BATTALION OIL CORP - Quarter Report: 2017 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, 2017
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number: 001-35467

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


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

1000 Louisiana Street, Suite 6700, Houston, TX 77002
(Address of principal executive offices)

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company ý 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 6, 2017, 149,596,067 shares of the Registrant's Common Stock were outstanding.

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PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Stockholders' Equity	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Unaudited Condensed Consolidated Financial Statements	10
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	49
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	70
ITEM 4.	Controls and Procedures	71
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	72
ITEM 1A.	Risk Factors	72
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	72
ITEM 3.	Defaults Upon Senior Securities	73
ITEM 4.	Mine Safety Disclosures	73
ITEM 5.	Other Information	73
ITEM 6.	Exhibits	73
Signatures		75

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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, including, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, or financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2016, and Quarterly Report on Form 10-Q for the quarter ended June 30, 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 and natural gas;
•: 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 position;
•: our ability to replace our oil and natural gas reserves and production;
•: the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management's time and energy;
•: 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 and the actual future production rates and associated costs;
•: our ability to successfully develop our large inventory of undeveloped acreage in our resource play;
•: 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 facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices;
•: contractual limitations that affect our management's discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;
•: the potential for production decline rates for our wells to be greater than we expect;
•: competition, including competition for acreage in our resource play;

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•: 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;
•: the insurance coverage maintained by us may not adequately cover all losses that we may sustain;
•: title to the properties in which we have an interest may be impaired by title defects;
•: senior management's ability to execute our plans to meet our goals;
•: the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars; and
•: our dependency on the skill, ability and decisions of third party operators of the oil and natural gas properties in which we have a non-operated working interest.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Successor						Predecessor

	Three Months Ended September 30, 2017			Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	88,256		$	21,260		$	74,002
Natural gas		2,886			823			2,610
Natural gas liquids		5,448			798			2,488

Total oil, natural gas and natural gas liquids sales		96,590			22,881			79,100
Other		363			226			247

Total operating revenues		96,953			23,107			79,347

Operating expenses:
Production:
Lease operating		17,798			3,791			12,473
Workover and other		3,644			1,565			6,801
Taxes other than income		6,846			2,173			7,442
Gathering and other		10,886			2,637			7,376
Restructuring		1,275			—			95
General and administrative		39,195			16,681			17,317
Depletion, depreciation and accretion		35,940			9,051			25,618
Full cost ceiling impairment		—			420,934			—
(Gain) loss on sale of oil and natural gas properties		(491,830	)		—			—

Total operating expenses		(376,246	)		456,832			77,122

Income (loss) from operations		473,199			(433,725	)		2,225
Other income (expenses):
Net gain (loss) on derivative contracts		(22,415	)		(7,575	)		17,783
Interest expense and other, net		(19,330	)		(5,479	)		(16,136	)
Reorganization items		—			(556	)		913,722
Gain (loss) on extinguishment of debt		(29,167	)		—			—

Total other income (expenses)		(70,912	)		(13,610	)		915,369

Income (loss) before income taxes		402,287			(447,335	)		917,594
Income tax benefit (provision)		17,000			(3,357	)		8,666

Net income (loss)		419,287			(450,692	)		926,260
Series A preferred dividends		—			—			(2,451	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			(791	)		(7,388	)

Net income (loss) available to common stockholders	$	419,287		$	(451,483	)	$	916,421



Net income (loss) per share of common stock:
Basic	$	2.85		$	(4.96	)	$	7.58



Diluted	$	2.82		$	(4.96	)	$	6.06



Weighted average common shares outstanding:
Basic		146,944			91,071			120,905



Diluted		148,490			91,071			151,876

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 OPERATIONS (Unaudited) (Continued)

(In thousands, except per share amounts)

	Successor						Predecessor

	Nine Months Ended September 30, 2017			Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	319,472		$	21,260		$	248,064
Natural gas		15,051			823			9,511
Natural gas liquids		16,779			798			7,929

Total oil, natural gas and natural gas liquids sales		351,302			22,881			265,504
Other		1,386			226			1,339

Total operating revenues		352,688			23,107			266,843

Operating expenses:
Production:
Lease operating		58,822			3,791			50,032
Workover and other		22,213			1,565			22,507
Taxes other than income		29,149			2,173			24,453
Gathering and other		34,640			2,637			29,279
Restructuring		2,080			—			5,168
General and administrative		86,966			16,681			83,641
Depletion, depreciation and accretion		100,788			9,051			120,555
Full cost ceiling impairment		—			420,934			754,769
(Gain) loss on sale of oil and natural gas properties		(727,520	)		—			—
Other operating property and equipment impairment		—			—			28,056

Total operating expenses		(392,862	)		456,832			1,118,460

Income (loss) from operations		745,550			(433,725	)		(851,617	)
Other income (expenses):
Net gain (loss) on derivative contracts		28,139			(7,575	)		(17,998	)
Interest expense and other, net		(63,808	)		(5,479	)		(122,249	)
Reorganization items		—			(556	)		913,722
Gain (loss) on extinguishment of debt		(86,065	)		—			81,434

Total other income (expenses)		(121,734	)		(13,610	)		854,909

Income (loss) before income taxes		623,816			(447,335	)		3,292
Income tax benefit (provision)		5,000			(3,357	)		8,666

Net income (loss)		628,816			(450,692	)		11,958
Non-cash preferred dividend		(48,007	)		—			—
Series A preferred dividends		—			—			(8,847	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			(791	)		(35,905	)

Net income (loss) available to common stockholders	$	580,809		$	(451,483	)	$	(32,794	)



Net income (loss) per share of common stock:
Basic	$	4.56		$	(4.96	)	$	(0.27	)



Diluted	$	4.52		$	(4.96	)	$	(0.27	)



Weighted average common shares outstanding:
Basic		127,458			91,071			120,513



Diluted		128,410			91,071			120,513

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)

	Successor

	September 30, 2017			December 31, 2016
Current assets:
Cash	$	989,347		$	24
Accounts receivable		108,753			147,762
Receivables from derivative contracts		5,166			5,923
Prepaids and other		12,171			6,940

Total current assets		1,115,437			160,649

Oil and natural gas properties (full cost method):
Evaluated		782,695			1,269,034
Unevaluated		757,401			316,439

Gross oil and natural gas properties		1,540,096			1,585,473
Less—accumulated depletion		(561,989	)		(465,849	)

Net oil and natural gas properties		978,107			1,119,624

Other operating property and equipment:
Other operating property and equipment		68,195			38,617
Less—accumulated depreciation		(2,967	)		(1,107	)

Net other operating property and equipment		65,228			37,510

Other noncurrent assets:
Receivables from derivative contracts		1,444			—
Funds in escrow and other		2,408			1,887

Total assets	$	2,162,624		$	1,319,670



Current liabilities:
Accounts payable and accrued liabilities	$	172,012		$	186,184
Liabilities from derivative contracts		3,279			16,434
Current portion of long-term debt, net		408,879			—
Other		8			4,935

Total current liabilities		584,178			207,553

Long-term debt, net		408,879			964,653
Other noncurrent liabilities:
Liabilities from derivative contracts		2,175			486
Asset retirement obligations		5,116			31,985
Other		288			2,305
Commitments and contingencies (Note 10)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized;
149,665,527 and 92,991,183 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively		15			9
Additional paid-in capital		1,013,141			592,663
Retained earnings (accumulated deficit)		148,832			(479,984	)

Total stockholders' equity		1,161,988			112,688

Total liabilities and stockholders' equity	$	2,162,624		$	1,319,670

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Preferred Stock					Common Stock									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, 2015 (Predecessor)		245		$	—		122,524		$	12		$	3,283,097		$	(3,230,695	)	$	52,414
Net income (loss)		—			—		—			—			—			11,958			11,958
Conversion of Series A preferred stock		(23	)		—		724			—			—			—			—
Preferred dividends on redeemable noncontrolling interest		—			—		—			—			—			(9,329	)		(9,329	)
Accretion of redeemable noncontrolling interest		—			—		—			—			—			(26,576	)		(26,576	)
Fair value of equity issued to Predecessor common stockholders		—			—		—			—			(22,176	)		—			(22,176	)
Cash payment to Preferred Holders		—			—		—			—			(11,100	)		—			(11,100	)
Reverse stock split rounding		—			—		5			—			—						—
Offering costs		—			—		—			—			(10	)		—			(10	)
Long-term incentive plan forfeitures		—			—		(517	)		—			—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(498	)		—			(176	)		—			(176	)
Share-based compensation		—			—		—			—			4,995			—			4,995

Balances at September 9, 2016 (Predecessor)		222		$	—		122,238		$	12		$	3,254,630			(3,254,642	)	$	—



Cancellation of Predecessor equity		(222	)	$	—		(122,238	)	$	(12	)	$	(3,254,630	)	$	3,254,642		$	—

Balances at September 9, 2016 (Predecessor)		—		$	—		—		$	—		$	—		$	—		$	—




Issuance of Successor common stock and warrants		—		$	—		90,000		$	9		$	571,114		$	—		$	571,123
Balances at September 9, 2016 (Successor)		—		$	—		90,000		$	9		$	571,114		$	—		$	571,123
Net income (loss)		—			—		—			—			—			(479,193	)		(479,193	)
Preferred dividends on redeemable noncontrolling interest		—			—		—			—			—			(791	)		(791	)
Long-term incentive plan grants		—			—		2,991			—			—			—			—
Share-based compensation		—			—		—			—			21,549						21,549

Balances at December 31, 2016 (Successor)		—		$	—		92,991		$	9		$	592,663		$	(479,984	)	$	112,688



Net income (loss)		—			—		—			—			—			628,816			628,816
Sale of convertible preferred stock		6			—		—			—			352,048			—			352,048
Preferred beneficial conversion feature		—			—		—			—			48,007			—			48,007
Conversion of preferred stock		(6	)		—		55,180			6			(6	)		—			—
Offering costs		—			—		—			—			(11,919	)		—			(11,919	)
Long-term incentive plan grants		—			—		2,022			—			—			—			—
Long-term incentive plan forfeitures		—			—		(232	)		—			—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(295	)		—			(1,845	)		—			(1,845	)
Share-based compensation		—			—		—			—			34,193			—			34,193

Balances at September 30, 2017 (Successor)		—		$	—		149,666		$	15		$	1,013,141		$	148,832		$	1,161,988

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)

	Successor						Predecessor

				Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
	Nine Months Ended September 30, 2017


Cash flows from operating activities:
Net income (loss)	$	628,816		$	(450,692	)	$	11,958
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		100,788			9,051			120,555
Full cost ceiling impairment		—			420,934			754,769
(Gain) loss on sale of oil and natural gas properties		(727,520	)		—			—
Other operating property and equipment impairment		—			—			28,056
Share-based compensation, net		33,548			13,196			4,876
Unrealized loss (gain) on derivative contracts		(11,010	)		30,338			263,732
Amortization and write-off of deferred loan costs		1,306			—			6,371
Amortization of discount and premium		2,358			377			1,515
Reorganization items		(739	)		560			(929,084	)
Loss (gain) on extinguishment of debt		86,065			—			(81,434	)
Accrued settlements on derivative contracts		(673	)		(22,695	)		—
Other income (expense)		(3,393	)		(94	)		(4,233	)
Change in assets and liabilities:
Accounts receivable		37,950			12,541			47,920
Prepaids and other		(5,231	)		(81	)		(4,329	)
Accounts payable and accrued liabilities		(40,043	)		(1,113	)		(45,324	)

Net cash provided by (used in) operating activities		102,222			12,322			175,348

Cash flows from investing activities:
Oil and natural gas capital expenditures		(218,880	)		(10,289	)		(226,741	)
Proceeds received from sale of oil and natural gas properties		1,901,578			—			(407	)
Acquisition of oil and natural gas properties		(916,676	)		—			124
Acquisition of other operating property and equipment		(25,538	)		—			—
Other operating property and equipment capital expenditures		(25,474	)		(231	)		(950	)
Proceeds received from sale of other operating property and equipment		21,291			—			138
Funds held in escrow and other		1,459			(1,721	)		62

Net cash provided by (used in) investing activities		737,760			(12,241	)		(227,774	)

Cash flows from financing activities:
Proceeds from borrowings		1,349,000			30,000			886,000
Repayments of borrowings		(1,497,826	)		(32,000	)		(727,648	)
Cash payments to Noteholders and Preferred Holders		(70,903	)		(10,013	)		(97,521	)
Debt issuance costs		(17,220	)		—			(1,977	)
Preferred stock issued		400,055			—			—
Offering costs and other		(13,765	)		—			(511	)

Net cash provided by (used in) financing activities		149,341			(12,013	)		58,343

Net increase (decrease) in cash		989,323			(11,932	)		5,917
Cash at beginning of period		24			13,943			8,026

Cash at end of period	$	989,347		$	2,011		$	13,943



Supplemental cash flow information:
Cash paid (received) for reorganization items	$	739		$	(4	)	$	15,362
Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	—		$	—		$	(23,966	)
Asset retirement obligations		(28,481	)		8			939
Accretion of non-cash preferred dividend		48,007			—			—
Preferred dividends on redeemable noncontrolling interest paid-in-kind		—			791			9,329
Accretion of redeemable noncontrolling interest		—			—			26,576
Accrued debt issuance costs		(153	)		—			1,176

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. The Company's oil and natural gas properties are managed as a whole rather than through discrete operating areas. Operational information is tracked by operating area; however, financial performance is assessed as a whole. Allocation of capital is made across the Company's entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company's management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Halcón follows the accounting policies disclosed in its Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC) on March 1, 2017. Please refer to the notes in the 2016 Annual Report on Form 10-K when reviewing interim financial results, though, as described below, such prior financial statements may not be comparable to the interim financial statements due to the adoption of fresh-start accounting on September 9, 2016.

Emergence from Voluntary Reorganization under Chapter 11

On July 27, 2016 (the Petition Date), the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a joint prepackaged plan of reorganization (the Plan). On September 8, 2016, the Bankruptcy Court entered an order confirming the Plan and on September 9, 2016, the Plan became effective (the Effective Date) and the Halcón Entities emerged from chapter 11 bankruptcy. The Company's subsidiary, HK TMS, LLC which was divested on September 30, 2016, was not part of the chapter 11 bankruptcy filings. See Note 2, "Reorganization," for further details on the Company's chapter 11 bankruptcy and the Plan and Note 4, "Acquisitions and Divestitures," for further details on the divestiture of HK TMS, LLC.

Upon emergence from chapter 11 bankruptcy, the Company adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board's (FASB) Accounting Standards Codification (ASC) 852, "Reorganizations" (ASC 852) which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. Upon the adoption of fresh-start accounting, the Company's assets and liabilities were recorded at their fair values as of the fresh-start reporting date. As a result of the adoption of fresh-start accounting, the Company's unaudited condensed consolidated financial statements subsequent to September 9, 2016 are not comparable to its unaudited condensed consolidated financial statements prior to, and including, September 9, 2016. See Note 3, "Fresh-start Accounting," for further details on the impact of fresh-start accounting on the Company's unaudited condensed consolidated financial statements.

References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor"

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

Use of Estimates

The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of Reorganization Value, Enterprise Value and the fair value of assets and liabilities recorded as a result of the adoption of fresh-start accounting, plus the estimated 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 4, "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.

Accounts Receivable and Allowance for Doubtful Accounts

The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. There were no significant allowances for doubtful accounts as of September 30, 2017 (Successor) or December 31, 2016 (Successor).

Other Operating Property and Equipment

Other operating property and equipment were recorded at fair value as a result of fresh-start accounting on September 9, 2016 and additions since that date are recorded at cost. Depreciation is

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

calculated using the straight-line method over the following estimated useful lives: gas gathering systems, thirty years; water disposal and recycling facilities, twenty years; compressed natural gas facility, ten years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years or the lesser of the lease term; trailers, seven years; heavy equipment, eight to ten years; buildings, twenty years and leasehold improvements, lease term. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

Refer to Note 4, "Acquisitions and Divestitures," for a discussion of other operating property and equipment acquired and divested during the period.

The Company reviews its other operating property and equipment for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. For the period from January 1, 2016 through September 9, 2016 (Predecessor), the Company recorded a non-cash impairment charge of $28.1 million in "Other operating property and equipment impairment" in the Company's unaudited condensed consolidated statements of operations and in "Other operating property and equipment" in the Company's unaudited condensed consolidated balance sheets related to $32.8 million gross investments in gas gathering infrastructure that were deemed non-economical due to a shift in exploration, drilling and developmental plans in a low commodity price environment.

In accordance with ASC 820, Fair Value Measurements and Disclosures (ASC 820), a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The estimate of the fair value of the Company's gas gathering infrastructure was based on an income approach that estimated future cash flows associated with those assets over the remaining asset lives. This estimation includes the use of unobservable inputs, such as estimated future production, gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company's gas gathering infrastructure being classified as Level 3.

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

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acquisitions of assets or businesses. The Company is in the process of assessing the effects of the application of the new guidance.

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

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and early adoption is permitted. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity should apply the amendments in this ASU on a modified retrospective basis. The transition will require application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. The Company is in the early stages of assessing the effects of the application of the new guidance and the financial statement and disclosure impacts. The Company will adopt ASU 2016-02 no later than 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), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2017. Early adoption is not permitted. The Company is in the process of assessing its contracts with customers and evaluating the effects of the new guidance on its financial statements and disclosures. This process includes evaluating certain components of its natural gas gathering and processing agreements to determine whether changes to revenues and expenses will be appropriate when complying with the new guidance. The adoption is not expected to have a significant impact on the Company's net income or cash flows from operations. The Company will adopt ASU 2014-09 effective January 1, 2018.

2. REORGANIZATION

On June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company's 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the

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Unsecured Noteholders), the holder of the Company's 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of the Company's 5.75% Series A Convertible Perpetual Preferred Stock. On July 27, 2016, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware to effect an accelerated prepackaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement. On September 8, 2016, the Bankruptcy Court entered an order confirming the Plan and on September 9, 2016, the Halcón Entities emerged from chapter 11 bankruptcy.

Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred:

•: the Predecessor Company's financing facility under the Predecessor Credit Agreement was refinanced and replaced with a debtor-in-possession senior secured, super-priority revolving credit facility, which was subsequently converted into the Senior Credit Agreement (refer to Note 6, "Debt," for further details regarding the Senior Credit Agreement);
•: the Predecessor Company's Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) were unimpaired and reinstated;
•: the Predecessor Company's Third Lien Notes were cancelled and the Third Lien Noteholders received their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016, which interest was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;
•: the Predecessor Company's Unsecured Notes were cancelled and the Unsecured Noteholders received their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), and accrued and unpaid interest on their notes through May 15, 2016, which interest was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;
•: the Predecessor Company's Convertible Note was cancelled and the Convertible Noteholder received 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims;
•: the general unsecured claims were unimpaired and paid in full in the ordinary course;
•: all outstanding shares of the Predecessor Company's Series A Preferred Stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and
•: all of the Predecessor Company's outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests.

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2. REORGANIZATION (Continued)

Each of the foregoing percentages of equity in the reorganized Company were as of September 9, 2016 and are subject to dilution from the exercise of the new warrants described above, a management incentive plan discussed further in Note 11, "Stockholders' Equity," and other future issuances of equity securities.

See Note 6, "Debt," and Note 11, "Stockholders' Equity," for further information regarding the Company's Successor and Predecessor debt and equity instruments.

3. FRESH-START ACCOUNTING

Upon the Company's emergence from chapter 11 bankruptcy, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value of the Company's assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to Note 2, "Reorganization," for the terms of the Plan. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as "Successor" or "Successor Company." However, the Company will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor companies may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the application of fresh-start accounting, the Company allocated the Reorganization Value (the fair value of the Successor Company's total assets) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would value the Company's assets immediately after the reorganization.

Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company's long-term debt, stockholders' equity and working capital. The estimated Enterprise Value at the Effective Date was below the midpoint of the Court approved range of $1.6 billion to $1.8 billion, primarily reflecting the decline in forward commodity prices during the period between the Company's analysis performed in advance of the July 2016 chapter 11 bankruptcy filing and the Effective Date. The Enterprise Value was derived from an independent valuation using an asset based methodology of proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh-start reporting date of September 9, 2016.

The Company's principal assets are its oil and natural gas properties. For purposes of estimating the fair value of the Company's proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company's reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.5% for proved reserves and 12.5% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company's five year development plan. Weighted average

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3. FRESH-START ACCOUNTING (Continued)

commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per million British thermal units (MMBtu) of natural gas and $12.00 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts' estimated prices.

In estimating the fair value of the Company's unproved acreage that was not included in the valuation of probable and possible reserves, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company's unproved acreage from a market participant perspective.

See further discussion below in the "Fresh-start accounting adjustments" for the specific assumptions used in the valuation of the Company's various other assets.

Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value were reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment.

The following table reconciles the Company's Enterprise Value to the estimated fair value of the Successor's common stock as of September 9, 2016 (in thousands):

	September 9, 2016

Enterprise Value	$	1,618,888
Plus: Cash		13,943
Less: Fair value of debt		(1,016,160	)
Less: Fair value of redeemable noncontrolling interest		(41,070	)
Less: Fair value of other long-term liabilities		(4,478	)
Less: Fair value of warrants		(16,691	)

Fair Value of Successor common stock	$	554,432

The following table reconciles the Company's Enterprise Value to its Reorganization Value as of September 9, 2016 (in thousands):

	September 9, 2016

Enterprise Value	$	1,618,888
Plus: Cash		13,943
Plus: Current liabilities		178,639
Plus: Noncurrent asset retirement obligation		32,156

Reorganization Value of Successor assets	$	1,843,626

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. FRESH-START ACCOUNTING (Continued)

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company's unaudited condensed consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company's assumptions and methods used to determine fair value for its assets and liabilities. Amounts included in the table below are rounded to thousands.

	As of September 9, 2016

	Predecessor Company			Reorganization Adjustments				Fresh-Start Adjustments				Successor Company
Current assets:
Cash	$	111,464		$	(97,521	)	(1)	$	—			$	13,943
Accounts receivable		116,859			—				—				116,859
Receivables from derivative contracts		97,648			—				—				97,648
Restricted cash		17,164			—				—				17,164
Prepaids and other		8,961			—				(1,332	)	(7)		7,629

Total current assets		352,096			(97,521	)			(1,332	)			253,243

Oil and natural gas properties (full cost method):
Evaluated		7,712,003			—				(6,497,874	)	(8)		1,214,129
Unevaluated		1,193,259			—				(861,144	)	(8)		332,115

Gross oil and natural gas properties		8,905,262			—				(7,359,018	)			1,546,244
Less—accumulated depletion		(6,803,231	)		—				6,803,231		(8)		—

Net oil and natural gas properties		2,102,031			—				(555,787	)			1,546,244

Other operating property and equipment:
Other operating property and equipment		100,079			—				(62,008	)	(9)		38,071
Less—accumulated depreciation		(24,154	)		—				24,154		(9)		—

Net other operating property and equipment		75,925			—				(37,854	)			38,071

Other noncurrent assets:
Receivables from derivative contracts		4,431			—				—				4,431
Funds in escrow and other		1,610			—				27		(10)		1,637

Total assets	$	2,536,093		$	(97,521	)		$	(594,946	)		$	1,843,626



Current liabilities:
Accounts payable and accrued liabilities	$	160,000		$	13,688		(2)	$	—			$	173,688
Liabilities from derivative contracts		102			—				—				102
Other		414			—				4,435		(11)(12)		4,849

Total current liabilities		160,516			13,688				4,435				178,639

Long-term debt, net		1,031,114			—				(14,954	)	(13)		1,016,160
Liabilities subject to compromise		2,007,703			(2,007,703	)	(3)		—				—
Other noncurrent liabilities:
Liabilities from derivative contracts		525			—				—				525
Asset retirement obligations		48,955			—				(16,799	)	(12)		32,156
Other		528			—				3,425		(11)(14)		3,953
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest		219,891			—				(178,821	)	(14)		41,070
Stockholders' equity:
Preferred stock (Predecessor)		—			—		(4)		—				—
Common Stock (Predecessor)		12			(12	)	(4)		—				—
Common Stock (Successor)		—			9		(5)		—				9
Additional paid-in capital (Predecessor)		3,287,906			(3,287,906	)	(4)		—				—
Additional paid-in capital (Successor)		—			571,114		(5)		—				571,114
Retained earnings (accumulated deficit)		(4,221,057	)		4,613,289		(6)		(392,232	)	(15)		—

Total stockholders' equity		(933,139	)		1,896,494				(392,232	)			571,123

Total liabilities and stockholders' equity	$	2,536,093		$	(97,521	)		$	(594,946	)		$	1,843,626

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. FRESH-START ACCOUNTING (Continued)

Reorganization adjustments

(1): The table below details cash payments as of September 9, 2016, pursuant to the terms of the Plan described in Note 2, "Reorganization," (in thousands):


Payment to Third Lien Noteholders	$	33,826
Payment to Unsecured Noteholders		37,595
Payment to Convertible Noteholder		15,000
Payment to Preferred Holders		11,100

Total Uses	$	97,521

(2): In connection with the chapter 11 bankruptcy, the Company modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. This amount also reflects $10.3 million paid to the Company's restructuring advisors subsequent to the emergence from chapter 11 bankruptcy.
(3): Liabilities subject to compromise were as follows (in thousands):


13.0% senior secured third lien notes due 2022	$	1,017,970
9.25% senior notes due 2022		37,194
8.875% senior notes due 2021		297,193
9.75% senior notes due 2020		315,535
8.0% convertible note due 2020		289,669
Accrued interest		46,715
Office lease modification and rejection fees		3,427

Liabilities subject to compromise		2,007,703
Fair value of equity and warrants issued to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder		(548,947	)
Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder		(86,421	)
Office lease modification and rejection fees		(3,427	)

Gain on settlement of Liabilities subject to compromise	$	1,368,908

(4): Reflects the cancellation of Predecessor equity, as follows (in thousands):


Predecessor Company stock	$	3,287,918
Fair value of equity issued to Predecessor common stockholders		(22,176	)
Cash payment to Preferred Holders		(11,100	)

Cancellation of Predecessor Company equity	$	3,254,642

(5): Reflects the issuance of Successor equity. In accordance with the Plan, the Successor Company issued 3.6 million shares of common stock to the Predecessor Company's existing common stockholders, 68.8 million shares of common stock to the Third Lien Noteholders, 14.0 million shares of common stock to the Unsecured Noteholders, and 3.6 million shares of common stock to

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3. FRESH-START ACCOUNTING (Continued)

the Convertible Noteholder. This amount is subject to dilution by warrants issued to the Unsecured Noteholders and the Convertible Noteholder totaling 4.7 million shares with an exercise price of $14.04 per share and a term of four years. The fair value of the warrants was estimated at $3.52 per share using a Black-Scholes-Merton valuation model.

(6): The table below reflects the cumulative effect of the reorganization adjustments discussed above (in thousands):


Gain on settlement of Liabilities subject to compromise	$	1,368,908
Accrued reorganization items		(10,261	)
Cancellation of Predecessor Company equity		3,254,642

Net impact to retained earnings (accumulated deficit)	$	4,613,289

Fresh-start accounting adjustments

(7): Reflects the reclassification of tubulars and well equipment to "Oil and natural gas properties."
(8): In estimating the fair value of its oil and natural gas properties, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company's proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company's reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.5% for proved reserves and 12.5% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company's five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts' estimated prices.

(9): In estimating the fair value of its other operating property and equipment, the Company used a combination of the income, cost, and market approaches.

For purposes of estimating the fair value of its other operating property and equipment, an income approach was used that estimated future cash flows associated with the assets over the remaining useful lives. The valuation included such inputs as estimated future production, gathering and compression revenues, and operating expenses that were discounted at a weighted average cost of capital rate of 9.5%.

For purposes of estimating the fair value of its other operating assets, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and computer equipment, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach

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3. FRESH-START ACCOUNTING (Continued)

was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets.

(10): Reflects the adjustment of the Company's equity method investment in SBE Partners, L.P. to fair value based on an income approach, which calculated the discounted cash flows of the Company's share of the partnership's interest in oil and gas proved reserves. The anticipated cash flows of the reserves were risked by reserve category and discounted at 10.5%. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts' estimated prices.
(11): Records an intangible liability of approximately $8.3 million, $4.5 million of which was recorded as current, to adjust the Company's active rig contract to fair value at September 9, 2016. The intangible liability will be amortized over the remaining life of the contract.
(12): Reflects the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of September 9, 2016, adjusted for inflation and then discounted at the appropriate credit-adjusted risk free rate ranging from 5.5% to 6.6% depending on the life of the well. The fair value of asset retirement obligations was estimated at $32.5 million, approximately $0.3 million of which was recorded as current. Refer to Note 9, "Asset Retirement Obligations," for further details of the Company's asset retirement obligations.
(13): Reflects the adjustment of the 2020 Second Lien Notes and the 2022 Second Lien Notes to fair value. The fair value estimate was based on quoted market prices from trades of such debt on September 9, 2016. Refer to Note 6, "Debt," for definitions of and further information regarding the 2020 Second Lien Notes and 2022 Second Lien Notes.
(14): Reflects the adjustment of the Company's redeemable noncontrolling interest and related embedded derivative of HK TMS, LLC to fair value. The fair value of the redeemable noncontrolling interest was estimated at $41.1 million and the embedded derivative was estimated at zero. For purposes of estimating the fair values, an income approach was used that estimated fair value based on the anticipated cash flows associated with HK TMS, LLC's proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 12.5%. The value of the redeemable noncontrolling interest was further reduced by a probability factor of the potential assignment of the common shares of HK TMS, LLC to Apollo Global Management, which occurred subsequent to the fresh-start date. Refer to Note 4, "Acquisitions and Divestitures," for further information regarding the divestiture of HK TMS, LLC on September 30, 2016.
(15): Reflects the cumulative effect of the fresh-start accounting adjustments discussed above.

Reorganization Items

Reorganization items represent (i) expenses or income incurred subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments and are recorded in "Reorganization items" in the Company's unaudited condensed

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consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):

	Successor			Predecessor

	Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
Gain on settlement of Liabilities subject to compromise	$	—		$	1,368,908
Fresh start adjustments		—			(392,232	)
Reorganization professional fees and other		(556	)		(30,287	)
Write-off debt discounts/premiums and debt issuance costs		—			(32,667	)

Gain (loss) on reorganization items	$	(556	)	$	913,722

4. ACQUISITIONS AND DIVESTITURES

Acquisitions

Delaware Basin Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017 (Successor), 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 agreed 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), for a total 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 its preferred stock and borrowings under its Senior Credit Agreement. Refer to Note 11, "Stockholders' Equity," for further discussion of the Company's issuance of the Preferred Stock.

The Pecos County Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The estimated fair value of the properties acquired approximates the fair value of consideration and as a result no goodwill was recognized.

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4. ACQUISITIONS AND DIVESTITURES (Continued)

The following table summarizes the consideration paid to acquire the Pecos County Assets, as well as the estimated values of assets acquired and liabilities assumed as of the acquisition date (in thousands):


Cash consideration paid to Samson at closing(1)	$	703,865
Less: Post-effective closing date adjustments(2)		(4,677	)

Final consideration transferred	$	699,188



Plus: Estimated Fair Value of Liabilities Assumed:
Current liabilities	$	839
Asset retirement obligations		2,116

Amount attributable to liabilites assumed		2,955

Total purchase price plus liabilities assumed	$	702,143



Estimated Fair Value of Assets Acquired:
Evaluated oil and natural gas properties(3)(4)	$	150,275
Unevaluated oil and natural gas properties(3)(4)		525,489
Other operating property and equipment(5)		26,379

Amount attributable to assets acquired	$	702,143

(1): Represents amount of cash consideration, adjusted for customary closing items, for the purchase of the Pecos County Assets funded by the issuance of approximately $400.1 million of new 8% automatically convertible preferred stock and borrowings under the Senior Credit Agreement.
(2): In accordance with the purchase agreement, the effective date of the acquisition was November 1, 2016 and therefore revenues, expenses and related capital expenditures from November 1, 2016 through February 28, 2017, the closing date of the Pecos County Acquisition, have been reflected as adjustments to the purchase price consideration.
(3): In estimating the fair value of the Pecos County Assets' oil and natural gas properties, the Company used an income approach. For purposes of estimating the fair value of the proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Pecos County Assets' estimated reserves risked by reserve category and discounted using a weighted average cost of capital rate of 10.0% for proved reserves and 12.0% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company's five-year development plan. This estimation includes the use of unobservable inputs, such as estimated future production, oil and natural gas revenues and expenses. The use of these unobservable inputs results in the fair value estimate of the Pecos County Assets being classified as Level 3.
(4): Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $76.10 per barrel of oil, $4.14 per Mcf of natural gas and $29.48 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and research analysts' estimated prices.

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4. ACQUISITIONS AND DIVESTITURES (Continued)

(5): In estimating the fair value of the Pecos County Assets' other operating property and equipment, the Company used a combination of the cost and market approaches. A market approach was relied upon to value the land, heavy equipment and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets.

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2017 (Successor) and the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) 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 (Successor) and the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) 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 periods 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. Amounts included in the table below are rounded to thousands.

	Successor					Predecessor

	Nine Months Ended September 30, 2017		Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
	(Unaudited)		(Unaudited)			(Unaudited)
Revenue	$	360,590	$	25,516		$	288,902
Net income (loss)		635,854		(450,035	)		16,513
Net income (loss) available to common stockholders		587,847		(450,826	)		(28,239	)
Pro forma net income (loss) per share of common stock:
Basic	$	4.61	$	(4.95	)	$	(0.23	)
Diluted	$	4.58	$	(4.95	)	$	(0.23	)

The Company's historical financial information was adjusted to give effect to the pro forma events that are directly attributable to the Pecos County Assets and are factually supportable. The unaudited

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pro forma consolidated results include the historical revenues and expenses of assets acquired and liabilities assumed, with the following adjustments:

•: Adjustment to recognize incremental depletion expense under the full cost method of accounting based on the fair value of the oil and natural gas properties and incremental accretion expense based on the asset retirement costs of the oil and natural gas properties at acquisition;
•: Adjustment to recognize incremental depreciation expense of the other operating property and equipment and incremental accretion expense based on the asset retirement costs of the other operating property and equipment at acquisition; and
•: Eliminate transaction costs and non-recurring charges directly related to the transactions that were included in the historical results of operations for the Company in the amount of approximately $1.0 million. Transaction costs directly related to the transaction that do not have a continuing impact on the combined Company's operating results have been excluded from the pro forma earnings.

For the nine months ended September 30, 2017 (Successor), the Company recognized $28.3 million of oil, natural gas and natural gas liquids and other revenue related to the Pecos County Assets and $2.4 million of net field operating income (oil, natural gas and natural gas liquids and other revenues less lease operating expense, workover expense, production taxes, gathering and other expense, and depletion, depreciation and accretion expense) related to the Pecos County Assets. Additionally, non-recurring transaction costs of approximately $1.0 million related to the Pecos County Acquisition for the nine months ended September 30, 2017 (Successor) are included in the unaudited condensed consolidated statements of operations in "General and administrative" expenses; these non-recurring transaction costs have been excluded from the pro forma results for all periods presented in the above table.

Divestitures

Williston Basin Operated Assets

On July 10, 2017 (Successor), the Company and certain of its subsidiaries entered into an Agreement of Sale and Purchase (the Purchase Agreement) with Bruin Williston Holdings, LLC (the Purchaser) 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, subject to post-closing adjustments (the Williston Divestiture). The effective date of the sale was June 1, 2017 and the transaction closed on September 7, 2017. The Company is using the net proceeds from the sale to repay borrowings outstanding under its Senior Credit Agreement, repurchase approximately $425 million principal amount of the outstanding $850 million principal amount of its 6.75% senior unsecured notes, redeem all of its outstanding 12% 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.

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4. ACQUISITIONS AND DIVESTITURES (Continued)

As discussed further in Note 5, "Oil and Natural Gas Properties," the Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, 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 $491.8 million during the three months ended September 30, 2017 (Successor). 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 the 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 (Successor), certain of the Company's subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of the Company's oil and natural gas 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 $10.2 million was allocated to other operating property and equipment and approximately $484.1 million was allocated to the Company's oil and natural gas properties.

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 nine months ended September 30, 2017 (Successor). 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.

HK TMS, LLC

On September 30, 2016, certain wholly-owned subsidiaries of the Successor Company executed an Assignment and Assumption Agreement with an affiliate of Apollo Global Management (Apollo) pursuant to which Apollo acquired one hundred percent (100%) of the common shares (the Membership Interests) of HK TMS, LLC (HK TMS), which transaction is referred to as the HK TMS Divestiture. HK TMS was previously a wholly-owned subsidiary and held all of the Successor Company's oil and natural gas properties in the Tuscaloosa Marine Shale (TMS). In exchange for the

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assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests, which were previously classified as "Mezzanine Equity" on the unaudited condensed consolidated balance sheets of HK TMS, from and after such date. Prior to the HK TMS Divestiture, the preferred shares were considered probable of becoming redeemable and therefore were accreted up to the estimated required redemption value. The accretion was presented as a deemed dividend and recorded in "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. For the period of September 10, 2016 through September 30, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor), HK TMS issued 791 and 9,329 additional preferred shares to Apollo for dividends paid-in-kind, respectively. These dividends were presented within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations.

HK TMS was not included in the chapter 11 bankruptcy filings or the Restructuring Support Agreement discussed in Note 2, "Reorganization."

5. OIL AND NATURAL GAS PROPERTIES

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

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

Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Predecessor Company determined capitalized interest by multiplying the Predecessor Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool. The capitalized interest amounts were recorded as additions to "Unevaluated oil and natural gas properties" on the unaudited condensed consolidated balance sheets. For the period from January 1, 2016 through September 9, 2016 (Predecessor), the Company capitalized interest costs of $68.2 million. The Successor Company's policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization.

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5. OIL AND NATURAL GAS PROPERTIES (Continued)

At September 30, 2017 (Successor), 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 West Texas Intermediate (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 (Successor) did not exceed the ceiling amount.

At September 30, 2016 (Successor), 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, 2016 of the WTI crude oil spot price of $41.68 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, 2016 of the Henry Hub natural gas price of $2.28 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, 2016 exceeded the ceiling amount by $420.9 million ($268.1 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the period of September 10, 2016 through September 30, 2016 (Successor). The impairment at September 30, 2016 reflects the differences between the first day of the month average prices for the preceding 12-months required by Regulation S-X, Rule 4-10 and ASC 932 in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date of September 9, 2016.

At June 30, 2016 (Predecessor) and March 31, 2016 (Predecessor), the Company recorded a full cost ceiling impairment before income taxes of $257.9 million ($163.1 million after taxes, before valuation allowance) and $496.9 million ($315.1 million after taxes, before valuation allowance), respectively. The ceiling test impairments at March 31, 2016 and June 30, 2016, were driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculations since December 31, 2015, when the first-day-of-month 12-month average price for crude oil was $50.28 per barrel. The impairment at March 31, 2016 also reflects the transfer of the remaining unevaluated Utica/Point Pleasant (Utica) and TMS properties of approximately $330.4 million and $74.8 million, respectively, to the full cost pool. As discussed above, the Company considers the facts and circumstances around its unevaluated properties that may indicate impairment on a quarterly basis. For the quarter ended March 31, 2016, management concluded that it was no longer probable that capital would be available or approved to continue exploratory drilling activities in the Company's Utica or TMS acreage positions in advance of the related lease expirations due to the Company's evaluation of strategic alternatives to reduce its debt and preserve liquidity in light of continued low commodity prices, together with a reduction of the Company's exploration department and the Company's intent to expend capital only on its most economical and proven areas.

The Company recorded the full cost ceiling test impairments in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets.

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

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6. DEBT

Long-term debt as of September 30, 2017 (Successor) and December 31, 2016 (Successor) consisted of the following (in thousands):

	Successor

	September 30, 2017		December 31, 2016
Senior revolving credit facility	$	—	$	186,000
8.625% senior secured second lien notes due 2020(1)		—		672,613
12.0% senior secured second lien notes due 2022(2)		—		106,040
6.75% senior notes due 2025(3)		408,879		—

	$	408,879	$	964,653

(1): On February 16, 2017, the Company repurchased approximately 41% of the outstanding aggregate principal amount of its 8.625% senior secured second lien notes due 2020 with proceeds from the issuance of new 6.75% senior unsecured notes due 2025. The remaining aggregate principal amount was redeemed on March 20, 2017. Amount was net of a $27.4 million unamortized discount at December 31, 2016 (Successor). Refer to "8.625% Senior Secured Second Lien Notes" below for further details.
(2): On September 7, 2017, the Company issued an irrevocable notice to redeem the outstanding aggregate principal amount of its 12.0% senior secured second lien notes due 2022 on October 7, 2017. Amount is net of a $6.8 million unamortized discount at December 31, 2016 (Successor). Refer to "12.0% Senior Secured Second Lien Notes" below for further details.
(3): On February 16, 2017, the Company issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025. On October 10, 2017, the Company repurchased $425.0 million principal amount of the 2025 Notes at 103.0% of par plus accrued and unpaid interest. The repurchased 2025 Notes are presented in "Current portion of long-term debt, net" on the unaudited condensed consolidated balance sheet at September 30, 2017. Amount is net of $8.3 million unamortized discount and $7.8 million unamortized debt issuance costs at September 30, 2017 (Successor). 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. The Senior Credit Agreement amends and restates in its entirety the original Senior Secured Revolving Credit Agreement entered into on September 9, 2016. 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 $100.0 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

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borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.25% 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) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00. At September 30, 2017 (Successor), the Company was in compliance with the financial covenants under the Senior Credit Agreement.

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, 2017 (Successor), under the then effective borrowing base of $140.0 million, the Company had no indebtedness outstanding, approximately $6.4 million letters of credit outstanding and approximately $133.6 million of borrowing capacity available under the Senior Credit Agreement.

8.625% Senior Secured Second Lien Notes

On May 1, 2015 (Predecessor), the Company issued $700.0 million aggregate principal amount of its 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes) in a private offering. The 2020 Second Lien Notes were issued at par. The net proceeds from the sale of the 2020 Second Lien Notes were approximately $686.2 million (after deducting offering fees and expenses). The 2020 Second Lien Notes bore interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year. In accordance with the Plan, the 2020 Second Lien Notes were unimpaired and reinstated upon the Company's emergence from chapter 11 bankruptcy.

On February 16, 2017 (Successor), the Company paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes pursuant to a tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. On February 21, 2017 (Successor), the Company paid approximately $1.2 million for approximately $1.2 million of principal amount of 2020 Second Lien Notes, a make-whole premium of approximately $54,000 plus accrued and unpaid interest to repurchase such notes pursuant to guaranteed delivery procedures of the tender offer. On March 20, 2017 (Successor), the Company paid approximately $432.0 million for $409.6 million aggregate principal amount of 2020 Second Lien Notes,

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a make-whole premium of $17.7 million and unpaid interest of approximately $4.8 million to redeem the remaining notes at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The repurchase and redemption of the 2020 Second Lien Notes was funded with proceeds from the issuance of $850.0 million in new 6.75% senior unsecured notes due 2025.

The Company 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. The loss was recorded in "Gain (loss) on extinguishment of debt" on the unaudited condensed consolidated statements of operations.

12.0% Senior Secured Second Lien Notes

On December 21, 2015 (Predecessor), the Company completed the issuance in a private placement of approximately $112.8 million aggregate principal amount of new 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes) in exchange for approximately $289.6 million principal amount of its then outstanding senior unsecured notes, consisting of $116.6 million principal amount of 9.75% senior notes due 2020, $137.7 million principal amount of 8.875% senior notes due 2021 and $35.3 million principal amount of 9.25% senior notes due 2022. At closing, the Predecessor Company paid all accrued and unpaid interest since the respective interest payment dates of the unsecured notes surrendered in the exchange. The 2022 Second Lien Notes bore interest at a rate of 12.0% per annum, payable semi-annually on February 15 and August 15 of each year. In accordance with the terms of the Plan, the 2022 Second Lien Notes were unimpaired and reinstated upon the Company's emergence from chapter 11 bankruptcy.

On September 7, 2017 (Successor), the Company issued an irrevocable notice to redeem the outstanding aggregate principal amount of its 2022 Second Lien Notes on October 7, 2017 (the Redemption Date). In accordance with the terms of the indenture governing the 2022 Second Lien Notes, all of the outstanding 2022 Second Lien Notes were redeemed at a redemption price equal to the principal amount of $112.8 million plus a make whole premium of approximately $23.0 million and accrued and unpaid interest of approximately $2.0 million. On September 7, 2017, utilizing $137.8 million of the proceeds from the Williston Divestiture, the Company 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 the Company and the subsidiary guarantors under the 2022 Second Lien Notes and related guarantees. The payment of the redemption price and accrued interest to a holder of 2022 Second Lien Notes became due and payable on the Redemption Date upon presentation and surrender by the holder of such notes.

The Company 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. The loss was recorded in "Gain (loss) on extinguishment of debt" on the unaudited condensed consolidated statements of operations.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

6.75% Senior Notes

On February 16, 2017 (Successor), 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, beginning on August 15, 2017. The 2025 Notes will mature on February 15, 2025. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers' discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the private placement to fund the repurchase and redemption of the outstanding 2020 Second Lien Notes, as discussed above, and for general corporate purposes.

The 2025 Notes are governed by an Indenture, dated as of February 16, 2017 (as supplemented, the February 2017 Indenture) by and among the Company, the Guarantors and U.S. Bank National Association, as Trustee, which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The February 2017 Indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 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. In the event the Company fails to comply with its obligations under the 2017 Registration Rights Agreement, it will be subject to penalties in the form of additional interest payable on the 2025 Notes.

At any time prior to February 15, 2020, the Company may redeem the 2025 Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make-whole premium, together with accrued and unpaid interest, if any, to the redemption date. The 2025 Notes will be redeemable, in whole or in part, on or after February 15, 2020 at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest (if any)

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

on the 2025 Notes redeemed during the twelve month period indicated beginning on February 15 of the years indicated below:

Year		Percentage

2020			105.063
2021			103.375
2022			101.688
2023 and thereafter			100.000

Additionally, the Company may redeem up to 35% of the 2025 Notes prior to February 15, 2020 for a redemption price of 106.75% of the principal amount thereof, plus accrued and unpaid interest, utilizing net cash proceeds from certain equity offerings. In addition, upon a change of control of the Company, holders of the 2025 Notes will have the right to require the Company to repurchase all or any part of their 2025 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2025 Notes repurchased, plus any accrued and unpaid interest.

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 during the three months ended September 30, 2017. The remaining unamortized discount on the $850 million principal amount of 2025 Notes was $16.7 million at September 30, 2017.

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 $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest. The repurchased 2025 Notes are presented in "Current portion of long-term debt, net" on the unaudited condensed consolidated balance sheet at September 30, 2017.

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, 2017 (Successor), the Company capitalized approximately $17.1 million of debt issuance costs related to the Senior Credit Agreement and the 2025 Notes. The debt issuance costs for the Successor 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 "Current portion of long-term debt, net" and"Long-term debt, net" on the unaudited condensed consolidated balance sheets.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS

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

As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of September 30, 2017 (Successor) and December 31, 2016 (Successor) (in thousands):

	Successor

	September 30, 2017
	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	6,610	$	—	$	6,610



Liabilities
Liabilities from derivative contracts	$	—	$	5,454	$	—	$	5,454

	December 31, 2016

	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	5,923	$	—	$	5,923



Liabilities
Liabilities from derivative contracts	$	—	$	16,920	$	—	$	16,920

Derivative contracts listed above as Level 2 include collars 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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8, "Derivative and Hedging Activities," for additional discussion of derivatives.

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

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivables and accounts payables approximate their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair values of the Company's fixed interest rate debt instruments as of September 30, 2017 (Successor) and December 31, 2016 (Successor) (excluding discounts and debt issuance costs and including the current portion) (in thousands):

	Successor

	September 30, 2017				December 31, 2016
Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
8.625% senior secured second lien notes	$	—	$	—	$	700,000	$	733,250
12.0% senior secured second lien notes		—		—		112,826		123,827
6.75% senior notes		850,000		879,087		—		—

	$	850,000	$	879,087	$	812,826	$	857,077

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

On February 28, 2017 (Successor), the Company closed the Pecos County Acquisition and recorded the assets acquired and liabilities assumed at their acquisition date fair values. See Note 4, "Acquisitions and Divestitures," for a discussion of the fair value approaches used by the Company and the classification of the estimates within the fair value hierarchy.

On September 9, 2016, the Company emerged from chapter 11 bankruptcy and adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company's assets and liabilities were recorded at their fair values as of the fresh-start reporting date, September 9, 2016. See Note 3, "Fresh-start Accounting," for a detailed discussion of the fair value approaches used by the Company.

For the period from January 1, 2016 through September 9, 2016 (Predecessor), the Company recorded a non-cash impairment charge of $28.1 million related to its gas gathering infrastructure. See Note 1, "Financial Statement Presentation," for a discussion of the valuation approach used and the classification of the estimate within the fair value hierarchy.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

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

8. DERIVATIVE AND HEDGING ACTIVITIES

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

It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions 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.

At September 30, 2017 (Successor), the Company's crude oil and natural gas derivative positions consisted of basis swaps and costless put/call "collars." At December 31, 2016 (Successor), the Company's derivative positions consisted of collars only. 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 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, 2017 (Successor), the Company had 32 open commodity derivative contracts summarized in the following tables: four natural gas collar arrangements, 11 crude oil basis swaps and 17 crude oil collar arrangements.

At December 31, 2016 (Successor), the Company had 22 open commodity derivative contracts summarized in the following tables: two natural gas collar arrangements and 20 crude oil collar arrangements.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets (in thousands):

		Asset derivative contracts					Liability derivative contracts

		Successor					Successor
Derivatives not designated as hedging contracts under ASC 815	Balance sheet	September 30, 2017		December 31, 2016		Balance sheet	September 30, 2017			December 31, 2016
Commodity contracts	Current assets—receivables from derivative contracts	$	5,166	$	5,923	Current liabilities—liabilities from derivative contracts	$	(3,279	)	$	(16,434	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		1,444		—	Other noncurrent liabilities—liabilities from derivative contracts		(2,175	)		(486	)

Total derivatives not designated as hedging contracts under ASC 815		$	6,610	$	5,923		$	(5,454	)	$	(16,920	)

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


		Successor						Predecessor
		Successor						Predecessor
					Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016
		Three Months Ended September 30, 2017

	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815

Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(31,209	)	$	(30,338	)	$	(39,451	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		8,794			22,763			57,234

Total net gain (loss) on derivative contracts		$	(22,415	)	$	(7,575	)	$	17,783

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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


		Successor					Predecessor
		Successor					Predecessor
				Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016

		Nine Months Ended September 30, 2017
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815

Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	11,010	$	(30,338	)	$	(263,732	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		17,129		22,763			245,734

Total net gain (loss) on derivative contracts		$	28,139	$	(7,575	)	$	(17,998	)

At September 30, 2017 (Successor) and December 31, 2016 (Successor), the Company had the following open crude oil and natural gas derivative contracts:

			Successor

			September 30, 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
October 2017 - December 2017	Collars	Natural Gas		460,000	$	3.26	$	3.26	$	3.76	$	3.76	$	—	$	—
October 2017 - December 2017	Collars	Crude Oil		437,000		51.07 - 60.00		55.64		56.07 - 75.00		63.80
November 2017 - December 2017	Collars	Crude Oil		61,000		51.50		51.50		56.50		56.50
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
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		3,467,500										(0.98) - (1.33)		(1.15	)

			Successor

			December 31, 2016
					Floors				Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
January 2017 - December 2017	Collars	Natural Gas		3,650,000	$	3.15 - $3.26	$	3.20	$	3.50 - $3.76	$	3.63
January 2017 - December 2017	Collars	Crude Oil		6,843,750		47.00 - 60.00		51.39		52.00 - 76.84		58.75
January 2018 - December 2018	Collars	Crude Oil		730,000		53.00		53.00		58.00		58.00

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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

	Derivative Assets						Derivative Liabilities

	Successor						Successor
Offsetting of Derivative Assets and Liabilities	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Gross Amounts Presented in the Consolidated Balance Sheet	$	6,610		$	5,923		$	(5,454	)	$	(16,920	)
Amounts Not Offset in the Consolidated Balance Sheet		(2,714	)		(5,283	)		2,714			5,075

Net Amount	$	3,896		$	640		$	(2,740	)	$	(11,845	)

The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

9. ASSET RETIREMENT OBLIGATIONS

The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For other operating property and equipment, the Company records an ARO when the system is placed in service and it can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work when it is required. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes a 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)

9. 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, 2016 (Sucessor)	$	32,375
Liabilities settled and divested(1)		(31,743	)
Additions		286
Acquisitions(1)		2,194
Accretion expense		1,230
Revisions in estimated cash flows		782

Liability for asset retirement obligations as of September 30, 2017 (Successor)	$	5,124

(1): See Note 4, "Acquisitions and Divestitures," for further information.

10. COMMITMENTS AND CONTINGENCIES

Commitments

The Company leases corporate office space in Houston, Texas; and Denver, Colorado as well as other field office locations. Rent expense was approximately $3.0 million for the nine months ended September 30, 2017 (Successor). Rent expense was approximately $0.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and $5.9 million for the period of January 1, 2016 through September 9, 2016 (Predecessor). Future obligations associated with the Company's operating leases are presented in the table below (in thousands):


Remaining period in 2017	$	830
2018		3,339
2019		2,990
2020		1,811
2021		1,497
Thereafter		2,180

Total	$	12,647

As of September 30, 2017 (Successor), the Company has the following active drilling rig commitments (in thousands):


Remaining period in 2017	$	2,378
2018		2,040
2019		—
2020		—
2021		—
Thereafter		—

Total	$	4,418

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS AND CONTINGENCIES (Continued)

As of September 30, 2017 (Successor), termination of the Company's active drilling rig commitments would require early termination penalties of $1.7 million, which would be in lieu of paying the remaining active commitments of $4.4 million.

In past years, with the sustained decline in crude oil prices, the Company stacked certain drilling rigs and amended other previous drilling rig contracts. In the future, the Company expects to incur stacking charges/early termination fees on certain drilling rig commitments as follows (in thousands):


Remaining period in 2017	$	966
2018		1,260
2019		—
2020		3,000
2021		—
Thereafter		—

Total	$	5,226

Stacking fees and early termination fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations.

In December 2016 (Successor), the Company entered into an agreement with a private company for the right 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 for an initial purchase price of $11,000 per acre. The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. The agreement was subsequently amended on June 14, 2017 (Successor) to increase the purchase price of the Southern and 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, the Company initially paid $5.0 million and drilled a commitment well on the Southern Tract and on June 15, 2017 (Successor) purchased the Southern Tract acreage for approximately $13,000 per acre. On June 15, 2017 (Successor), the Company also paid $5.0 million and recently drilled a commitment well on the Northern Tract, to earn the option to acquire the Northern Tract acreage for $13,000 per acre by December 31, 2017. This option purchase agreement is not included in the tables above.

The Company has entered into various long-term gathering, transportation and sales contracts with respect to production from the Delaware Basin in West Texas. As of September 30, 2017 (Successor), the Company had in place two long-term crude oil contracts and four long-term natural gas contracts in this area. 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 eight years from the date of first production. The sales prices under these contracts are based on posted market rates.

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS AND CONTINGENCIES (Continued)

material effect on the Company's unaudited condensed consolidated operating results, financial position or cash flows.

11. STOCKHOLDERS' EQUITY

Preferred Stock and Non-Cash Preferred Stock Dividend

On January 24, 2017 (Successor) (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 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 is 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 (Successor) 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 (Successor). The Discount amortization is reflected in "Non-cash preferred dividend" in

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

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 September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of Predecessor common stock were cancelled and the Successor Company issued approximately 90.0 million shares of common stock in total to the Predecessor Company's existing common stockholders, Third Lien Noteholders, Unsecured Noteholders, and the Convertible Noteholder. Refer to Note 2, "Reorganization" for further details.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the Successor Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for (i) the total number of shares of all classes of capital stock that the Successor Company has the authority to issue is 1,001,000,000 of which 1,000,000,000 shares are common stock, par value $0.0001 per share and 1,000,000 shares are preferred stock, par value $0.0001 per share, (ii) a classified board structure, (iii) the right of removal of directors with or without cause by stockholders, and (iv) a restriction on the Successor Company from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code. Additionally, the Company's 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred), was cancelled pursuant to the Plan, and no shares of Series A Preferred are outstanding.

Warrants

On September 9, 2016, upon the emergence from chapter 11 bankruptcy, all existing February 2012 warrants were cancelled and the Successor Company issued 3.8 million new warrants to the Unsecured Noteholders and 0.9 million new warrants to the Convertible Noteholder. The warrants in aggregate can be exercised to purchase 4.7 million shares of the Successor Company's common stock at an exercise price of $14.04 per share. The Company allocated approximately $16.7 million of the Enterprise Value to the warrants which is reflected in "Additional paid-in capital" on the unaudited condensed consolidated balance sheets. The holders are entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020. See Note 2, "Reorganization" for further details.

Incentive Plans

Immediately prior to emergence from chapter 11 bankruptcy, the Predecessor incentive plan was cancelled and all share-based compensation awards granted thereunder were either vested or cancelled and the Predecessor Company's Board adopted the 2016 Long-Term Incentive Plan (the 2016 Incentive Plan). An aggregate of 10.0 million shares of the Successor Company's common stock were available for grant pursuant to awards under the 2016 Incentive Plan in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awards. On April 6, 2017 (Successor), an amendment to the 2016 Incentive Plan to increase by 9.0 million shares the maximum number of shares of common stock that may be issued thereunder, i.e., a maximum of 19.0 million shares, became effective, which was 20 calendar days following the date the Company mailed an information statement to all stockholders of record notifying them of approval of the amendment by

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

written consent. As of September 30, 2017 (Successor) and December 31, 2016 (Successor), a maximum of 7.3 million and 1.7 million shares of common stock, respectively, remained reserved for issuance under the 2016 Incentive Plan.

The Company accounts for share-based payment accruals under authoritative guidance on stock compensation. The guidance requires all share-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. For awards granted under the 2016 Incentive Plan subsequent to emerging from chapter 11 bankruptcy and in conjunction with the early adoption of ASU 2016-09, 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, 2017 (Successor) the Company recognized $12.3 million and $33.5 million, respectively, of share-based compensation expense. For the period from September 10, 2016 through September 30, 2016 (Successor), the period from July 1, 2016 through September 9, 2016 (Predecessor) and the period from January 1, 2016 through September 9, 2016 (Predecessor) the Company recognized $13.2 million, $1.2 million, and $4.9 million, respectively, of share-based compensation expense. These were recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

Stock Options

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

During the nine months ended September 30, 2017 (Successor), the Company granted stock options under the 2016 Incentive 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 (Successor), 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.

During the period from September 10, 2016 through September 30, 2016 (Successor), the Company granted stock options under the 2016 Incentive Plan covering 5.0 million shares of common stock to employees of the Company. These stock options have an exercise price of $9.24 per share with a weighted average exercise price of $9.24 per share. At September 30, 2016 (Successor), the Company had $29.8 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.9 years. Immediately prior to emergence from chapter 11 bankruptcy, all outstanding stock options under the Predecessor Incentive Plan were cancelled. Refer to Note 2, "Reorganization," for further details.

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

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 2016 Incentive Plan specifically related to the Company's emergence from chapter 11 bankruptcy vested on or before September 30, 2017.

During the nine months ended September 30, 2017 (Successor), the Company granted 2.0 million shares of restricted stock under the 2016 Incentive 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 (Successor), 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.

During the period from September 10, 2016 through September 30, 2016 (Successor), the Company granted 2.6 million shares of restricted stock under the 2016 Incentive Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $7.82 to $9.24 per share with a weighted average price of $9.17 per share. At September 30, 2016 (Successor), the Company had $12.0 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 0.9 years. Immediately prior to emergence from chapter 11 bankruptcy, all restricted stock awards granted under the Predecessor Incentive Plan were vested. Refer to Note 2, "Reorganization," for further details.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. EARNINGS PER COMMON SHARE

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the Company's Predecessor equity was cancelled and new equity was issued. Refer to Note 2, "Reorganization," for further details.

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

	Successor					Predecessor

			Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016
	Three Months Ended September 30, 2017


Basic:
Net income (loss) available to common stockholders	$	419,287	$	(451,483	)	$	916,421



Weighted average basic number of common shares outstanding		146,944		91,071			120,905

Basic net income (loss) per share of common stock	$	2.85	$	(4.96	)	$	7.58



Diluted:
Net income (loss) available to common stockholders	$	419,287	$	(451,483	)	$	916,421



Interest on Convertible Note, net		—		—			1,522
Series A preferred dividends		—		—			2,451

Net income (loss) available to common stockholders after assumed conversions	$	419,287	$	(451,483	)	$	920,394



Weighted average basic number of common shares outstanding		146,944		91,071			120,905
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive		Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		—		—			Anti-dilutive
Exercise of warrants		Anti-dilutive		Anti-dilutive			—
Vesting of restricted shares		1,546		Anti-dilutive			Anti-dilutive
Vesting of performance units		—		—			—
Conversion of preferred stock		—		—			—
Conversion of Convertible Note		—		—			23,743
Conversion of Series A Preferred Stock		—		—			7,228

Weighted average diluted number of common shares outstanding		148,490		91,071			151,876

Diluted net income (loss) per share of common stock	$	2.82	$	(4.96	)	$	6.06

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. EARNINGS PER COMMON SHARE (Continued)

	Successor					Predecessor

			Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
	Nine Months Ended September 30, 2017


Basic:
Net income (loss) available to common stockholders	$	580,809	$	(451,483	)	$	(32,794	)



Weighted average basic number of common shares outstanding		127,458		91,071			120,513

Basic net income (loss) per share of common stock	$	4.56	$	(4.96	)	$	(0.27	)



Diluted:
Net income (loss) available to common stockholders	$	580,809	$	(451,483	)	$	(32,794	)



Weighted average basic number of common shares outstanding		127,458		91,071			120,513
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive		Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		—		—			Anti-dilutive
Exercise of warrants		Anti-dilutive		Anti-dilutive			—
Vesting of restricted shares		952		Anti-dilutive			Anti-dilutive
Vesting of performance units		—		—			—
Conversion of preferred stock		Anti-dilutive					—
Conversion of Convertible Note		—		—			Anti-dilutive
Conversion of Series A Preferred Stock		—		—			Anti-dilutive

Weighted average diluted number of common shares outstanding		128,410		91,071			120,513

Diluted net income (loss) per share of common stock	$	4.52	$	(4.96	)	$	(0.27	)

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 (Successor), respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

Common stock equivalents, including stock options, warrants, restricted shares, convertible debt and preferred stock totaling 11.1 million, 11.9 million and 43.6 million shares for the period from September 10, 2016 through September 30, 2016 (Successor), the period from July 1, 2016 through September 9, 2016 (Predecessor), and the period from January 1, 2016 through September 9, 2016 (Predecessor), 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)

13. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

	Successor

	September 30, 2017		December 31, 2016
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	74,645	$	86,433
Joint interest accounts		27,637		39,828
Accrued settlements on derivative contracts		673		18,599
Affiliated partnership		11		268
Other		5,787		2,634

	$	108,753	$	147,762



Prepaids and other:
Prepaids	$	5,856	$	6,704
Income tax receivable		6,250		—
Other		65		236

	$	12,171	$	6,940



Funds in escrow and other:
Funds in escrow	$	562	$	561
Debt issuance costs		479		—
Other		1,367		1,326

	$	2,408	$	1,887



Accounts payable and accrued liabilities:
Trade payables	$	32,911	$	24,364
Accrued oil and natural gas capital costs		64,427		32,967
Revenues and royalties payable		47,926		79,147
Accrued interest expense		7,377		31,146
Accrued employee compensation		8,158		3,428
Accrued lease operating expenses		8,924		14,077
Drilling advances from partners		922		422
Income tax payable		—		250
Affiliated partnership		22		323
Other		1,345		60

	$	172,012	$	186,184

14. SUBSEQUENT EVENTS

Divestiture of Williston Basin Non-Operated Assets

On September 19, 2017 (Successor), certain wholly owned subsidiaries of the Company entered into an Agreement of Sale and Purchase with a privately-owned company pursuant to which the Company agreed to sell 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 purchase price of approximately $105.2 million, subject to post-closing adjustments. The effective date of the transaction

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. SUBSEQUENT EVENTS (Continued)

is April 1, 2017 and the transaction closed on November 9, 2017. The purchase price is subject to post-closing adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Upon the closing of the sale of the Non-Operated Williston Assets, the borrowing base on the Company's Senior Credit Agreement was reduced from $140.0 million to $100.0 million.

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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, 2017 (Successor) and the period of September 10, 2016 through September 30, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor) 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, 2016, though as described below, our financial statements for prior periods may not be comparable due to our adoption of fresh-start accounting on September 9, 2016. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

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. As discussed below in more detail under "Recent Developments," we have recently acquired certain properties in the Delaware Basin, divested our operated assets located in the Williston Basin and assets located in the El Halcón area of East Texas. 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 discussed under "Recent Developments, " 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 slightly in the first nine months of 2017 (Successor) when compared to the same period in the prior year due to the El Halcón Divestiture, discussed under "Recent Developments," on March 9, 2017 and the Williston Divestiture on September 7, 2017. This decrease was partially mitigated by the production associated with the acquisition of the Pecos County Assets on February 28, 2017. During the first nine months of 2017 (Successor), production averaged 34,513 Boe/d compared to average daily production of 33,333 Boe/d and 36,787 Boe/d during the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. During the first nine months of 2017 (Successor), we participated in the drilling of 75 gross (12.6 net) wells, all of which were completed and capable of production.

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

Oil and natural gas prices are inherently volatile and have declined dramatically since mid-year 2014. In response to this, in 2015 and 2016 we significantly curtailed our capital spending, reduced

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operating costs, concluded discounted debt exchanges, and incurred substantial asset impairments, primarily as a result of the full cost ceiling test calculation. Despite these efforts low commodity prices persisted and we decided to reorganize under Chapter 11 on September 9, 2016, as discussed in greater detail below.

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, 2017 of $51.67 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. Sustained lower commodity prices would have a material impact upon our full cost ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

Divestiture of Williston Basin Non-Operated Assets

On September 19, 2017 (Successor), certain of our wholly owned subsidiaries entered into an Agreement of Sale and Purchase with a privately-owned company pursuant to which we agreed to sell our 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 purchase price of approximately $105.2 million, subject to post-closing adjustments. The effective date of the transaction is April 1, 2017 and the transaction closed on November 9, 2017. The purchase price is subject to post-closing adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Upon the closing of the sale of the Non-Operated Williston Assets, the borrowing base on our Senior Credit Agreement was reduced from $140.0 million to $100.0 million.

Divestiture of Williston Basin Operated Assets

On July 10, 2017 (Successor), we and certain of our subsidiaries (the Sellers) entered into an Agreement of Sale and Purchase (the Purchase Agreement) with Bruin Williston Holdings, LLC (the Purchaser) for the sale of all of our 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 our subsidiaries (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion, subject to post-closing adjustments (the Williston Divestiture). The effective date of the sale was June 1, 2017, and we closed the transaction on September 7, 2017. Estimated proved reserves associated with these properties accounted for approximately 104.9 MMBoe, or approximately 71% of our year-end 2016 proved reserves. The Williston Assets generated net production of approximately 26,180 Boe/d, or approximately 76% of our average daily production during the nine months ended September 30, 2017. We are using the proceeds from the sale to repay borrowings outstanding under our Senior Credit Agreement, repurchase $425.0 million principal amount of the outstanding $850.0 million principal amount of our 6.75% senior unsecured notes due 2025 (the 2025 Notes), and redeem all of our outstanding 12% second lien notes, along with general corporate purposes.

The sales price is subject to post-closing adjustments for (i) proration of expenses, capital expenditures and revenues as of the effective time, (ii) title and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. We use the full cost method of accounting for our investment in oil and natural gas properties. Under this method of

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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, we recognized a gain on the sale of $491.8 million during the three months ended September 30, 2017 (Successor). 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 the sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

Amended and Restated Senior Secured Revolving Credit Agreement

On September 7, 2017 (Successor), 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. The Senior Credit Agreement amends and restates in its entirety the original Senior Secured Revolving Credit Agreement entered into on September 9, 2016. 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 $100.0 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 next scheduled redetermination date is May 2018. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.25% 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 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) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00.

Repurchase of 2025 Notes

On September 7, 2017 (Successor), we commenced an offer to purchase for cash up to $425.0 million of the $850.0 million outstanding aggregate principal amount of our 2025 Notes at 103.0% of principal plus accrued and unpaid interest. The consummation of the Williston Divestiture constituted a "Williston Sale" under the indenture governing the 2025 Notes dated as of February 16, 2017 (as supplemented, the February 2017 Indenture). Pursuant to the February 2017 Indenture, we were 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 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, we repurchased in cash $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest.

Redemption of 2022 Second Lien Notes

On September 7, 2017 (Successor), we issued an irrevocable notice to redeem the outstanding aggregate principal amount of our 12.0% second lien notes due 2022 (the 2022 Second Lien Notes) on October 7, 2017 (the Redemption Date). In accordance with the terms of the indenture governing the 2022 Second Lien Notes, all of the outstanding 2022 Second Lien Notes were redeemed at a

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redemption price equal to the principal amount of $112.8 million plus a make whole premium of approximately $23.0 million and accrued and unpaid interest of approximately $2.0 million. 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. The payment of the redemption price and accrued interest to a holder of 2022 Second Lien Notes became due and payable on the Redemption Date upon presentation and surrender by the holder of such notes.

Issuance of 2025 Senior Notes and Repurchase of 2020 Second Lien Notes

On February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of 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, beginning on August 15, 2017. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers' discounts and commissions and offering expenses. We utilized a portion of the net proceeds from the private placement to fund the repurchase and redemption of the outstanding 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes), discussed further below, and for general corporate purposes.

On February 9, 2017 (Successor), we commenced a cash tender offer for any and all of our 2020 Second Lien Notes and on February 15, 2017, we received approximately $289.2 million or 41% of the outstanding aggregate principal amount of the 2020 Second Lien Notes which were validly tendered (and not validly withdrawn). As a result, on February 16, 2017 (Successor), we paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes pursuant to the tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. On February 21, 2017 (Successor), we paid approximately $1.2 million for approximately $1.2 million of principal amount of 2020 Second Lien Notes, a make-whole premium of approximately $54,000 plus accrued and unpaid interest to repurchase such notes pursuant to guaranteed delivery procedures of the tender offer. On March 20, 2017 (Successor), we paid approximately $432.0 million for $409.6 million aggregate principal amount of 2020 Second Lien Notes, a make-whole premium of $17.7 million and unpaid interest of approximately $4.8 million to redeem the remaining notes at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date.

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.

Divestiture of East Texas Eagle Ford Assets

On January 24, 2017 (Successor), certain of our subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of our oil and natural gas 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. We used the net proceeds from the sale to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes. The sale properties included approximately 80,500 net acres prospective

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for the Eagle Ford formation in East Texas. As of December 31, 2016 (Successor), estimated proved reserves from these properties were approximately 35.1 MMBoe, or 24% of our estimated year-end 2016 proved reserves. The sale included approximately 191 gross (135 net) wells that produced approximately 7,600 Boe/d (80% oil) for the year ended December 31, 2016 (Successor).

We use the full cost method of accounting for our investment in oil and natural gas properties. Under this 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, we recognized a gain on the sale of $235.7 million during the nine months ended September 30, 2017 (Successor). 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 unaudited condensed consolidated statements of operations.

Private Placement of Automatically Convertible Preferred Stock

On January 24, 2017 (Successor), we 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 is convertible into 10,000 shares of common stock. Also on January 24, 2017 (Successor), we 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 (Successor), we 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 us on that same date. We issued the Preferred Stock at $72,500 per share. Gross proceeds were approximately $400.1 million, or $7.25 per share of common stock. We incurred approximately $11.9 million in expenses associated with this offering, including placement agent fees. We used the net proceeds from the sale of the Preferred Stock to partially fund the Pecos County Acquisition, which is discussed further below.

On March 16, 2017 (Successor), we mailed a definitive information statement to our common stockholders notifying them that a majority of our 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 April 6, 2017 (Successor) 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.

We determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature of $48.0 million. This portion 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 $48.0 million discount was fully amortized during the six months ended June 30, 2017 (Successor) and 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.

We also agreed to file a registration statement to register the resale of the shares of common stock issuable upon conversion of the preferred stock and to pay penalties in the event such registration was

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not effective by June 27, 2017. We filed such registration statement on March 3, 2017 and it was declared effective by the SEC on April 7, 2017.

Acquisition of Delaware Basin Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017 (Successor), we entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which we agreed to acquire a total of 20,901 net acres 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 purchase price of $699.2 million (the Pecos County Acquisition). The effective date of the acquisition was November 1, 2016, and we closed the transaction on February 28, 2017. Based on information provided by Samson, we estimate that net production from the Pecos County Assets at the acquisition date was approximately 2,200 Boe/d (72% oil, 15% NGLs, 13% natural gas). We estimate that the Pecos County Assets include a 75% average working interest, with approximately 44% held by production. We are currently operating one rig in the Hackberry Draw. We funded the Pecos County Acquisition with the net proceeds from the private placement of the Preferred Stock and borrowings under our Senior Credit Agreement.

Option Agreement to Acquire Delaware Basin Assets (Ward County, Texas)

On December 9, 2016 (Successor), we entered into an agreement with a private company for the right 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 for an initial purchase price of $11,000 per acre. The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. The agreement was subsequently amended on June 14, 2017 (Successor) to increase the purchase price of the Southern and 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, we initially paid $5.0 million and drilled a commitment well on the Southern Tract and on June 15, 2017 (Successor) purchased the Southern Tract acreage for approximately $13,000 per acre. On June 15, 2017 (Successor), we also paid $5.0 million and recently drilled a commitment well on the Northern Tract, to earn the option to acquire the Northern Tract acreage for $13,000 per acre by December 31, 2017.

Reorganization

The prices of crude oil and natural gas declined dramatically beginning mid-year 2014, before reaching multi-year lows in 2016, as a result of robust non-Organization of the Petroleum Exporting Countries' (OPEC) supply growth led by unconventional production in the United States, weakening demand in emerging markets, and OPEC's production levels. In response to these developments, among other things, in 2015 and 2016 we reduced our spending and completed a series of transactions that resulted in the reduction of our debt by approximately $1.1 billion and reduced our annual interest burden by approximately $61.5 million. We also extended the maturity date and amended other provisions of certain of our debt agreements.

These efforts proved insufficient in light of continued low commodity prices to ensure our ability to weather the downturn or position us to take advantage of opportunities that might arise. Accordingly, on July 27, 2016, we and certain of our subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a prepackaged plan of reorganization in accordance with the terms of the Restructuring Support Agreement discussed below. Prior to filing the chapter 11 bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of our 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), our 8.875% senior

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unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of our 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of our 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders), to support a restructuring in accordance with the terms of a plan of reorganization as described therein (the Plan). On September 8, 2016, the Halcón Entities received confirmation of their joint prepackaged plan of reorganization from the Bankruptcy Court and subsequently emerged from chapter 11 bankruptcy on September 9, 2016 (the Effective Date).

Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred:

•: the Predecessor Credit Agreement was refinanced and replaced with a debtor-in-possession senior secured, super-priority revolving credit facility, which was subsequently converted into the Senior Credit Agreement (see above for further details regarding the Senior Credit Agreement);
•: the Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) were unimpaired and reinstated;
•: the Third Lien Notes were cancelled and the Third Lien Noteholders received their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016, which was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;
•: the Unsecured Notes were cancelled and the Unsecured Noteholders received their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), and accrued and unpaid interest on their notes through May 15, 2016, in full and final satisfaction of their claims;
•: the Convertible Note was cancelled and the Convertible Noteholder received 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims;
•: the general unsecured claims were unimpaired and paid in full in the ordinary course;
•: all outstanding shares of the preferred stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and
•: all of the outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests.

Each of the foregoing percentages of equity in the reorganized company were as of September 9, 2016 and are subject to dilution from the exercise of the new warrants described above, a management incentive plan and other future issuances of equity securities.

Fresh-start Accounting

Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in ASC 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the

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Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to "Reorganization" above for the terms of our reorganization under the Plan.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we will have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our unaudited condensed consolidated financial statements subsequent to September 9, 2016 are not comparable to our unaudited condensed consolidated financial statements prior to September 9, 2016, as such, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies.

HK TMS Divestiture

On September 30, 2016 (Successor), certain of our wholly-owned subsidiaries executed an Assignment and Assumption Agreement with an affiliate of Apollo Global Management (Apollo) pursuant to which Apollo acquired one hundred percent (100%) of the common shares (the Membership Interests) of HK TMS, LLC (HK TMS), which transaction is referred to as the HK TMS Divestiture. HK TMS was previously a wholly-owned subsidiary of ours and held all of our oil and natural gas properties in the Tuscaloosa Marine Shale (TMS). In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests. The TMS properties generated net production of approximately 530 Boe/d during the nine months ended September 30, 2016 and had 1.1 MMBoe of proved reserves at December 31, 2015 (Predecessor).

Capital Resources and Liquidity

Our near-term capital spending requirements are expected to be funded with cash flows from operations, cash on hand and borrowings under our Senior Credit Agreement, the terms of which are discussed above. 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) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00. At September 30, 2017 (Successor), under the effective borrowing base of $140.0 million, we had no indebtedness outstanding, $6.4 million letters of credit outstanding and approximately $133.6 million of borrowing capacity available under our Senior Credit Agreement. At September 30, 2017, we were in compliance with the financial covenants under the Senior Credit Agreement.

We have in the past obtained amendments 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. For example, under our Predecessor Senior Credit Agreement, we received a reduction in the minimum required interest coverage ratio of 2.0 to 1.0 on March 21, 2014 and again on February 25, 2015. 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. Declining commodity prices also adversely impacted our ability to comply with these covenants. As part of our plan to manage liquidity risks, we scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties and completed our reorganization (as described above). Upon emergence from reorganization under chapter 11, approximately $2.0 billion of our debt obligations were cancelled, reducing our ongoing interest obligations by more than $200 million annually. In the first three months of 2017, we completed the issuance of our 2025 Notes and repurchased the remaining 2020 Second Lien Notes, lowering our interest obligations approximately $3.0 million per year and extending the

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maturity date of our senior notes from 2020 to 2025. Additionally, we utilized a portion of the proceeds from the Williston Divestiture to redeem all of our outstanding 2022 Second Lien Notes and to repurchase one-half of our outstanding 2025 Notes, which will lower our future interest obligations by approximately $42.2 million per year.

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.

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

We strive to maintain financial flexibility while pursuing our drilling plans and evaluating potential acquisitions, and will continue to access capital markets (if on acceptable terms) as necessary to, among other things, maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects while sustaining sufficient operating cash levels. Our ability to complete future debt and equity offerings and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, reserves and commodity prices, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

Cash Flow

In the first nine months of 2017, cash generated by operating and financing activities, as well as proceeds from the sale of the Williston and El Halcón Assets, were used to fund our acquisition initiatives, primarily the acquisition of the Pecos County Assets, and our drilling and completion program. See "Results of Operations" for a review of the impact of prices and volumes on sales.

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

	Successor					Predecessor

			Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
	Nine Months Ended September 30, 2017


Cash flows provided by (used in) operating activities	$	102,222	$	12,322		$	175,348
Cash flows provided by (used in) investing activities		737,760		(12,241	)		(227,774	)
Cash flows provided by (used in) financing activities		149,341		(12,013	)		58,343

Net increase (decrease) in cash	$	989,323	$	(11,932	)	$	5,917

Operating Activities. Net cash provided by operating activities for the nine months ended September 30, 2017 (Successor) were $102.2 million compared to $12.3 million and $175.3 million generated during the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs and historically, realized settlements on our derivative contracts.

The $102.2 million of operating cash flows for the nine months ended September 30, 2017 (Successor) 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 operating revenues, as well as decreases in cash paid for interest and general and administrative expenses.

For the period September 10, 2016 through September 30, 2016 (Successor), cash flows were modestly impacted by changes in our working capital. For the period January 1, 2016 through September 9, 2016 (Predecessor) our net operating cash flows were $175.3 million, which included $245.7 million of realized settlements on our derivative contracts, offset by transaction costs related to our chapter 11 bankruptcy and reorganization activities.

Investing Activities. Net cash provided by investing activities for the nine months ended September 30, 2017 (Successor) was approximately $737.8 million compared to net cash used in investing activities of $12.2 million and $227.8 million for the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

During the first nine months of 2017 (Successor), we incurred cash expenditures of $700.1 million to acquire 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 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 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 sale of the El Halcón Assets 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.

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During the period of September 10, 2016 through September 30, 2016 (Successor), we spent $10.3 million on oil and natural gas capital expenditures, of which $9.2 million related to drilling and completion costs. During the period January 1, 2016 through September 9, 2016 (Predecessor), we spent $226.6 million on oil and natural gas capital expenditures, of which $129.5 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, and to a lesser extent, leasing and seismic data.

Financing Activities. Net cash flows provided by financing activities for the nine months ended September 30, 2017 (Successor) were approximately $149.3 million compared to net cash flows used in financing activities of $12.0 million for the period of September 10, 2016 through September 30, 2016 (Successor) and net cash flows provided by financing activities of $58.3 million for the period of January 1, 2016 through September 9, 2016 (Predecessor).

During the first nine months of 2017 (Successor) 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 our 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 (Successor), we utilized a portion of the proceeds from the Williston Divestiture to redeem all of our outstanding 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 the Preferred Stock at $72,500 per share. Gross proceeds from this issuance were approximately $400.1 million.

During the period September 10, 2016 through September 30, 2016 (Successor), we paid a consent fee of approximately $10.0 million to our Second Lien Noteholders. The primary drivers of cash provided by financing activities for the period of January 1, 2016 through September 9, 2016 (Predecessor) were net borrowings on our Predecessor Credit Agreement, offset by cash payments totaling $97.5 million made to the Third Lien Noteholders, Unsecured Noteholders, Convertible Noteholder and Preferred Holders in accordance with the Plan.

During the first quarter of 2016 (Predecessor), we repurchased approximately $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022. The net cash used to make these repurchases was approximately $9.7 million and we recognized an $81.4 million net gain on the extinguishment of debt, as an $82.1 million gain on the repurchase was partially offset by the writedown of $0.7 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the senior unsecured notes repurchased.

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Contractual Obligations

The following summarizes our contractual obligations and commitments by payment periods as of September 30, 2017 (Successor) (in thousands):

	Payments Due by Period

Contractual Obligations	Total		Remaining period in 2017		Years 2018 - 2019		Years 2020 - 2021		Years 2022 and Beyond
Senior revolving credit facility	$	—	$	—	$	—	$	—	$	—
6.75% senior notes due 2025(1)		850,000		425,000		—		—		425,000
Interest expense on long-term debt(2)		215,268		7,817		58,712		58,712		90,027
Operating leases		12,647		830		6,329		3,308		2,180
Drilling rig commitments(3)		4,418		2,378		2,040		—		—
Rig stacking commitments		5,226		966		1,260		3,000		—

Total contractual obligations	$	1,087,559	$	436,991	$	68,341	$	65,020	$	517,207

(1): On October 10, 2017, we repurchased $425.0 million principal amount of the 2025 Notes at 103.0% of par plus accrued and unpaid interest. Excludes a $16.7 million unamortized discount and $15.6 million unamortized debt issuance costs.
(2): Future interest expense was calculated based on interest rates and amounts outstanding at September 30, 2017 less required annual repayments. It includes approximately $0.5 million of interest accrued on the $425.0 million principal amount of 2025 Notes which were redeemed on October 10, 2017.
(3): Early termination of our drilling rig commitments would result in termination penalties approximating $1.7 million, which would be in lieu of paying the remaining active commitments of approximately $4.4 million.

We lease corporate office space in Houston, Texas and Denver, Colorado as well as other field office locations. Rent expense was approximately $3.0 million for the nine months ended September 30, 2017 (Successor). Rent expense was approximately $0.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and $5.9 million for the period January 1, 2016 through September 30, 2016 (Predecessor).

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, 2017 (Successor), we had in place two long-term crude oil contracts and four long-term natural gas contracts in this area. Under

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the terms of these contracts, we have committed a substantial portion of our production from this area for periods ranging from one to eight years from the date of first production. The sales prices under these contracts are based on posted market rates.

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, 2016.

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Results of Operations

Three Months Ended September 30, 2017 and 2016

The table included below sets forth financial information for the periods presented. As a result of our application of fresh-start accounting upon our emergence from chapter 11 bankruptcy, on September 9, 2016, our financial results are not comparable to prior periods.

	Successor						Predecessor

				Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016
	Three Months Ended September 30, 2017

In thousands (except per unit and per Boe amounts)
Net income (loss)	$	419,287		$	(450,692	)	$	926,260
Operating revenues:
Oil		88,256			21,260			74,002
Natural gas		2,886			823			2,610
Natural gas liquids		5,448			798			2,488
Other		363			226			247
Operating expenses:
Production:
Lease operating		17,798			3,791			12,473
Workover and other		3,644			1,565			6,801
Taxes other than income		6,846			2,173			7,442
Gathering and other		10,886			2,637			7,376
Restructuring		1,275			—			95
General and administrative:
General and administrative		26,937			3,485			16,093
Share-based compensation		12,258			13,196			1,224
Depletion, depreciation and accretion:
Depletion—Full cost		34,336			8,716			24,115
Depreciation—Other		1,230			204			1,120
Accretion expense		374			131			383
Full cost ceiling impairment		—			420,934			—
(Gain) loss on sale of oil and natural gas properties		(491,830	)		—			—
Other income (expenses):
Net gain (loss) on derivative contracts		(22,415	)		(7,575	)		17,783
Interest expense and other, net		(19,330	)		(5,479	)		(16,136	)
Reorganization items		—			(556	)		913,722
Gain (loss) on extinguishment of debt		(29,167	)		—			—
Income tax benefit (provision)		17,000			(3,357	)		8,666
Production:
Oil—MBbls		2,007			533			1,844
Natural Gas—Mmcf		1,874			521			1,718
Natural gas liquids—MBbls		335			80			315
Total MBoe(1)		2,655			700			2,445
Average daily production—Boe/d(1)		28,859			33,333			34,437
*Average price per unit(2)***:
Oil price—Bbl	$	43.97		$	39.89		$	40.13
Natural gas price—Mcf		1.54			1.58			1.52
Natural gas liquids price—Bbl		16.26			9.98			7.90
Total per Boe(1)		36.38			32.69			32.35
Average cost per Boe:
Production:
Lease operating	$	6.70		$	5.42		$	5.10
Workover and other		1.37			2.24			2.78
Taxes other than income		2.58			3.10			3.04
Gathering and other		4.10			3.77			3.02
Restructuring		0.48			—			0.04
General and administrative:
General and administrative		10.15			4.98			6.58
Share-based compensation		4.62			18.85			0.50
Depletion		12.93			12.45			9.86

(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.

Oil, natural gas and natural gas liquids revenues were $96.6 million, $22.9 million and $79.1 million for three months ended September 30, 2017 (Successor), the period of September 10, 2016 through

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September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. Average realized prices (excluding the effects of hedging arrangements) were $36.38 per Boe, $32.69 per Boe and $32.35 per Boe for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. Oil and natural gas prices are inherently volatile and have decreased significantly since early 2014 levels with only modest increases in 2017. Our average daily oil and natural gas production decreased in the three months ended September 30, 2017 (Successor) when compared to the same period in the prior year due to the El Halcón Divestiture in the first quarter of 2017 and the Williston Divestiture in the third quarter of 2017. This decrease was partially mitigated by the production associated with the acquisition of the Pecos County Assets and our drilling activities since acquiring the assets.

Lease operating expenses were $17.8 million, $3.8 million and $12.5 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. The increase in lease operating expenses during 2017 relates to costs in our Bakken/Three Forks area, where we have increased our well inventory over the prior year period, and repairs, maintenance and operational improvements on wells acquired in the Pecos County Acquisition. On a per unit basis, lease operating expenses were $6.70 per Boe, $5.42 per Boe and $5.10 per Boe for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively.

Workover and other expenses were $3.6 million, $1.6 million and $6.8 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. The decreased costs in 2017 are attributable to our Bakken/Three Forks area where the workover rig count has decreased. On a per unit basis, workover and other expenses were $1.37 per Boe, $2.24 per Boe and $2.78 per Boe for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively.

Taxes other than income were $6.8 million, $2.2 million and $7.4 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), 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 $2.58 per Boe, $3.10 per Boe and $3.04 per Boe for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively.

Gathering and other expenses were $10.9 million, $2.6 million and $7.4 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. Gathering and other expenses include gathering fees paid on our oil and natural gas production as well as rig termination or stacking charges incurred. Approximately $7.6 million, $1.8 million and $4.9 million of expenses incurred for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively, relate to gathering and other fees paid on our oil and natural gas production. Also included are $1.3 million, $0.7 million and $2.3 million of rig stacking or termination charges for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively.

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During the three months ended September 30, 2017 (Successor), we incurred approximately $1.3 million in severance costs related to the termination of certain employees in conjunction with the Williston Divestiture. For the period of September 10, 2016 through September 30, 2016 (Successor) and July 1, 2016 through September 9, 2016 (Predecessor), we incurred zero and $0.1 million, respectively, in severance costs related to reductions in our workforce.

General and administrative expense was $26.9 million, $3.5 million and $16.1 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. The increase in general and administrative expense from the prior year period is primarily due to $8.4 million of transaction costs paid in conjunction with the Williston Divestiture. On a per unit basis, general and administrative expenses were $10.15 per Boe, $4.98 per Boe and $6.58 per Boe for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively.

Share-based compensation expense was $12.3 million, $13.2 million and $1.2 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. Share-based compensation expense decreased from the prior year period due to forfeitures in the current year period.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. On a per unit basis, depletion expense was $12.93 per Boe, $12.45 per Boe and $9.86 per Boe for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. The increase in depletion expense and the depletion rate per Boe from 2016 levels is due to the El Halcón and Williston Divestitures.

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling", based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves using the first-day-of-the-month average price for the 12-months ended September 30, 2017. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. As of September 30, 2017 (Successor), the net book value of oil and natural gas properties did not exceed the ceiling amount. We recorded a full cost ceiling test impairment before income taxes of $420.9 million for the period of September 10, 2016 through September 30, 2016 (Successor). The impairment at September 30, 2016 primarily reflects the pricing differences between the first-day-of-the-month average price for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date of September 9, 2016. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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Accordingly, we recognized a gain on the sale of $491.8 million during the three months ended September 30, 2017 (Successor). 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 and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2017 (Successor), we had a $6.6 million derivative asset, $5.2 million of which was classified as current and we had a $5.5 million derivative liability, $3.3 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $22.4 million ($31.2 million net unrealized loss and $8.8 million net realized gain on settled contracts) for the three months ended September 30, 2017 (Successor) compared to a net derivative loss of $7.6 million ($30.3 million net unrealized loss and $22.7 million net realized gain on settled contracts) and a net derivative gain of $17.8 million ($39.4 million net unrealized loss and $57.2 million net realized gain on settled contracts) for the period of September 10, 2016 through September 30, 2016 (Successor) and for the period of July 1, 2016 through September 10, 2016 (Predecessor), respectively.

Interest expense and other was $19.3 million, $5.5 million and $16.1 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. Capitalized interest for the three months ended September 30, 2017 (Successor) and the period of September 10, 2016 through September 30, 2016 (Successor) was zero. Capitalized interest for the period of July 1, 2016 through September 9, 2016 (Predecessor) was $15.2 million and gross interest expense was $39.6 million. The decrease in gross interest expense in 2017 was primarily due to the discontinuance of interest on our senior notes that were cancelled as part of our reorganization under chapter 11.

We incurred reorganization expense of $0.6 million and a reorganization gain of $913.7 million for the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. The Successor expense was associated with legal and professional fees directly attributable to the chapter 11 bankruptcy. The Predecessor gain resulted from the gain on the discharge of debt and fresh-start adjustments upon emergence from chapter 11 bankruptcy.

We recorded an income tax benefit of $17.0 million for the three months ended September 30, 2017 (Successor) 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. We recorded an income tax provision of $3.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and an income tax benefit of $8.7 million for the period of July 1, 2016 through September 9, 2016 (Predecessor) related to our estimated 2016 alternative minimum tax liability and the reversal of the Predecessor 2015 alternative minimum tax liability, respectively.

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Nine Months Ended September 30, 2017 and 2016

	Successor						Predecessor

				Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
	Nine Months Ended September 30, 2017
In thousands (except per unit and per Boe amounts)
In thousands (except per unit and per Boe amounts)
Net income (loss)	$	628,816		$	(450,692	)	$	11,958
Operating revenues:
Oil		319,472			21,260			248,064
Natural gas		15,051			823			9,511
Natural gas liquids		16,779			798			7,929
Other		1,386			226			1,339
Operating expenses:
Production:
Lease operating		58,822			3,791			50,032
Workover and other		22,213			1,565			22,507
Taxes other than income		29,149			2,173			24,453
Gathering and other		34,640			2,637			29,279
Restructuring		2,080			—			5,168
General and administrative:
General and administrative		53,418			3,485			78,765
Share-based compensation		33,548			13,196			4,876
Depletion, depreciation and accretion:
Depletion—Full cost		96,141			8,716			114,775
Depreciation—Other		3,417			204			4,366
Accretion expense		1,230			131			1,414
Full cost ceiling impairment		—			420,934			754,769
(Gain) loss on sale of oil and natural gas properties		(727,520	)		—			—
Other operating property and equipment impairment		—			—			28,056
Other income (expenses):
Net gain (loss) on derivative contracts		28,139			(7,575	)		(17,998	)
Interest expense and other, net		(63,808	)		(5,479	)		(122,249	)
Reorganization items		—			(556	)		913,722
Gain (loss) on extinguishment of debt		(86,065	)		—			81,434
Income tax benefit (provision)		5,000			(3,357	)		8,666
Production:
Oil—MBbls		7,108			533			7,118
Natural Gas—Mmcf		6,892			521			6,560
Natural gas liquids—MBbls		1,165			80			1,096
Total MBoe(1)		9,422			700			9,307
Average daily production—Boe(1)		34,513			33,333			36,787
*Average price per unit(2)***:
Oil price—Bbl	$	44.95		$	39.89		$	34.85
Natural gas price—Mcf		2.18			1.58			1.45
Natural gas liquids price—Bbl		14.40			9.98			7.23
Total per Boe(1)		37.29			32.69			28.53
Average cost per Boe:
Production:
Lease operating	$	6.24		$	5.42		$	5.38
Workover and other		2.36			2.24			2.42
Taxes other than income		3.09			3.10			2.63
Gathering and other		3.68			3.77			3.15
Restructuring		0.22			—			0.56
General and administrative:
General and administrative		5.67			4.98			8.46
Share-based compensation		3.56			18.85			0.52
Depletion		10.20			12.45			12.33

(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 $351.3 million, $22.9 million and $265.5 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. Average realized prices (excluding the effects of hedging arrangements) were $37.29 per Boe, $32.69 per Boe and $28.53 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. Oil and natural gas prices are inherently volatile and have decreased significantly since early 2014 levels with only modest increases in 2017. Our average daily oil and natural gas production decreased slightly in the first nine months of 2017 (Successor) when compared to the same period in the prior year due to the El Halcón Divestiture in the first quarter of 2017 and the Williston Divestiture in the third quarter of 2017. This decrease was partially mitigated by the production associated with the acquisition of the Pecos County Assets in the first quarter of 2017 and our drilling activities since acquiring the assets.

Lease operating expenses were $58.8 million, $3.8 million and $50.0 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. The increase in lease operating expenses during 2017 relates to costs in our Bakken/Three Forks area, where we have increased our well inventory over the prior year period, and repairs, maintenance and operational improvements on wells acquired in the Pecos County Acquisition. On a per unit basis, lease operating expenses were $6.24 per Boe, $5.42 per Boe and $5.38 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

Workover and other expenses were $22.2 million, $1.6 million and $22.5 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. The decreased costs in 2017 are attributable to our Bakken/Three Forks area where the workover rig count has decreased. On a per unit basis, workover and other expenses were $2.36 per Boe, $2.24 per Boe and $2.42 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

Taxes other than income were $29.1 million, $2.2 million and $24.5 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), 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 $3.09 per Boe, $3.10 per Boe and $2.63 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

Gathering and other expenses were $34.6 million, $2.6 million and $29.3 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. Gathering and other expenses include gathering fees paid on our oil and natural gas production as well as rig termination or stacking charges incurred. Approximately $25.6 million, $1.8 million and $19.8 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively, relate to gathering and other fees paid on our oil and natural gas production. Also included are $5.9 million, $0.7 million and

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$8.8 million of rig stacking or termination charges for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

During the nine months ended September 30, 2017 (Successor), we incurred $2.1 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in conjunction with the El Halcón and Williston Divestitures. For the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), we incurred zero and $5.2 million, respectively, in severance costs and accelerated stock-based compensation expense related to reductions in our workforce.

General and administrative expense was $53.4 million, $3.5 million and $78.8 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. General and administrative expense in the prior year period included fees associated with the effort to restructure our indebtedness, costs associated with key employee retention agreements and settlements of disputes with lease brokers and warrant holders. The decrease from the prior year period is also a result of a reduction in our workforce and office lease expenses. On a per unit basis, general and administrative expenses were $5.67 per Boe, $4.98 per Boe and $8.46 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

Share-based compensation expense was $33.5 million, $13.2 million and $4.9 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. Share-based compensation expense increased from the Predecessor period due to equity awards made since our emergence from reorganization under chapter 11.

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. On a per unit basis, depletion expense was $10.20 per Boe, $12.45 per Boe and $12.33 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. The decrease in depletion expense and the depletion rate per Boe from 2016 levels is attributable to decreases in the amortizable base due to our full cost ceiling test impairments recorded in 2016.

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reporting date, September 9, 2016. We recorded a full cost ceiling test impairment before income taxes of $754.8 million for the period January 1, 2016 through September 9, 2016 (Predecessor). The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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 and El Halcón Divestitures were accounted for as adjustments of capitalized costs with no gain or loss recognized, the adjustments would have significantly altered the relationship between capitalized costs and proved reserves at the time of each of the transactions. Accordingly, we recognized a gain on the sale of the Williston Assets of $491.8 million during the three months ended September 30, 2017 (Successor). We recognized a gain on the sale of the El Halcón Assets of $235.7 million during the nine months ended September 30, 2017 (Successor). 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 review our other operating property and equipment for impairment in accordance with ASC 360. For the period of January 1, 2016 through September 9, 2016 (Predecessor), we recorded a non-cash impairment charge of $28.1 million. The impairment related to our gross investments of $32.8 million in gas gathering infrastructure that were not likely to be economically recoverable at that point in time due to our shift in exploration, drilling and developmental plans for 2016 to our most economic areas as a result of the low commodity price environment.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2017 (Successor), we had a $6.6 million derivative asset, $5.2 million of which was classified as current and we had a $5.5 million derivative liability, $3.3 million of which was classified as current associated with these contracts. We recorded a net derivative gain of $28.1 million ($11.0 million net unrealized gain and $17.1 million net realized gain on settled contracts) for the nine months ended September 30, 2017 (Successor). We recorded a net derivative loss of $7.6 million ($30.3 million net unrealized loss and $22.7 million net realized gain on settled contracts) and $18.0 million ($263.7 million net unrealized loss and $245.7 million net realized gain on settled contracts) for the period of September 10, 2016 through September 30, 2016 (Successor) and for the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

Interest expense and other was $63.8 million, $5.5 million and $122.2 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. Capitalized interest for the nine months ended September 30, 2017 (Successor) and the period of September 10, 2016 through September 30, 2016 (Predecessor) was zero. Capitalized interest for the period of January 1, 2016 through September 9, 2016 (Predecessor) was $68.2 million. Gross interest expense was $195.7 million for the period of January 1, 2016 through September 9, 2016 (Predecessor). The decrease in gross interest expense was primarily due to the discontinuance of interest on our senior notes that were cancelled as part of our reorganization under chapter 11.

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We incurred reorganization expense of $0.6 million and a reorganization gain of $913.7 million for the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. The Successor expense was associated with legal and professional fees directly attributable to the chapter 11 bankruptcy. The Predecessor gain primarily resulted from the gain on the discharge of debt and fresh-start accounting adjustments upon emergence from chapter 11 bankruptcy.

On September 7, 2017 (Successor), 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 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. During the nine months ended September 30, 2017 (Successor), we repurchased and redeemed approximately $700.0 million principal amount of our 2020 Second Lien Notes. Upon settlement of the repurchases and redemptions, we recorded a net loss on extinguishment of debt of approximately $56.9 million, which included a write-off of $26.0 million associated with the discount for the notes. During the first three months of 2016 (Predecessor), we repurchased approximately $91.8 million principal amount of our then outstanding senior unsecured notes, consisting of $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022 for cash at prevailing market prices at the time of the transactions. The net cash used to make these repurchases was approximately $9.7 million. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased and we recorded a net gain on the extinguishment of debt of approximately $81.4 million, which included the write-down of $0.7 million associated with related issuance costs and discounts and premiums for the respective notes.

We recorded an income tax benefit of $5.0 million for the nine months ended September 30, 2017 (Successor), resulting from the reversal of our estimated 2016 alternative minimum tax liability. We recorded an income tax provision of $3.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and an income tax benefit of $8.7 million for the period January 1, 2016 through September 9, 2016 (Predecessor) related to our estimated 2016 alternative minimum tax liability and the reversal of the Predecessor estimated 2015 alternative minimum tax liability, respectively.

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

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and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and deferred put options. The total volumes that we hedge through the use of derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our 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 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 8, "Derivative and Hedging Activities," for additional information.

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under ASC 825, Financial Instruments (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 7, "Fair Value Measurements," for additional information.

Interest Rate Sensitivity

Historically, we have been exposed to interest rate risk exposure primarily from fluctuations in short-term rates, which are LIBOR and ABR based. These fluctuations can cause reductions of earnings or cash flows due to increases in the interest rates that we have historically paid on these obligations. At September 30, 2017 (Successor), the principal amount of our debt was $850.0 million which bears interest at a weighted average fixed interest rate of 6.75% per year. At September 30, 2017 (Successor), we did not have any amounts drawn under our Senior Credit Agreement. Therefore, we do not currently have any long-term debt that bears interest at floating and variable interest rates. If we incur future indebtedness which bears interest at variable rates, fluctuations in market interest rates could cause our annual interest costs to fluctuate.

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, 2017. 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, 2017 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.

Item 1A. Risk Factors

Our Williston Basin operated assets represented the substantial majority of our production, proved reserves and revenues, and following the sale of these assets we will be substantially dependent upon our drilling success on our Delaware Basin properties, which are largely undeveloped and with which we have less experience.

For the nine months ended September 30, 2017, our Williston Basin operated assets represented approximately 76% of our production and our revenue. As of December 31, 2016, our Williston Basin operated assets represented approximately 71% of our proved reserves, of which 62% was classified as proved developed. The disposition of our Williston Basin operated assets, combined with our other recent acquisition and divestiture activities, transformed our company from one operating in multiple basins in which we have years of accumulated operational experience and substantial proved developed acreage to one with largely unproven acreage concentrated in the Delaware Basin, an area in which we have only limited recent experience. As a consequence, we will be subject to the greater risks associated with a more concentrated, less developed property portfolio in an area where we have less experience, and more dependent upon our future drilling success in that area. If our drilling results are less than anticipated, or the risks associated with a more concentrated property portfolio such as regional supply and demand factors and delays or interruptions in production from governmental regulation, transportation constraints, market limitations, water shortages or other conditions, adversely impact our ability to produce or market our production, it could have a material adverse effect on our results of operations, financial condition and prospects.

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

The following table sets forth information regarding our acquisition of shares of common stock for the periods presented.

		Average Price Paid Per Share

July 2017	—	$	—	—	—
August 2017	—		—	—	—
September 2017	292,914		6.24	—	—

(1): All of the shares were surrendered by employees in satisfaction of tax obligations upon the vesting of restricted stock awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock, nor were they considered as or accounted for as treasury shares.

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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	*	Agreement of Sale and Purchase, dated September 19, 2017, by and among Halcón Energy Properties, Inc., HRC Energy, LLC, Halcón Holdings, Inc. and Halcón Operating Co., Inc., collectively as seller, and Riverbend Oil and Gas VI, LLC, as purchaser.

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).

4.1		Indenture, dated as of February 16, 2017, among Halcón Resources Corporation, the guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 6.75% Senior Unsecured Notes due 2025 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 16, 2017).

4.1.1		First Supplemental Indenture dated as of July 24, 2017, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the to the 6.75% Senior Notes due 2025 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 25, 2017).

4.1.2	*	Second Supplemental Indenture dated as of October 9, 2017, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 6.75% Senior Notes due 2025.

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).

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

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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 9, 2017	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board, Chief Executive Officer and President
November 9, 2017	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
November 9, 2017	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Senior Vice President, Chief Accounting Officer and Controller