which the Company determined the SCM proposal to be superior to other alternatives, as well as the principal terms of the agreement, in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company's website at www.halconresources.com) and the Company's procedures for the review and approval of transactions with related parties. Ares also controls other funds which own in excess of ten percent (10%) of the common stock of the Company.

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

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.

Charter of Aircraft

In the ordinary course of its business, the Company occasionally charters a private aircraft for business use. Floyd C. Wilson, Halcón's Chairman, Chief Executive Officer and President, owns an aircraft which the Company has chartered from time to time. For a portion of 2017, Mr. Wilson's aircraft was managed by an independent air charter company unaffiliated with both Mr. Wilson and Halcón. The aircraft in the air charter company's fleet are available to the public for charter based upon a standard fee schedule established by the air charter company, with the fees dependent primarily upon the type and size of the aircraft utilized and the duration of the flight. Because the air charter company established fees for the use of the aircraft in its fleet, Mr. Wilson did not receive any greater benefit from Halcón's charter of the aircraft indirectly owned by him than he would have if any third party were to charter the aircraft. During the course of 2017, Mr. Wilson terminated the independent air charter company and removed his aircraft from the charter company's fleet, pending his search for a new charter company to manage his aircraft. During the search period for a new charter company, 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 of the Company, and subsequently by the disinterested members of the Company's board of directors upon the recommendation of the Audit Committee, in accordance with the Company's procedures for the review and approval of transactions with related parties. During the three and nine months ended September 30, 2018, the Company paid approximately $0.2 million and $0.8 million, respectively, to Mr. Wilson for the Company use of the aircraft. As of September 30, 2018, the Company recorded a $0.1 million payable to Mr. Wilson. The payable is recorded in "Accounts payable and accrued liabilities," on the Company's unaudited condensed consolidated balance sheet.

Recently Issued Accounting Pronouncements

In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). For public business entities, ASU 2017-01 is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2017. The amendments in this ASU should be applied prospectively on or after the effective date. The ASU was issued to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The Company applied the provisions of ASU 2017-01 to the acquisition of the West Quito Draw Properties, which is discussed further in Note 3, "Acquisitions and Divestitures."

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) (ASU 2016-15). For public business entities, ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and early adoption is permitted. The areas for simplification in this ASU involve addressing eight specific classification issues in the statement of cash flows. An entity should apply the amendments in this ASU using a retrospective

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

transition method. The adoption of ASU 2016-15 did not have an impact on the Company's unaudited condensed consolidated statement of cash flows.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and early adoption is permitted. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In January 2018, ASU 2016-02 was updated with ASU No. 2018-01, Lease (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842 (ASU 2018-01), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. An entity that does not elect this practical expedient should evaluate all existing or expired land easements in connection with the adoption of the new lease requirements in Topic 842 to assess whether they meet the definition of a lease. In July 2018, ASU 2016-02 was updated with ASU No. 2018-11, Targeted Improvements to ASC 842, which provides entities with relief from the costs of implementing certain aspects of the new leasing standard. Specifically, under the amendments in ASU 2018-11, (1) entities may elect not to recast the comparative periods presented when transitioning to ASC 842 and (2) lessors may elect not to separate lease and nonlease components when certain conditions are met. Before ASU 2018-11 was issued, transition to the new lease standard required application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. As of September 30, 2018, the Company had approximately $18.5 million of contractual obligations related to its non-cancelable leases and drilling contracts, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under the new leasing standard. In addition, the Company is implementing an accounting software solution to facilitate compliance with the new lease accounting requirements, as well as continuing to analyze its processes and internal controls surrounding its leases. At this time, the Company cannot reasonably estimate the financial statement impact of the adoption of ASU 2016-02; however, the unaudited condensed consolidated balance sheets will be impacted due to the recognition of right-of-use assets and lease liabilities that are not recognized under the current lease accounting guidance. The Company will adopt ASU 2016-02 on January 1, 2019.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08, and collectively with ASU 2014-09, ASC 606), which provides further clarification on the principal versus agent evaluation. The Company adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. See Note 2, "Operating Revenues," for further details.

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2. OPERATING REVENUES

Adoption of ASC 606, Revenue from Contracts with Customers

On January 1, 2018, the Company adopted ASC 606 using the modified retrospective approach applied to all contracts as of the date of adoption. Reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported under the accounting standards in effect for those periods. The adoption of ASC 606 resulted in offsetting changes to revenues and expenses associated with certain natural gas gathering and processing agreements, and therefore there was no cumulative effect of applying ASC 606 to the opening balance of "Retained earnings (accumulated deficit)." The net impact of adopting ASC 606 for the three and nine months ended September 30, 2018 was a decrease of $0.2 million and $0.6 million to "Natural gas" and an offsetting decrease of $0.2 million and $0.6 million to "Gathering and other," respectively, on the unaudited condensed consolidated statements of operations.

These changes result from principal versus agent considerations under ASC 606 for the Company's natural gas gathering and processing arrangements in place with midstream companies. 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."

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 $37.1 million and $24.1 million as of September 30, 2018 and December 31, 2017, 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

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2. OPERATING REVENUES (Continued)

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 September 30,				Nine Months Ended September 30,

	2018		2017⁽¹⁾		2018		2017⁽¹⁾
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	53,918	$	88,256	$	145,743	$	319,472
Natural gas		1,407		2,886		5,286		15,051
Natural gas liquids		5,920		5,448		14,623		16,779

Total oil, natural gas and natural gas liquids sales		61,245		96,590		165,652		351,302
Other		350		363		613		1,386

Total operating revenues	$	61,595	$	96,953	$	166,265	$	352,688

(1): As noted above, prior period amounts have not been adjusted under the modified retrospective method of adoption.

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 treated as 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, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers, and therefore any fees incurred to gather or process the natural gas are presented separately as "Gathering and other."

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2. OPERATING REVENUES (Continued)

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."

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.

Concentrations of Credit Risk

The purchasers of the Company's oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. For the nine months ended September 30, 2018, two individual purchasers of the Company's production, Sunoco, Inc. and Western Refining, Inc., each accounted for more than 10% of total sales, collectively representing 81% of the Company's total sales for the period. In 2017, two individual purchasers of the Company's production, Crestwood Midstream Partners, formerly Arrow Field Services, LLC, and Suncor Energy Marketing, Inc., each accounted for more than 10% of total sales, collectively representing 58% of the Company's total sales for the year.

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company's joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company's joint interest partners to reimburse the Company could be adversely affected.

Practical Expedients

The Company does not disclose the transaction price of unsatisfied performance obligations for i) contracts with an original expected duration of one year or less and ii) contracts where variable consideration is allocated entirely to a wholly unsatisfied performance obligation (each unit of product typically represents a separate performance obligation, and therefore, future volumes under the Company's long-term contracts are wholly unsatisfied).

3. 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

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3. ACQUISITIONS AND DIVESTITURES (Continued)

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 the Additional 2025 Notes and common stock, which are discussed in Note 5, "Long-term Debt," and Note 10, "Stockholders' Equity," respectively.

Monument Draw Assets (Ward and Winkler Counties, Texas)

On December 9, 2016, the Company entered into an agreement with a private company, pursuant to which the Company acquired the rights to purchase acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations for an initial purchase price of $11,000 per acre. The Ward County Assets are divided into two tracts (the Southern Tract and the Northern Tract) with separate options for each tract. The agreement was subsequently amended on June 14, 2017 to increase the purchase price of the Southern Tract and the Northern Tract acreage, from $11,000 per acre to $13,000 per acre, for rights to additional depths in the acreage under option. Pursuant to the terms of the agreement, on June 15, 2017, the Company purchased the Southern Tract acreage for approximately $87.4 million and on January 9, 2018, the Company purchased the Northern Tract acreage for approximately $108.2 million.

Acquisition of Additional Properties in Monument Draw (Ward and Winkler Counties, Texas)

On December 13, 2017, the Company acquired undeveloped acreage and related assets in the Delaware Basin, in an area contiguous to the western and southern areas of the Company's existing Monument Draw properties in Ward County, Texas from a private company, for a total adjusted cash purchase price of $101.8 million. The effective date of the acquisition was September 1, 2017.

Hackberry Draw Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017, Halcón Energy Properties, Inc., a wholly owned subsidiary of the Company, entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which it acquired acreage and related assets in the Hackberry Draw area of the Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total adjusted purchase price of $699.2 million (the Pecos County Acquisition). The Pecos County Acquisition closed on February 28, 2017. The transaction had an effective date of November 1, 2016. The Company funded the Pecos County Acquisition with the net proceeds from the private placement of new 8% automatically convertible preferred stock and borrowings under its Senior Credit Agreement. Refer to Note 10, "Stockholders' Equity," for further discussion of the Company's issuance of the preferred stock.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. ACQUISITIONS AND DIVESTITURES (Continued)

Pro Forma Impact of Acquisition (Unaudited)

As disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, the acquisition of the Pecos County Assets was accounted for as a business combination in accordance with ASC No. 805, Business Combinations (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Certain assets and liabilities may be adjusted as additional information is obtained, but no later than one year from the respective acquisition dates. During the nine months ended September 30, 2018, there were no adjustments to the purchase price of the Pecos County Assets. The purchase price allocation for the Pecos County Assets is complete.

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2017 as though the Pecos County Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2016. The pro forma combined results of operations for the nine months ended September 30, 2017 have been prepared by adjusting the historical results of the Company to include the historical results of the Pecos County Assets. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the period presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Pecos County Acquisition, or any estimated costs that will be incurred to integrate the Pecos County Assets. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors.

The Company's historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Pecos County Acquisition and that were factually supportable. Adjustments and assumptions made for this pro forma calculation are consistent with those used in the Company's annual pro forma information, as more fully described in Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures," to the Company's Annual Report on Form 10-K for the year ended December 31, 2017. Amounts included in the table below are rounded to thousands, except per share amounts.

	Nine Months Ended September 30, 2017

	(Unaudited)
Revenue	$	360,590
Net income (loss)		635,854
Net income (loss) available to common stockholders		587,847
Pro forma net income (loss) per share of common stock:
Basic	$	4.61
Diluted	$	4.58

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3. ACQUISITIONS AND DIVESTITURES (Continued)

Divestitures

Williston Basin Non-Operated Assets

On September 19, 2017, certain wholly owned subsidiaries of the Company entered into an agreement with a privately-owned company pursuant to which the Company sold its non-operated properties and related assets located in the Williston Basin in North Dakota and Montana (the Non-Operated Williston Assets) for a total adjusted sales price of $103.4 million. The effective date of the transaction was April 1, 2017 and the transaction closed on November 9, 2017. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

Williston Basin Operated Assets

On July 10, 2017, the Company and certain of its subsidiaries entered into an agreement with Bruin Williston Holdings, LLC for the sale 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 (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion (the Williston Divestiture). The effective date of the sale was June 1, 2017 and the transaction closed on September 7, 2017. The Company used the net proceeds from the sale to repay borrowings outstanding under its Senior Credit Agreement, repurchase approximately $425.0 million principal amount of the then outstanding $850.0 million principal amount of its 6.75% senior notes, redeem all of its outstanding 12% senior secured second lien notes and for general corporate purposes.

The net proceeds from the sale were allocated between the Company's oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $1.39 billion was allocated to the Company's oil and natural gas properties and approximately $10.9 million was allocated to other operating property and equipment.

As discussed further in Note 4, "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, 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 $7.2 million during the nine months ended September 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.

East Texas Eagle Ford Assets

On January 24, 2017, certain of the Company's subsidiaries entered into an agreement with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of its oil and natural gas

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3. ACQUISITIONS AND DIVESTITURES (Continued)

properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total adjusted sales price of $491.1 million (the El Halcón Divestiture). The effective date of the sale was January 1, 2017 and the transaction closed on March 9, 2017. The Company used the net proceeds from the sale to repay borrowings outstanding under its Senior Credit Agreement and for general corporate purposes.

The net proceeds from the sale were allocated between the Company's oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $484.1 million was allocated to the Company's oil and natural gas properties and $10.2 million was allocated to other operating property and equipment.

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 El Halcón 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 $235.7 million during the year ended December 31, 2017. 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 was recorded in "Gain (loss) on sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

4. OIL AND NATURAL GAS PROPERTIES

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

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

At September 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 September 30, 2018 of the West Texas Intermediate (WTI) crude oil spot price of $63.43 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 September 30, 2018 of the Henry Hub natural gas price of $2.91 per million British

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4. OIL AND NATURAL GAS PROPERTIES (Continued)

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 September 30, 2018 did not exceed the ceiling amount.

At September 30, 2017, 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 September 30, 2017 of the WTI crude oil spot price of $49.81 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 September 30, 2017 of the Henry Hub natural gas price of $3.00 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at September 30, 2017 did not exceed the ceiling amount.

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

5. LONG-TERM DEBT

Long-term debt as of September 30, 2018 and December 31, 2017 consisted of the following (in thousands):

	September 30, 2018		December 31, 2017

Senior revolving credit facility	$	55,000	$	—
6.75% senior notes due 2025⁽¹⁾		612,726		409,168

	$	667,726	$	409,168

(1): On February 15, 2018, the Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at 103.0% of par. Amount includes a $7.4 million and $8.1 million unamortized discount at September 30, 2018 and December 31, 2017, respectively, associated with the 2025 Notes. Amount includes a $5.6 million unamortized premium at September 30, 2018, associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.4 million and $7.7 million unamortized debt issuance costs at September 30, 2018 and December 31, 2017, respectively. Refer to "6.75% Senior Notes" below for further details.

Senior Revolving Credit Facility

On September 7, 2017, the Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Senior Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the Senior Credit Agreement, the lenders party thereto have agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a current borrowing base of $200.0 million. The maturity date of the Senior Credit Agreement is September 7, 2022. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant

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5. LONG-TERM DEBT (Continued)

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 1.25% to 2.25% for ABR-based loans or at specified margins over LIBOR of 2.25% to 3.25% 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 also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement), which was recently revised by the Consent and Fifth Amendment, as discussed below, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00 to 1.00.

The Senior Credit Agreement also 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.

At September 30, 2018, under the then effective borrowing base of $200.0 million, the Company had $55.0 million of indebtedness outstanding, approximately $1.6 million letters of credit outstanding and approximately $143.4 million of borrowing capacity available under the Senior Credit Agreement.

On November 7, 2018, the Company entered into the Fifth Amendment (the Fifth Amendment) to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of (a) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (b) 4.25 to 1.0 for the fiscal quarter ending December 31, 2018 and (c) 4.0 to 1.0 for the fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter.

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

On July 12, 2018, the Company entered into the Fourth Amendment (the Fourth Amendment) to the Senior Credit Agreement which provided for an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA (as defined in the Senior Credit Agreement) of (i) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (ii) 5.0 to 1.0 for the fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019, (iii) 4.25 to 1.0 for the fiscal quarter ending September 30, 2019 and (iv) 4.0 to 1.0 for the fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter; provided, however, that if the Company consummates a sale of all or a material portion of its midstream assets, then the ratio of Consolidated Total Net Debt to

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5. LONG-TERM DEBT (Continued)

EBITDA shall be reduced to 4.0 to 1.0 for each fiscal quarter ending after the fiscal quarter in which such sale is consummated.

On May 1, 2018, the Company entered into the Third Amendment (the Third Amendment) to the Senior Credit Agreement which provided for an assignment and reallocation of the Maximum Credit Amounts (as defined in the Senior Credit Agreement) among certain of the lender financial institutions. The Third Amendment did not adjust the aggregate Maximum Credit Amounts, which remain at $1.0 billion.

On February 2, 2018, the Company entered into the Second Amendment (the Second Amendment) to 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. The Second Amendment 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 June 30, 2018, September 30, 2018 and December 31, 2018, (ii) an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of 4.50 to 1.00 for the fiscal quarter ending June 30, 2018, and a ratio of 4.00 to 1.00 for any fiscal quarter thereafter, (iii) a waiver of compliance with the covenant relating to the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2018, and (iv) a waiver of the automatic reduction to the borrowing base that would otherwise result due to the issuance of the Additional 2025 Notes (defined below).

After giving effect to the Consent and the Fifth Amendment, at September 30, 2018, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

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 then outstanding 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes) and for general corporate purposes. Upon repurchase and redemption of the 2020 Second Lien Notes during the three months ended March 31, 2017, the Company recorded a loss on extinguishment of debt of approximately $56.9 million, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes.

The 2025 Notes are governed by an Indenture, dated as of February 16, 2017 (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;

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5. LONG-TERM DEBT (Continued)

and, in certain circumstances, to pay dividends or make other distributions on stock. The February 2017 Indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 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 filed the registration statement on November 1, 2017 and it was declared effective by the SEC on December 21, 2017. In addition, 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 amends provisions in order to exempt, among other things, the Williston Divestiture from certain provisions therein 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 Additional 2025 Notes were issued in a private placement exempt from registration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act and applicable state securities laws. The net proceeds from the sale of the Additional 2025 Notes were approximately $202.4 million after initial purchasers' premiums and deducting commissions and offering expenses and were used to fund the cash consideration for the acquisition of the West Quito Draw Properties, discussed further in Note 3, "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.

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5. LONG-TERM DEBT (Continued)

The Additional 2025 Notes are treated as a single class with, and have the same terms as, the 2025 Notes, except that the Additional 2025 Notes will initially be subject to transfer restrictions and have the benefit of certain registration rights and provisions for the payment of additional interest in the event of a breach with respect to such registration rights pursuant to the terms of a Registration Rights Agreement, entered into on February 15, 2018 (the 2018 Registration Rights Agreement). Pursuant to the 2018 Registration Rights Agreement 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 180 days after closing. The Company filed the registration statement on March 20, 2018 and it was declared effective by the SEC on April 9, 2018. In addition, the Company completed the exchange offer for the Additional 2025 Notes on May 17, 2018.

The remaining unamortized discount on the 2025 Notes was $7.4 million at September 30, 2018. The unamortized premium on the Additional 2025 Notes was $5.6 million at September 30, 2018.

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. During the nine months ended September 30, 2018, the Company capitalized approximately $3.9 million of debt issuance costs related to the Senior Credit Agreement and the Additional 2025 Notes. At September 30, 2018 and December 31, 2017, the Company had approximately $11.2 million and $8.3 million, respectively, of unamortized debt issuance costs. The debt issuance costs for the Company's Senior Credit Agreement are presented in "Funds in escrow and other" and the debt issuance costs for the Company's senior unsecured debt are presented in "Long-term debt, net" on the unaudited condensed consolidated balance sheets.

6. 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.

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6. FAIR VALUE MEASUREMENTS (Continued)

As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of September 30, 2018 and December 31, 2017 (in thousands):

	September 30, 2018

	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	19,347	$	—	$	19,347



Liabilities
Liabilities from derivative contracts	$	—	$	123,635	$	—	$	123,635

	December 31, 2017

	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	677	$	—	$	677



Liabilities
Liabilities from derivative contracts	$	—	$	26,999	$	—	$	26,999

Derivative contracts listed above as Level 2 include collars, puts, calls, 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 7, "Derivative and Hedging Activities," for additional discussion of derivatives.

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

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

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6. FAIR VALUE MEASUREMENTS (Continued)

the estimated fair values of the Company's fixed interest rate debt instruments as of September 30, 2018 and December 31, 2017 (excluding discounts, premiums and debt issuance costs) (in thousands):

	September 30, 2018				December 31, 2017

Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
6.75% senior notes	$	625,005	$	600,005	$	425,005	$	443,790

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; consequently, the Company has designated these liabilities as Level 3. See Note 8, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

7. 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 changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company's hedge policies and objectives may change significantly as its operational profile changes and/or commodities prices change. The Company does not enter into derivative contracts for speculative trading purposes.

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

The Company's crude oil, natural gas and natural gas liquids derivative positions at any point in time generally consist of swaps, basis swaps and costless put/call "collars." Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) and the relevant price index at which the oil production is sold (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

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7. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

At September 30, 2018, the Company had 85 open commodity derivative contracts summarized in the following tables: eight natural gas collar arrangements, seven natural gas basis swaps, eight natural gas liquids swaps, 25 crude oil basis swaps, 31 crude oil collar arrangements two crude oil puts, three crude oil calls, and one crude oil WTI NYMEX roll.

At December 31, 2017, the Company had 34 open commodity derivative contracts summarized in the following tables: three natural gas collar arrangements, 12 crude oil basis swaps and 19 crude oil collar arrangements.

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 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	September 30, 2018⁽¹⁾		December 31, 2017		Balance sheet location	September 30, 2018⁽²⁾			December 31, 2017
Commodity contracts	Current assets—receivables from derivative contracts	$	16,553	$	677	Current liabilities—liabilities from derivative contracts	$	(86,176	)	$	(19,248	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		2,794		—	Other noncurrent liabilities—liabilities from derivative contracts		(37,459	)		(7,751	)

Total derivatives not designated as hedging contracts under ASC 815		$	19,347	$	677		$	(123,635	)	$	(26,999	)

(1): Amount includes a $0.7 million deferred premium asset classified all as current as of September 30, 2018.
(2): Amount includes a $4.7 million deferred premium obligation of which $0.3 million was classified as current as of September 30, 2018.

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						Amount of gain or (loss) recognized in income on derivative contracts for the

		Three Months Ended September 30,						Nine Months Ended September 30,
	Location of gain or (loss) recognized in income on derivative contracts	Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives not designated as hedging contracts under ASC 815		2018			2017			2018			2017
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(50,763	)	$	(31,209	)	$	(77,524	)	$	11,010
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		(9,643	)		8,794			10,921			17,129

Total net gain (loss) on derivative contracts		$	(60,406	)	$	(22,415	)	$	(66,603	)	$	28,139

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

At September 30, 2018 and December 31, 2017, the Company had the following open crude oil, natural gas and natural gas liquids derivative contracts:

			September 30, 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
October 2018 - December 2018	Basis Swap	Crude Oil		1,012,000		$—	$	—	$—	$	—	$(6.90) - $(12.50)	$	(10.64	)
October 2018 - December 2018	Basis Swap	Natural Gas		1,380,000								(1.05) - (1.19)		(1.10	)
October 2018 - December 2018	Collars	Crude Oil		1,196,000		45.00 - 55.80		50.08	50.00 - 63.00		56.87
October 2018 - December 2018	Collars	Natural Gas		690,000		3.00 - 3.03		3.01	3.22 - 3.38		3.30
October 2018 - December 2018	Calls	Crude Oil		1,196,000					59.00 - 63.00		59.92
October 2018 - December 2018	Calls	Crude Oil		(1,196,000	)				50.00 - 63.00		56.87
October 2018 - December 2018	Swap	Natural Gas Liquids		92,000		32.50		32.50
October 2018 - December 2018	WTI NYMEX Roll	Crude Oil		460,000								0.35		0.35
January 2019 - March 2019	Collars	Crude Oil		90,000		46.75		46.75	51.75		51.75
January 2019 - June 2019	Basis Swap	Crude Oil		543,000								(1.15) - (1.33)		(1.22	)
January 2019 - September 2019	Basis Swap	Crude Oil		546,000								(6.20) - (7.60)		(6.90	)
January 2019 - December 2019	Basis Swap	Crude Oil		2,365,000								(0.98) - (6.50)		(3.73	)
January 2019 - December 2019	Basis Swap	Natural Gas		9,307,500								(1.05) - (1.40)		(1.18	)
January 2019 - December 2019	Collars	Crude Oil		5,110,000		50.00 - 58.00		53.12	55.00 - 63.00		58.98
January 2019 - December 2019	Collars	Natural Gas		8,395,000		2.52 - 2.65		2.60	3.00 - 3.03		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 - December 2019	Collars	Crude Oil		275,000		55.00		55.00	62.85		62.85
July 2019 - December 2019	Collars	Crude Oil		184,000		55.00		55.00	69.00		69.00
October 2019 - December 2019	Basis Swap	Crude Oil		368,000								3.45 - 3.75		3.65
October 2019 - December 2019	Swap	Natural Gas Liquids		92,000		32.50		32.50
January 2020 - December 2020	Basis Swap	Crude Oil		2,928,000								2.00 - 3.75		2.82
January 2020 - December 2020	Collars	Crude Oil		549,000		50.00		50.00	70.00		70.00
January 2020 - December 2020	Calls	Crude Oil		1,464,000					70.00		70.00
January 2020 - December 2020	Puts	Crude Oil		915,000		55.00		55.00
January 2020 - December 2020	Swap	Natural Gas Liquids		732,000		31.00		31.00

			December 31, 2017

					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 2018 - December 2018	Basis Swap	Crude Oil		2,555,000	$—	$	—	$—	$	—	$(1.05) - $(1.50)	$	(1.29	)
January 2018 - December 2018	Collars	Crude Oil		2,920,000	45.00 - 53.00		49.29	50.00 - 60.00		56.82
January 2018 - December 2018	Collars	Natural Gas		2,737,500	3.00 - 3.03		3.01	3.22 - 3.38		3.30
April 2018 - December 2018	Basis Swap	Crude Oil		275,000							(1.15)		(1.15	)
April 2018 - December 2018	Collars	Crude Oil		275,000	46.75		46.75	51.75		51.75
July 2018 - December 2018	Basis Swap	Crude Oil		1,012,000							(0.98) - (1.18)		(1.12	)
July 2018 - December 2018	Collars	Crude Oil		184,000	48.50		48.50	53.50		53.50
October 2018 - December 2018	Collars	Crude Oil		92,000	50.65		50.65	55.65		55.65
January 2019 - March 2019	Collars	Crude Oil		90,000	46.75		46.75	51.75		51.75
January 2019 - December 2019	Basis Swap	Crude Oil		4,380,000							(0.50) - (1.33)		(1.02	)
January 2019 - December 2019	Collars	Crude Oil		1,825,000	50.00 - 51.00		50.24	55.00 - 57.30		55.70

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. 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 (in thousands):

	Derivative Assets						Derivative Liabilities

Offsetting of Derivative Assets and Liabilities	September 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
Gross Amounts Presented in the Consolidated Balance Sheet	$	19,347		$	677		$	(123,635	)	$	(26,999	)
Amounts Not Offset in the Consolidated Balance Sheet		(18,040	)		(231	)		18,040			231

Net Amount	$	1,307		$	446		$	(105,595	)	$	(26,768	)

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.

8. 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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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. ASSET RETIREMENT OBLIGATIONS (Continued)

The Company recorded the following activity related to its ARO liability (in thousands, inclusive of the current portion):


Liability for asset retirement obligations as of December 31, 2017	$	4,368
Liabilities settled and divested		(110	)
Additions		796
Acquisitions⁽¹⁾		2,465
Accretion expense		225
Revisions in estimated cash flows		(632	)

Liability for asset retirement obligations as of September 30, 2018	$	7,112

(1): See Note 3, "Acquisitions and Divestitures," for additional information on the Company's acquisition and divestiture activities.

9. COMMITMENTS AND CONTINGENCIES

Commitments

The Company leases corporate office space in Houston, Texas and Denver, Colorado. Rent expense was approximately $2.8 million and $3.0 million for the nine months ended September 30, 2018 and 2017, respectively. Future obligations associated with the Company's operating leases are presented in the table below (in thousands):


Remaining period in 2018	$	846
2019		2,990
2020		1,811
2021		1,497
2022		835
Thereafter		1,345

Total	$	9,324

As of September 30, 2018, the Company has the following active drilling rig commitments (in thousands):


Remaining period in 2018	$	4,419
2019		4,726
2020		—
2021		—
2022		—
Thereafter		—

Total	$	9,145

As of September 30, 2018, termination of the Company's active drilling rig commitments would require early termination penalties of $8.2 million, which would be in lieu of paying the remaining active commitments of $9.1 million.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. COMMITMENTS AND CONTINGENCIES (Continued)

In past years, with the sustained decline in crude oil prices, the Company stacked certain drilling rigs and amended previously entered into drilling rig contracts. In connection with the early termination of a drilling contract from 2015, if certain requirements are not met by January 12, 2020, the Company may incur an additional $3.0 million. Rig stacking fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations and are not included in the table above.

In September 2018, the Company entered into a purchase agreement for certain natural gas treating equipment totaling approximately $13.3 million. As of September 30, 2018, the Company's remaining commitment is approximately $9.8 million and is expected to be incurred by March 31, 2019.

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 September 30, 2018, 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 this area for periods ranging from one to twenty years from the date of first production.

Contingencies

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

10. STOCKHOLDERS' EQUITY

Preferred Stock and Non-Cash Preferred Stock Dividend

On January 24, 2017 (the Commitment Date), the Company entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which was convertible into 10,000 shares of common stock. Also on January 24, 2017, the Company received an executed written consent in lieu of a stockholders' meeting authorizing and approving the conversion of the Preferred Stock into common stock. On February 27, 2017, the Company filed with the Delaware Secretary of State a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation), which created the series of preferred stock issued by the Company on that same date. The Company issued the Preferred Stock at $72,500 per share. Gross proceeds were approximately $400.1 million, or $7.25 per share of common stock. The Company incurred approximately $11.9 million in expenses associated with this offering, including placement agent fees. On March 16, 2017, the Company mailed a definitive information statement to its common stockholders notifying them that a majority of its stockholders had consented to the issuance of common stock, par value $0.0001 per share, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 55.2 million shares of common stock on

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCKHOLDERS' EQUITY (Continued)

April 6, 2017 in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since, pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to June 1, 2017.

The Company agreed to file a registration statement to register the resale of shares of common stock issuable upon conversion of the Preferred Stock and to pay penalties in the event such registration was not effective by June 27, 2017. The Company filed such registration statement on March 3, 2017 and it was declared effective by the SEC on April 7, 2017.

In accordance with ASC Topic 470, Debt (ASC 470), the Company determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature. The fair value of the Company's common stock of $8.12 per share on the Commitment Date was greater than the conversion price of $7.25 per share of common stock, representing a beneficial conversion feature of $0.87 per share of common stock, or approximately $48.0 million in aggregate. Under ASC 470, $48.0 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to "Additional paid-in capital," creating a discount on the Preferred Stock (the Discount). The Discount was required to be amortized on a non-cash basis over the approximate 65-month period between the issuance date and the required redemption date of July 28, 2022, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. As a result, approximately $0.8 million of the Discount was amortized and a non-cash preferred dividend was recorded in the three months ended March 31, 2017 and due to the conversion date occurring on April 6, 2017, the remaining $47.2 million of the amortization of the Discount was accelerated to the conversion date and fully amortized in the three months ended June 30, 2017. The Discount amortization is reflected in "Non-cash preferred dividend" in the unaudited condensed consolidated statements of operations. The preferred dividend was charged against additional paid-in capital since no retained earnings were available.

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCKHOLDERS' EQUITY (Continued)

by 9.0 million shares, the maximum number of shares of common stock that may be issued thereunder, i.e., a maximum of 19.0 million shares, became effective, which was 20 calendar days following the date the Company mailed an information statement to all stockholders of record notifying them of approval of the amendment by written consent of holders of a majority of the Company's outstanding stock. As of September 30, 2018 and December 31, 2017, a maximum of 4.9 million and 7.7 million shares, respectively, of the Company's common stock remained reserved for issuance under the Plan.

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

For the three and nine months ended September 30, 2018, the Company recognized $4.4 million and $12.2 million, respectively, of stock-based compensation expense. For the three and nine months ended September 30, 2017, the Company recognized $12.3 million and $33.5 million, respectively, of stock-based compensation expense. Stock-based compensation expense is recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

Stock Options

From time to time, the Company grants stock options under the Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date.

During the nine months ended September 30, 2018, the Company granted stock options under the Plan covering 1.2 million shares of common stock to employees of the Company. These stock options have an exercise price of $5.65. During the nine months ended September 30, 2018, the Company received $0.3 million from the exercise of stock options. At September 30, 2018, the Company had $7.1 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.1 years.

During the nine months ended September 30, 2017, the Company granted stock options under the Plan covering 1.8 million shares of common stock to employees of the Company. These stock options have exercise prices ranging from $6.55 to $7.75 per share with a weighted average exercise price of $7.72 per share. At September 30, 2017, the Company had $17.3 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.5 years.

Restricted Stock

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. Certain shares granted under the Plan specifically related to the Company's emergence from chapter 11 bankruptcy, vested on or before September 30, 2017.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. STOCKHOLDERS' EQUITY (Continued)

During the nine months ended September 30, 2018, the Company granted 2.3 million shares of restricted stock under the Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $3.75 to $5.65 with a weighted average price of $5.47. At September 30, 2018, the Company had $8.6 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.2 years.

During the nine months ended September 30, 2017, the Company granted 2.0 million shares of restricted stock under the Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $6.08 to $7.75 per share with a weighted average price of $7.07 per share. At September 30, 2017, the Company had $5.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. EARNINGS PER COMMON SHARE

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

	Three Months Ended September 30,					Nine Months Ended September 30,

	2018			2017		2018			2017
Basic:
Net income (loss) available to common stockholders	$	(81,837	)	$	419,287	$	(100,709	)	$	580,809



Weighted average basic number of common shares outstanding		158,011			146,944		156,628			127,458

Basic net income (loss) per share of common stock	$	(0.52	)	$	2.85	$	(0.64	)	$	4.56



Diluted:
Net income (loss) available to common stockholders	$	(81,837	)	$	419,287	$	(100,709	)	$	580,809



Weighted average basic number of common shares outstanding		158,011			146,944		156,628			127,458
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			1,546		Anti-dilutive			952
Conversion of preferred stock		—			—		—			Anti-dilutive

Weighted average diluted number of common shares outstanding		158,011			148,490		156,628			128,410

Diluted net income (loss) per share of common stock	$	(0.52	)	$	2.82	$	(0.64	)	$	4.52

Common stock equivalents, including stock options, restricted shares, and warrants totaling 14.9 million and 14.3 million shares for the three and nine months ended September 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.

Common stock equivalents, including stock options, restricted shares, warrants, and preferred stock totaling 11.7 million and 19.0 million shares for the three and nine months ended September 30, 2017, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

	September 30, 2018		December 31, 2017

Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	37,085	$	24,110
Joint interest accounts		8,736		2,249
Other		943		10,057

	$	46,764	$	36,416



Prepaids and other:
Prepaids	$	4,684	$	4,324
Income tax receivable		6,250		6,250
Other		35		54

	$	10,969	$	10,628



Funds in escrow and other:
Funds in escrow	$	568	$	563
Other		1,347		1,128

	$	1,915	$	1,691



Accounts payable and accrued liabilities:
Trade payables	$	51,192	$	35,688
Accrued oil and natural gas capital costs		53,692		50,743
Revenues and royalties payable		20,587		20,256
Accrued interest expense		5,858		10,985
Accrued employee compensation		5,086		9,805
Accrued lease operating expenses		4,667		2,024
Other		295		1,586

	$	141,377	$	131,087

13. SUBSEQUENT EVENTS

Sale of Water Infrastructure Assets

On October 31, 2018, certain wholly owned subsidiaries of the Company entered into an Asset Purchase Agreement (the Agreement) with an affiliate of WaterBridge Resources LLC (the Purchaser) pursuant to which the Company agreed to sell its water infrastructure assets located in the Delaware Basin (the Water Assets) to Purchaser for a total purchase price of up to $325.0 million, consisting of $200.0 million payable in cash upon closing and additional incentive payments of up to $25.0 million per year for the next five years based on the Company's ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. The ability of the Company to achieve the incentive thresholds will be driven by, among other things, its development program which will consider future market conditions and is subject to change. The purchase price is subject to adjustment for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date and (ii) environmental defects, if any.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. SUBSEQUENT EVENTS (Continued)

The effective date of the transaction is October 1, 2018 and the transaction is expected to close in late-December 2018, subject to satisfaction of customary closing conditions set forth in the Agreement. The Agreement also contains customary representations, warranties and covenants by the Company and Purchaser and contemplates a transition services period whereby the Company would operate the Water Assets for approximately two months following the closing and also operate the Water Assets in Monument Draw for approximately six months in order to install additional water service and treating infrastructure. In addition, the parties have agreed to negotiate in good faith prior to closing, a definitive agreement relating to certain water supply assets. While the parties have a non-binding agreement relating to the material business terms of such agreement, if they are unable to agree on a definitive agreement prior to closing, certain water supply assets will remain with the Company and $30.0 million of the cash purchase price will not be paid to the Company until such time as such definitive agreement is executed. At closing, the Company will dedicate all of the produced water from its oil and natural gas wells within the Company's Monument Draw, Hackberry Draw and West Quito Draw operating areas to Purchaser. Purchaser will be entitled to receive a current market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and assuming a definitive agreement related to the water supply assets is executed, Purchaser will be entitled to receive a market price for the supply of freshwater and recycled produced water to the Company.

Borrowing Base Redetermination

The Company recently completed the fall 2018 borrowing base redetermination for its Senior Credit Agreement. The Company received commitments to increase its borrowing base from $200.0 million to $275.0 million upon the closing of its water infrastructure assets sale in December 2018.

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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 nine months ended September 30, 2018 and 2017 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, 2017.

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, where we have an extensive drilling inventory that we believe offers more attractive economics. The Williston Divestiture improved our liquidity and significantly reduced our debt, better enabling us to accelerate development of our Delaware Basin properties and execute our growth plans in the basin.

Our average daily oil and natural gas production decreased in the first nine months of 2018 when compared to the same period in the prior year primarily due to our divestitures in 2017. This decrease was partially mitigated by the production associated with our assets located in the Delaware Basin and our drilling activities since acquiring the assets. During the first nine months of 2018, production averaged 12,795 Boe/d compared to average daily production of 34,513 Boe/d during the first nine months of 2017. During the first nine months of 2018, we participated in the drilling of 22 gross (21.7 net) wells, none of which were dry holes.

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

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could have a material impact upon our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for October 1, 2018 of $75.30 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 not have generated an impairment. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Our 2018 capital budget has been revised to reflect changes in our drilling program. We have reduced our number of operated rigs running in the Delaware Basin from four to three rigs. We expect

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to spend approximately $75 million to $95 million on drilling and completion capital expenditures in the fourth quarter of 2018. In addition, we expect to spend approximately $20 million to $30 million on infrastructure, seismic and other in the fourth quarter of 2018. Our capital budget for the fourth quarter of 2018 is based on our current view of market conditions and current business plans, and is subject to change.

Recent Developments

Sale of Water Infrastructure Assets

On October 31, 2018, we entered into an Asset Purchase Agreement (the Agreement) with an affiliate of WaterBridge Resources LLC (the Purchaser) pursuant to which we agreed to sell our water infrastructure assets located in the Delaware Basin (the Water Assets) to Purchaser for a total purchase price of up to $325.0 million, consisting of $200.0 million payable in cash upon closing and additional incentive payments of up to $25.0 million per year for the next five years based on our ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. Our ability to achieve the incentive thresholds will be driven by, among other things, our development program which will consider future market conditions and is subject to change. The purchase price is subject to adjustment for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date and (ii) environmental defects, if any.

The effective date of the transaction is October 1, 2018 and the transaction is expected to close in late-December 2018, subject to satisfaction of customary closing conditions set forth in the Agreement. The Agreement also contains customary representations, warranties and covenants by us and Purchaser and contemplates a transition services period whereby we would operate the Water Assets for approximately two months following the closing and also operate the Water Assets in Monument Draw for approximately six months in order to install additional water service and treating infrastructure. In addition, the parties have agreed to negotiate in good faith prior to closing, a definitive agreement relating to certain water supply assets. While the parties have a non-binding agreement relating to the material business terms of such agreement, if they are unable to agree on a definitive agreement prior to closing, certain water supply assets will remain with us and $30.0 million of the cash purchase price will not be paid to us until such time as such definitive agreement is executed. At closing, we will dedicate 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 Purchaser. Purchaser will be entitled to receive a current market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and assuming a definitive agreement related to the water supply assets is executed, Purchaser will be entitled to receive a market price for the supply of freshwater and recycled produced water to us.

Borrowing Base Redetermination

We recently completed the fall 2018 borrowing base redetermination for our Senior Credit Agreement. We received commitments to increase our borrowing base from $200.0 million to $275.0 million upon the closing of our water infrastructure assets sale in December 2018.

Acquisition of West Quito Draw Properties

On February 6, 2018, one of our wholly owned subsidiaries entered into a Purchase and Sale Agreement (the Shell PSA) with SWEPI LP (Shell), an affiliate of Shell Oil Company, pursuant to which we agreed to purchase 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 we closed the transaction on April 4, 2018. We funded the cash consideration of the acquisition of the West Quito Draw Properties with the net

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proceeds from our recent issuance of the Additional 2025 Notes (defined below) and common stock, both of which are discussed below.

Issuance of Additional 2025 Notes

On February 15, 2018, we issued an additional $200.0 million aggregate principal amount of our 6.75% senior notes due 2025 at a price to the initial purchasers of 103.0% of par (the Additional 2025 Notes). The Additional 2025 Notes were sold pursuant to the exemption from registration under the Securities Act and applicable state securities laws, including Rule 144A and Regulation S under the Securities Act. The net proceeds from the sale of the Additional 2025 Notes were approximately $202.4 million after initial purchasers' premiums and deducting commissions and offering expenses and a portion was used to fund the cash consideration for the acquisition of the West Quito Draw Properties and for general corporate purposes, including funding our 2018 drilling program. These notes were issued under the Indenture, dated as of February 16, 2017, among us, certain of our subsidiaries and U.S. Bank National Association, as trustee, which governs our 6.75% senior notes due 2025 that were issued on February 16, 2017 (the 2025 Notes). The Additional 2025 Notes are treated as a single class with, and have the same terms as the 2025 Notes, except that the Additional 2025 Notes will initially be subject to transfer restrictions and have the benefit of certain registration rights and provisions for the payment of additional interest in the event of a breach with respect to such registration rights.

In connection with the issuance of the Additional 2025 Notes, on February 15, 2018, we, our subsidiary guarantors and J.P. Morgan Securities, LLC, on behalf of itself and the initial purchasers, entered into a Registration Rights Agreement, pursuant to which we and our subsidiary guarantors 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 Additional 2025 Notes within 180 days after closing. We filed such registration statement on March 20, 2018 and it was declared effective by the Securities and Exchange Commission (SEC) on April 9, 2018. In addition, we completed the exchange offer for the Additional 2025 Notes on May 17, 2018.

Issuance of Common Stock

On February 9, 2018, we 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 us from the offering were approximately $60.4 million, after deducting underwriters' discounts and offering expenses.

Amended and Restated Senior Secured Revolving Credit Agreement

On November 7, 2018, we entered into the Fifth Amendment (the Fifth Amendment) to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of (a) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (b) 4.25 to 1.0 for the fiscal quarter ending December 31, 2018 and (c) 4.0 to 1.0 for the fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter.

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

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On July 12, 2018, we entered into the Fourth Amendment (the Fourth Amendment) to the Senior Credit Agreement which provided for an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA (as defined in the Senior Credit Agreement) of (i) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (ii) 5.0 to 1.0 for the fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019, (iii) 4.25 to 1.0 for the fiscal quarter ending September 30, 2019 and (iv) 4.0 to 1.0 for the fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter; provided, however, that if we consummate a sale of all or a material portion of our midstream assets, then the ratio of Consolidated Total Net Debt to EBITDA shall be reduced to 4.0 to 1.0 for each fiscal quarter ending after the fiscal quarter in which such sale is consummated.

On May 1, 2018, we entered into the Third Amendment (the Third Amendment) to the Senior Credit Agreement which provided for an assignment and reallocation of the Maximum Credit Amounts (as defined in the Senior Credit Agreement) among certain of the lender financial institutions. The Third Amendment did not adjust the aggregate Maximum Credit Amounts, which remain at $1.0 billion, or the borrowing base, which is currently $200.0 million.

On February 2, 2018, we entered into the Second Amendment (the Second Amendment) to the Senior Credit Agreement which among other things, for certain fiscal quarters in 2018, provided flexibility with respect to certain financial covenants as specified in the Senior Credit Agreement. The Second Amendment provides for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending June 30, 2018, September 30, 2018 and December 31, 2018, (ii) an increase in the ratio of our Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of 4.50 to 1.00 for the fiscal quarter ending June 30, 2018, and a ratio of 4.00 to 1.00 for any fiscal quarter thereafter, (iii) a waiver of compliance with the covenant relating to the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2018, and (iv) a waiver of the automatic reduction to the borrowing base that would otherwise have resulted from the issuance of the Additional 2025 Notes. The Senior Credit Agreement also contains a financial covenant to maintain a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00 to 1.00.

Option Agreement to Acquire Monument Draw Assets (Ward and Winkler Counties, Texas)

On December 9, 2016, one of our wholly owned subsidiaries entered into an agreement with a private company, pursuant to which it acquired the rights to purchase up to 15,040 net acres in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations. The Ward County Assets are divided into two tracts (the Southern Tract and the Northern Tract) with separate options for each tract. Pursuant to the terms of the agreement (as amended), on June 15, 2017, we purchased the Southern Tract for approximately $87.4 million and on January 9, 2018, we purchased the Northern Tract for approximately $108.2 million.

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, proceeds from recent debt and equity issuances and borrowings under our Senior Credit Agreement, which has a current borrowing base of $200.0 million. As of September 30, 2018, under the effective borrowing base of $200.0 million, we had $55.0 million of indebtedness outstanding, $1.6 million letters of credit outstanding, and approximately $143.4 million of borrowing capacity available under the Senior Credit Agreement. Amounts borrowed under the Senior Credit Agreement will mature on September 7, 2022. Our borrowing base is redetermined on a semi-annual basis (with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations) and adjusted based on the estimated value of our oil and natural gas reserves, the amount and cost of our other indebtedness and

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other relevant factors. We recently completed the fall 2018 borrowing base redetermination for our Senior Credit Agreement. We received commitments to increase our borrowing base from $200.0 million to $275.0 million upon the closing of our water infrastructure assets sale in December 2018, as discussed above in "Recent Developments."

We have recently, and in the past, obtained amendments and consents to the covenants under our financing agreements under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. Most recently, 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. This, coupled with our current drilling plans, has impacted our ability to comply with our debt covenants by reducing our production and reserves on a current and, for purposes of covenant calculations, a pro forma historical basis, and drilling will take time to replace this lost production and related EBITDA. On November 7, 2018, we entered into the Fifth Amendment to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of (a) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (b) 4.25 to 1.0 for the fiscal quarter ending December 31, 2018 and (c) 4.0 to 1.0 for the fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter. On November 6, 2018, the lenders party to the Senior Credit Agreement issued the Consent to us whereby H2S Expenses (as defined in the Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019. On July 12, 2018, we entered into the Fourth Amendment to the Senior Credit Agreement which provided for an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA (as defined in the Senior Credit Agreement) of (i) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (ii) 5.0 to 1.0 for the fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019, (iii) 4.25 to 1.0 for the fiscal quarter ending September 30, 2019 and (iv) 4.0 to 1.0 for the fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter; provided, however, that if we consummate a sale of all or a material portion of our midstream assets, then the ratio of Consolidated Total Net Debt to EBITDA shall be reduced to 4.0 to 1.0 for each fiscal quarter ending after the fiscal quarter in which such sale is consummated. On February 2, 2018, we entered into the Second Amendment to our Senior Credit Agreement. The Second Amendment, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending June 30, 2018, September 30, 2018 and December 31, 2018, (ii) an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of 4.50 to 1.00 for the fiscal quarter ending June 30, 2018, and a ratio of 4.00 to 1.00 for any fiscal quarter thereafter, (iii) a waiver of compliance with the covenant relating to the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2018, and (iv) a waiver of the automatic reduction to the borrowing base that would otherwise result due to the issuance of the Additional 2025 Notes.

The basis for these amendment and waiver requests was the potential for us to fall out of compliance as a result of our strategic decisions. Over the longer term, we expect that our strategy and

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our investments will result in increased production and reserves, lower lease operating costs and more abundant drilling opportunities. Shorter term, however, our strategy makes us more susceptible to fluctuations in performance and compliance with these covenants more challenging. Even relatively modest changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can cause our EBITDA to change significantly, particularly in those quarters where it is annualized, and affect our ability to comply with the covenants under our Senior Credit Agreement. The Consent and the Fifth Amendment were intended to provide us with the covenant relief we believe is adequate under our currently projected business plan; however, as stated previously, even relatively modest variations from the assumptions underlying our business plan may cause significant changes to our EBITDA and/or our debt level, which could cause us to fall out of compliance with our covenants. As a consequence, we constantly monitor our liquidity and capital resources, anticipate and identify potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time. While we have been successful to date in obtaining modifications of our covenants as needed, there can be no assurance that we will be successful in the future. After giving effect to the Consent and the Fifth Amendment, at September 30, 2018, we were in compliance with the financial covenants under the Senior Credit Agreement.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and the capital markets and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes.

We strive to maintain financial flexibility while pursuing our drilling plans and evaluating potential acquisitions, and will therefore likely continue to access capital markets (if on acceptable terms) as necessary to, among other things, maintain adequate borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects while sustaining sufficient operating cash levels. Our ability to complete future debt and equity offerings and maintain or increase our borrowing base under our Senior Credit Agreement is subject to a number of variables, including our level of oil and natural gas production, 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 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.

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

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

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significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

Cash Flow

Our primary sources of cash and cash equivalents for the nine months ended September 30, 2018 and 2017 were from operating and financing activities. In the first nine months of 2018, cash generated by financing activities was used to fund the acquisitions of the Northern Tract of the Ward County Assets and the West Quito Draw Properties, 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):

	Nine Months Ended September 30,

	2018			2017
Cash flows provided by (used in) operating activities	$	36,709		$	102,222
Cash flows provided by (used in) investing activities		(778,127	)		737,760
Cash flows provided by (used in) financing activities		317,484			149,341

Net increase (decrease) in cash and cash equivalents	$	(423,934	)	$	989,323

Operating Activities. Net cash flows provided by operating activities for the nine months ended September 30, 2018 were $36.7 million compared to net cash flows provided by operating activities of $102.2 million for the nine months ended September 30, 2017. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs.

Operating cash flows for the nine months ended September 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 nine months ended September 30, 2018.

The $102.2 million of operating cash flows for the nine months ended September 30, 2017 were lower than the prior year period primarily due to a decrease in realized settlements on our derivative contracts. This decrease was partially offset by the impact of increased commodity prices, which served to increase our realized operating revenues, as well as decreases in cash paid for interest and general and administrative expenses.

Investing Activities. Net cash flows used in investing activities for the nine months ended September 30, 2018 was approximately $778.1 million compared to net cash flows provided by investing activities of $737.8 million for the nine months ended September 30, 2017.

During the first nine months of 2018, we incurred cash expenditures of $333.5 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 $369.3 million on oil and natural gas capital expenditures, of which $342.8 million related to drilling and completion costs. We also spent approximately $79.4 million on capital expenditures related to our other operating property and equipment, primarily to develop our water recycling facilities and gas gathering and treating infrastructure.

During the first nine months of 2017, we incurred cash expenditures of $700.1 million to acquire acreage and related assets in the Hackberry Draw area of the Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets) of which $674.6 million related to the oil and natural gas properties and $25.5 million related to the other operating property and equipment. In

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addition to the acquisition of the Pecos County Assets, we spent $242.1 million on other acquisitions, primarily in the Delaware Basin to increase our position in the area. We spent $218.9 million on oil and natural gas capital expenditures, of which $206.1 million related to drilling and completion costs. These cash outflows for acquisitions and our drilling and completion activities were more than offset by cash inflows from our non-core asset sales. Approximately $1.39 billion of the proceeds from the Williston Divestiture were allocated to the oil and natural gas properties divested and $10.9 million of the proceeds were allocated to the other operating property and equipment divested. Proceeds from the El Halcón Divestiture were $494.3 million of which $484.1 million related to the oil and natural gas properties divested and $10.2 million related to the other operating property and equipment divested.

Financing Activities. Net cash flows provided by financing activities for the nine months ended September 30, 2018 were approximately $317.5 million compared to net cash flows provided by financing activities of $149.3 million for the nine months ended September 30, 2017.

During the first nine 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 initial purchasers' premiums and deducting 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.

During the first nine months of 2017, we issued $850.0 million aggregate principal amount of our new 6.75% senior unsecured notes due 2025. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers' discounts and commissions and offering expenses. We utilized the majority of the net proceeds from the private placement to fund the repurchase and redemption of the then outstanding 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes). The net cash to make these repurchases and redemptions was approximately $736.8 million and we recognized a loss on the extinguishment of debt, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes. During the first nine months of 2017, we utilized a portion of the proceeds from the Williston Divestiture to redeem all of the then outstanding 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes). The net cash used to make the redemption was approximately $137.8 million and we recognized a loss on the extinguishment of debt, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the notes. We also paid a consent fee of approximately $16.9 million to the holders of our 2025 Notes. Additionally, we issued 5,518 shares of preferred stock at $72,500 per share. Gross proceeds from this issuance were approximately $400.1 million.

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Contractual Obligations

The following summarizes our contractual obligations and commitments by payment periods as of September 30, 2018 (in thousands):

	Payments Due by Period

Contractual Obligations	Total		Remaining period in 2018		Years 2019 - 2020		Years 2021 - 2022		Years 2023 and Beyond
Senior revolving credit facility	$	55,000	$	—	$	—	$	55,000	$	—
6.75% senior notes due 2025⁽¹⁾		625,005		—		—		—		625,005
Interest expense on long-term debt⁽²⁾		286,263		11,655		93,236		91,840		89,532
Operating leases		9,324		846		4,801		2,332		1,345
Drilling rig commitments⁽³⁾		9,145		4,419		4,726		—		—
Rig termination commitments		3,000		—		3,000		—		—

Total contractual obligations	$	987,737	$	16,920	$	105,763	$	149,172	$	715,882

(1): Amount excludes a $7.4 million unamortized discount, a $5.6 million unamortized premium, and $10.4 million unamortized debt issuance costs.
(2): Future interest expense was calculated based on interest rates and amounts outstanding at September 30, 2018 less required annual repayments.
(3): Early termination of our drilling rig commitments would result in termination penalties approximating $8.2 million, which would be in lieu of paying the remaining active commitments of approximately $9.1 million.

We lease corporate office space in Houston, Texas and Denver, Colorado. Rent expense was approximately $2.8 million and $3.0 million for the nine months ended September 30, 2018 and 2017, respectively. Future obligations associated with our operating leases are presented in the table above.

In September 2018, we entered into a purchase agreement for certain natural gas treating equipment totaling approximately $13.3 million. As of September 30, 2018, our remaining commitment is approximately $9.8 million and is expected to be incurred by March 31, 2019. This purchase commitment is not included in the table above.

We have entered into various long-term gathering, transportation and sales contracts with respect to production from the Delaware Basin in West Texas. As of September 30, 2018, we had in place three long-term crude oil contracts and eleven long-term natural gas contracts in this area, with sales prices based on posted market rates. Under the terms of these contracts, we have committed a substantial portion of our production from this area for periods ranging from one to twenty years from the date of first production.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

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Results of Operations

Three Months Ended September 30, 2018 and 2017

We reported a net loss of $81.8 million and net income of $419.3 million for the three months ended September 30, 2018 and 2017, respectively. The table included below sets forth financial information for the periods presented.

	Three Months Ended September 30,

In thousands (except per unit and per Boe amounts)	2018			2017			Change
Net income (loss)	$	(81,837	)	$	419,287		$	(501,124	)
Operating revenues:
Oil		53,918			88,256			(34,338	)
Natural gas		1,407			2,886			(1,479	)
Natural gas liquids		5,920			5,448			472
Other		350			363			(13	)
Operating expenses:
Production:
Lease operating		5,275			17,798			(12,523	)
Workover and other		1,478			3,644			(2,166	)
Taxes other than income		3,557			6,846			(3,289	)
Gathering and other		18,404			10,886			7,518
Restructuring		—			1,275			(1,275	)
General and administrative:
General and administrative		15,308			26,937			(11,629	)
Stock-based compensation		4,423			12,258			(7,835	)
Depletion, depreciation and accretion:
Depletion—Full cost		18,170			34,336			(16,166	)
Depreciation—Other		2,046			1,230			816
Accretion expense		94			374			(280	)
(Gain) loss on sale of oil and natural gas properties		1,331			(491,830	)		493,161
Other income (expenses):
Net gain (loss) on derivative contracts		(60,406	)		(22,415	)		(37,991	)
Interest expense and other		(12,940	)		(19,330	)		6,390
Gain (loss) on extinguishment of debt		—			(29,167	)		29,167
Income tax benefit (provision)		—			17,000			(17,000	)
Production:
Oil—MBbls		980			2,007			(1,027	)
Natural Gas—Mmcf		1,040			1,874			(834	)
Natural gas liquids—MBbls		190			335			(145	)
Total MBoe⁽¹⁾		1,344			2,655			(1,311	)
Average daily production—Boe/d⁽¹⁾		14,609			28,859			(14,250	)
*Average price per unit⁽²⁾***:
Oil price—Bbl	$	55.02		$	43.97		$	11.05
Natural gas price—Mcf		1.35			1.54			(0.19	)
Natural gas liquids price—Bbl		31.16			16.26			14.90
Total per Boe⁽¹⁾		45.57			36.38			9.19
Average cost per Boe:
Production:
Lease operating	$	3.92		$	6.70		$	(2.78	)
Workover and other		1.10			1.37			(0.27	)
Taxes other than income		2.65			2.58			0.07
Gathering and other		13.69			4.10			9.59
Restructuring		—			0.48			(0.48	)
General and administrative:
General and administrative		11.39			10.15			1.24
Stock-based compensation		3.29			4.62			(1.33	)
Depletion		13.52			12.93			0.59

(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 $61.2 million and $96.6 million for three months ended September 30, 2018 and 2017, respectively. For the three months ended September 30, 2018 and 2017, production averaged 14,609 Boe/d and 28,859 Boe/d, respectively. Our average daily oil and natural gas production decreased in the three months ended September 30, 2018 when compared to the same period in the prior year due to our divestitures in 2017. This decrease was partially mitigated by the production associated with our Delaware Basin assets and our drilling activities since acquiring the assets. Average realized prices (excluding the effects of hedging arrangements) were $45.57 per Boe and $36.38 per Boe for the three months ended September 30, 2018 and 2017, respectively. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors.

Lease operating expenses were $5.3 million and $17.8 million for the three months ended September 30, 2018 and 2017, respectively. On a per unit basis, lease operating expenses were $3.92 per Boe and $6.70 per Boe for the three months ended September 30, 2018 and 2017, respectively. The decrease in lease operating expenses from the prior year period is primarily attributed to our El Halcón and Williston Divestitures in 2017 which greatly reduced our inventory of producing wells.

Workover and other expenses were $1.5 million and $3.6 million for the three months ended September 30, 2018 and 2017, respectively. On a per unit basis, workover and other expenses were $1.10 per Boe and $1.37 per Boe for the three months ended September 30, 2018 and 2017, respectively.

Taxes other than income were $3.6 million and $6.8 million for the three months ended September 30, 2018 and 2017, 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 $2.65 per Boe and $2.58 per Boe for the three months ended September 30, 2018 and 2017, respectively.

Gathering and other expenses were $18.4 million and $10.9 million for the three months ended September 30, 2018 and 2017, respectively. Gathering and other expenses include gathering fees paid on our oil and natural gas production, operating expenses on our water recycling facilities and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $1.4 million and $7.6 million of expenses incurred for the three months ended September 30, 2018 and 2017, respectively, relate to gathering and marketing fees paid on our oil and natural gas production. Approximately $17.4 million and $2.0 million of expenses for the three months ended September 30, 2018 and 2017, respectively, relate to operating expenses on our water recycling facilities and gas gathering infrastructure. Included in the current period is approximately $13.7 million of costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties as a consequence of a third party pipeline temporarily going out of service. We have secured capacity on another third party pipeline for a portion of the natural gas produced in this area and are progressing on solutions for the remaining natural gas produced, including the purchase of treating equipment which will alleviate reliance upon third party services for the removal of hydrogen sulfide from the natural gas produced. Therefore, we currently expect higher treating costs to continue into the fourth quarter of 2018, but to decrease slightly from the costs incurred in the third quarter of 2018 before decreasing substantially in early 2019. Also included are $0.9 million and $1.3 million of rig stacking charges for the three months ended September 30, 2018 and 2017, respectively.

Restructuring expense was zero and $1.3 million during the three months ended September 30, 2018 and 2017, respectively. The costs incurred in 2017 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 $15.3 million and $26.9 million for the three months ended September 30, 2018 and 2017, respectively. In the prior year period, we incurred approximately $8.4 million of transaction costs paid in conjunction with the Williston Divestiture. On a per unit basis, general and administrative expenses were $11.39 per Boe and $10.15 per Boe for the three months ended September 30, 2018 and 2017, respectively. General and administrative expense on a per Boe basis increased in the current period due to a decrease in our average daily production primarily as a result of our 2017 divestitures.

Stock-based compensation expense was $4.4 million and $12.3 million for the three months ended September 30, 2018 and 2017, respectively. Stock-based compensation expense decreased in the current period due to a reduction in our workforce and restricted stock granted in connection with our emergence from chapter 11 bankruptcy which vested on or before September 30, 2017.

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 $18.2 million and $34.3 million for the three months ended September 30, 2018 and 2017, respectively. On a per unit basis, depletion expense was $13.52 per Boe and $12.93 per Boe for the three months ended September 30, 2018 and 2017, respectively. The increase in the depletion rate per Boe from 2017 levels is primarily attributable to our shift in operations to the Delaware Basin.

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. Accordingly, we initially recognized a gain on the sale of the oil and natural gas properties associated with the Williston Divestiture of $491.8 million during the three months ended September 30, 2017. We reduced the gain on the sale of the oil and natural gas properties associated with the Williston Divestiture by approximately $1.3 million during the three months ended September 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.

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 record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2018, we had an $19.3 million derivative asset, $16.6 million of which was classified as current and we had a $123.6 million derivative liability, $86.2 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $60.4 million ($50.8 million net unrealized loss and a $9.6 million net realized loss on settled contracts) for the three months ended September 30, 2018 compared to a net derivative loss of $22.4 million ($31.2 million net unrealized loss and $8.8 million net realized gain on settled contracts), in the same period in 2017.

Interest expense and other was $12.9 million and $19.3 million for the three months ended September 30, 2018 and 2017, respectively. We utilized a portion of the proceeds from our divestitures in 2017 to repurchase outstanding long-term debt, which drove a decrease in interest expense in the three months ended September 30, 2018 when compared to the same period in the prior year. This decrease was partially offset by interest expense on the Additional 2025 Notes which were issued in February 2018.

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On September 7, 2017, we issued an irrevocable notice to redeem the outstanding aggregate principal amount of our 2022 Second Lien Notes on October 7, 2017. On September 7, 2017, utilizing $137.8 million of the proceeds from the Williston Divestiture, we deposited with U.S. Bank National Association an amount of funds sufficient to fund the redemption, delivered instructions to apply the deposited funds toward the redemption, and received a written acknowledgment from U.S. Bank National Association of the satisfaction and discharge of the indenture governing the 2022 Second Lien Notes and the obligations of us and our subsidiary guarantors under the 2022 Second Lien Notes and related guarantees. We recognized a $29.2 million loss on the extinguishment of debt, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the notes.

For the three months ended September 30, 2017, we recorded an income tax benefit of $17.0 million resulting from the reversal of the $12.0 million alternative minimum tax generated primarily by the sale of the El Halcón Assets combined with the reversal of the $5.0 million alternative minimum tax liability recorded in 2016.

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Nine Months Ended September 30, 2018 and 2017

We reported a net loss of $100.7 million and net income of $628.8 million for the nine months ended September 30, 2018 and 2017, respectively. The table included below sets forth financial information for the periods presented.

	Nine Months Ended September 30,

In thousands (except per unit and per Boe amounts)	2018			2017			Change
Net income (loss)	$	(100,709	)	$	628,816		$	(729,525	)
Operating revenues:
Oil		145,743			319,472			(173,729	)
Natural gas		5,286			15,051			(9,765	)
Natural gas liquids		14,623			16,779			(2,156	)
Other		613			1,386			(773	)
Operating expenses:
Production:
Lease operating		15,504			58,822			(43,318	)
Workover and other		4,795			22,213			(17,418	)
Taxes other than income		9,812			29,149			(19,337	)
Gathering and other		30,782			34,640			(3,858	)
Restructuring		128			2,080			(1,952	)
General and administrative:
General and administrative		36,955			53,418			(16,463	)
Stock-based compensation		12,241			33,548			(21,307	)
Depletion, depreciation and accretion:
Depletion—Full cost		46,920			96,141			(49,221	)
Depreciation—Other		5,252			3,417			1,835
Accretion expense		225			1,230			(1,005	)
(Gain) loss on sale of oil and natural gas properties		7,235			(727,520	)		734,755
Other income (expenses):
Net gain (loss) on derivative contracts		(66,603	)		28,139			(94,742	)
Interest expense and other		(30,522	)		(63,808	)		33,286
Gain (loss) on extinguishment of debt		—			(86,065	)		86,065
Income tax benefit (provision)		—			5,000			(5,000	)
Production:
Oil—MBbls		2,468			7,108			(4,640	)
Natural Gas—Mmcf		3,009			6,892			(3,883	)
Natural gas liquids—MBbls		523			1,165			(642	)
Total MBoe⁽¹⁾		3,493			9,422			(5,929	)
Average daily production—Boe⁽¹⁾		12,795			34,513			(21,718	)
*Average price per unit(2)***:
Oil price—Bbl	$	59.05		$	44.95		$	14.10
Natural gas price—Mcf		1.76			2.18			(0.42	)
Natural gas liquids price—Bbl		27.96			14.40			13.56
Total per Boe⁽¹⁾		47.42			37.29			10.13
Average cost per Boe:
Production:
Lease operating	$	4.44		$	6.24		$	(1.80	)
Workover and other		1.37			2.36			(0.99	)
Taxes other than income		2.81			3.09			(0.28	)
Gathering and other		8.81			3.68			5.13
Restructuring		0.04			0.22			(0.18	)
General and administrative:
General and administrative		10.58			5.67			4.91
Stock-based compensation		3.50			3.56			(0.06	)
Depletion		13.43			10.20			3.23

(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 $165.7 million and $351.3 million for the nine months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018 and 2017, production averaged 12,795 Boe/d and 34,513 Boe/d, respectively. Our average daily oil and natural gas production decreased in the nine months ended September 30, 2018 when compared to the same period in the prior year due to our divestitures in 2017. This decrease was partially mitigated by the production associated with our Delaware Basin assets and our drilling activities since acquiring the assets. Average realized prices (excluding the effects of hedging arrangements) were $47.42 per Boe and $37.29 per Boe for the nine months ended September 30, 2018 and 2017, respectively. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors.

Lease operating expenses were $15.5 million and $58.8 million for the nine months ended September 30, 2018 and 2017, respectively. On a per unit basis, lease operating expenses were $4.44 per Boe and $6.24 per Boe for the nine months ended September 30, 2018 and 2017, respectively. The decrease in lease operating expense from 2017 levels is primarily attributed to our El Halcón and Williston Divestitures in 2017 which greatly reduced our inventory of producing wells.

Workover and other expenses were $4.8 million and $22.2 million for the nine months ended September 30, 2018 and 2017, respectively. On a per unit basis, workover and other expenses were $1.37 per Boe and $2.36 per Boe for the nine months ended September 30, 2018 and 2017, respectively.

Taxes other than income were $9.8 million and $29.1 million for the nine months ended September 30, 2018 and 2017, 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 $2.81 per Boe and $3.09 per Boe for the nine months ended September 30, 2018 and 2017, respectively.

Gathering and other expenses were $30.8 million and $34.6 million for the nine months ended September 30, 2018 and 2017, respectively. Gathering and other expenses include gathering fees paid on our oil and natural gas production, operating expenses on our water recycling facilities and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $3.8 million and $25.6 million for the nine months ended September 30, 2018 and 2017, respectively, relate to gathering and marketing fees paid on our oil and natural gas production. Approximately $26.2 million and $3.1 million expenses for the nine months ended September 30, 2018 and 2017, respectively, relate to operating expenses on our water recycling facilities and gas gathering infrastructure. Included in the current period is approximately $14.0 million of costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties as a consequence of a third party pipeline temporarily going out of service. We have secured capacity on another third party pipeline for a portion of the natural gas produced in this area and are progressing on solutions for the remaining natural gas produced, including the purchase of treating equipment which will alleviate reliance upon third party services for the removal of hydrogen sulfide from the natural gas produced. Therefore, we currently expect higher treating costs to continue into the fourth quarter of 2018, but to decrease slightly from the costs incurred in the third quarter of 2018 before decreasing substantially in early 2019. Also included are $1.9 million and $5.9 million of rig stacking charges for the nine months ended September 30, 2018 and 2017, respectively.

Restructuring expense was approximately $0.1 million and $2.1 million during the nine months ended September 30, 2018 and 2017, respectively. This represents 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 $37.0 million and $53.4 million for the nine months ended September 30, 2018 and 2017, respectively. In the prior year period, we incurred approximately $8.4 million of transaction costs paid in conjunction with the Williston Divestiture. On a per unit basis, general and administrative expenses were $10.58 per Boe and $5.67 per Boe for the nine months ended September 30, 2018 and 2017, respectively. General and administrative expense on a per Boe basis increased in the current period due to a decrease in our average daily production primarily as a result of our 2017 divestitures.

Stock-based compensation expense was $12.2 million and $33.5 million for the nine months ended September 30, 2018 and 2017, respectively. Stock-based compensation expense decreased in the current period due to a reduction in our workforce and restricted stock granted in connection with our emergence from chapter 11 bankruptcy which vested on or before September 30, 2017.

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 $46.9 million and $96.1 million for the nine months ended September 30, 2018 and 2017, respectively. On a per unit basis, depletion expense was $13.43 per Boe and $10.20 per Boe for the nine months ended September 30, 2018 and 2017, respectively. The increase in the depletion rate per Boe from 2017 levels is primarily attributable to our shift in operations to the Delaware Basin.

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 El Halcón and Williston Divestitures were 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, we recognized a gain on the sale of the oil and natural gas properties associated with the El Halcón Divestiture of $235.7 million during the nine months ended September 30, 2017. We also recognized an initial gain on the sale of the Williston Divestiture of $491.8 million during the nine months ended September 30, 2017. We reduced the gain on the sale of the oil and natural gas properties associated with the Williston Divestiture by approximately $7.2 million during the nine months ended September 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.

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 record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2018, we had an $19.3 million derivative asset, $16.6 million of which was classified as current and we had a $123.6 million derivative liability, $86.2 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $66.6 million ($77.5 million net unrealized loss and $10.9 million net realized gain on settled and early terminated contracts) for the nine months ended September 30, 2018 compared to a net derivative gain of $28.1 million ($11.0 million net unrealized gain and $17.1 million net realized gain on settled contracts), in the same period in 2017.

Interest expense and other was $30.5 million and $63.8 million for the nine months ended September 30, 2018 and 2017, respectively. We utilized a portion of the proceeds from our divestitures in 2017 to repurchase outstanding long-term debt, which drove a decrease in interest expense in the nine months ended September 30, 2018 when compared to the same period in the prior year. This

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decrease was partially offset by interest expense on the Additional 2025 Notes which were issued in February 2018.

We recorded an income tax benefit of $5.0 million for the nine months ended September 30, 2017 resulting from the reversal of our estimated 2016 alternative minimum tax liability.

Recently Issued Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable; therefore, we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and 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 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 financial institutions deemed by management as competitive market makers. We did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 7, "Derivative and Hedging Activities," for additional information.

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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 6, "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 September 30, 2018, the principal amount of our debt was $680.0 million, of which approximately 92% bears interest at a weighted average fixed interest rate of 6.75% per year. The remaining 8% of our total debt at September 30, 2018 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 September 30, 2018, the weighted average interest rate on our variable rate debt was 6.75% per year. If the balance of our variable interest rate at September 30, 2018 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $0.4 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 September 30, 2018. 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 September 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Under rules promulgated by the SEC, administrative or judicial proceedings arising under any federal, state or local provisions that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment are disclosed if the governmental authority is party to such proceeding and the proceeding involves potential monetary sanctions of $100,000 or more. We are not party to any such proceedings, except as described below.

On September 17, 2018, the United States Environmental Protection Agency (EPA) approved a Consent Agreement entered into among us, one of our subsidiaries and the EPA (Region 8), resolving alleged failures by us to minimize leakage of natural gas emissions into the atmosphere as required by EPA regulations at certain oil and natural gas wells located in Fort Berthold, North Dakota. We sold all of the wells subject to the Consent Agreement, together with our other operated properties in North Dakota, in September 2017. The EPA provided us with notice of the alleged violations in January 2018, which we promptly contested. In entering into the Consent Agreement, neither we nor our subsidiary admitted the facts or violations alleged by the EPA. Pursuant to the terms of the Consent Agreement, we paid a civil penalty of $110,000 to the EPA in September 2018.

Item 1A. Risk Factors

There have been no changes to the risk factors described in our Annual Report on Form 10-K, for the fiscal year ended December 31, 2017, except as described below.

We could experience periods of higher costs for various reasons, including due to higher commodity prices, increased drilling activity in the Delaware Basin and trade disputes that affect the costs of steel and other raw materials that we and our vendors rely upon, which could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and periods of increasing oil, natural gas and natural gas liquids prices may result in shortages of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production, particularly in the Delaware Basin, may increase demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. Cost increases may also result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other materials that we and our vendors rely upon and increases in the cost of services to process, treat and transport our production. Recently, for instance, the President exercised his authority to impose significant tariffs on imports of steel and aluminum from a number of countries. Steel is extensively used by us and those in oil and gas industry generally, including for such items as tubulars, flanges, fittings and tanks, among many other items. As a result of the imposition of such tariffs, we will pay significantly more for most or all of these items in the near term. Any escalation or expansion of tariffs could result in higher costs and affect a greater range of materials we rely upon in our business. The unavailability or high cost of drilling rigs, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and

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profitability. In order to secure drilling rigs and pressure pumping equipment and related services, we may enter into certain contracts that extend over several months or years. If demand for drilling rigs and pressure pumping equipment subside during the period covered by these contracts, the price we are required to pay may be significantly more than the market rate for similar services.

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

None.

Item 3. Defaults Upon Senior Securities

None.

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	*	Asset Purchase Agreement, dated October 31, 2018, by and among Halcón Field Services, LLC, Halcón Operating Co., Inc., Halcón Energy Properties, Inc. and Water Bridge Texas Midstream LLC.
3.1		Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated September 9, 2016 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed September 9, 2016).
3.2		Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed May 7, 2015).
3.2.1		Amendment No. 1 to the Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed September 9, 2016).
10.1		Amended and Restated Senior Secured Revolving Credit Agreement, dated as of September 7, 2017, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 11, 2017).
10.1.1		Second Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of February 2, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed February 8, 2018).

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10.1.2		Third Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 1, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1.2 of our Quarterly Report on Form 10-Q filed May 2, 2018).
10.1.3		Fourth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of July 12, 2018, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 17, 2018).
12.1	*	Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
31.1	*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer
31.2	*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer
32	*	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
101.INS	*	XBRL Instance Document
101.SCH	*	XBRL Taxonomy Extension Schema Document
101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	*	XBRL Taxonomy Extension Definition Document
101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document

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

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SIGNATURES

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


	HALCÓN RESOURCES CORPORATION
November 7, 2018	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board, Chief Executive Officer and President
November 7, 2018	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer