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

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.

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 July 31, 2017, 150,076,361 shares of the Registrant's Common Stock were outstanding.

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, the purchase price, timing and use of proceeds from the Williston Divestiture and our 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, 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:

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.

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Successor			Predecessor			Successor			Predecessor

	Successor			Predecessor			Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016			Six Months Ended June 30, 2017			Six Months Ended June 30, 2016


Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	108,695		$	99,095		$	231,216		$	174,062
Natural gas		5,946			3,159			12,165			6,901
Natural gas liquids		5,306			3,504			11,331			5,441

Total oil, natural gas and natural gas liquids sales		119,947			105,758			254,712			186,404
Other		190			389			1,023			1,092

Total operating revenues		120,137			106,147			255,735			187,496

Operating expenses:
Production:
Lease operating		20,380			16,981			41,024			37,559
Workover and other		7,128			7,915			18,569			15,706
Taxes other than income		10,727			9,753			22,303			17,011
Gathering and other		11,812			10,519			23,754			21,903
Restructuring		50			189			805			5,073
General and administrative		26,922			24,708			47,771			66,324
Depletion, depreciation and accretion		31,962			39,671			64,848			94,937
Full cost ceiling impairment		—			257,869			—			754,769
(Gain) loss on sale of oil and natural gas properties		(4,500	)		—			(235,690	)		—
Other operating property and equipment impairment		—			—			—			28,056

Total operating expenses		104,481			367,605			(16,616	)		1,041,338

Income (loss) from operations		15,656			(261,458	)		272,351			(853,842	)
Other income (expenses):
Net gain (loss) on derivative contracts		24,156			(54,523	)		50,554			(35,781	)
Interest expense and other, net		(19,635	)		(58,322	)		(44,478	)		(106,113	)
Gain (loss) on extinguishment of debt		—			—			(56,898	)		81,434

Total other income (expenses)		4,521			(112,845	)		(50,822	)		(60,460	)

Income (loss) before income taxes		20,177			(374,303	)		221,529			(914,302	)
Income tax benefit (provision)		—			—			(12,000	)		—

Net income (loss)		20,177			(374,303	)		209,529			(914,302	)
Non-cash preferred dividend		(47,206	)		—			(48,007	)		—
Series A preferred dividends		—			(3,198	)		—			(6,396	)
Preferred dividends and accretion on redeemable noncontrolling interest		—			(4,852	)		—			(28,517	)

Net income (loss) available to common stockholders	$	(27,029	)	$	(382,353	)	$	161,522		$	(949,215	)



Net income (loss) per share of common stock:
Basic	$	(0.19	)	$	(3.17	)	$	1.37		$	(7.89	)



Diluted	$	(0.19	)	$	(3.17	)	$	1.37		$	(7.89	)



Weighted average common shares outstanding:
Basic		143,545			120,708			117,554			120,360



Diluted		143,545			120,708			118,209			120,360

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	Successor

	June 30, 2017			December 31, 2016
Current assets:
Cash	$	21		$	24
Accounts receivable		124,250			147,762
Receivables from derivative contracts		26,389			5,923
Prepaids and other		6,839			6,940

Total current assets		157,499			160,649

Oil and natural gas properties (full cost method):
Evaluated		1,326,160			1,269,034
Unevaluated		1,053,408			316,439

Gross oil and natural gas properties		2,379,568			1,585,473
Less—accumulated depletion		(527,654	)		(465,849	)

Net oil and natural gas properties		1,851,914			1,119,624

Other operating property and equipment:
Gas gathering and other operating assets		67,595			38,617
Less—accumulated depreciation		(3,041	)		(1,107	)

Net other operating property and equipment		64,554			37,510

Other noncurrent assets:
Receivables from derivative contracts		5,477			—
Funds in escrow and other		1,906			1,887

Total assets	$	2,081,350		$	1,319,670



Current liabilities:
Accounts payable and accrued liabilities	$	223,305		$	186,184
Liabilities from derivative contracts		280			16,434
Other		4,704			4,935

Total current liabilities		228,289			207,553

Long-term debt, net		1,093,548			964,653
Other noncurrent liabilities:
Liabilities from derivative contracts		363			486
Asset retirement obligations		26,980			31,985
Other		141			2,305
Commitments and contingencies (Note 10)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 150,101,781 and 92,991,183 shares issued and outstanding as of June 30, 2017 and December 31, 2016, respectively		15			9
Additional paid-in capital		1,002,469			592,663
Retained earnings (accumulated deficit)		(270,455	)		(479,984	)

Total stockholders' equity		732,029			112,688

Total liabilities and stockholders' equity	$	2,081,350		$	1,319,670

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

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)		—			—		—			—			—			209,529			209,529
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		—			—		(89	)		—			—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(2	)		—			(17	)		—			(17	)
Share-based compensation		—			—		—			—			21,693			—			21,693

Balances at June 30, 2017 (Successor)		—		$	—		150,102		$	15		$	1,002,469		$	(270,455	)	$	732,029

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Successor			Predecessor

	Six Months Ended June 30, 2017			Six Months Ended June 30, 2016


Cash flows from operating activities:
Net income (loss)	$	209,529		$	(914,302	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		64,848			94,937
Full cost ceiling impairment		—			754,769
(Gain) loss on sale of oil and natural gas properties		(235,690	)		—
Other operating property and equipment impairment		—			28,056
Share-based compensation, net		21,290			3,652
Unrealized loss (gain) on derivative contracts		(42,219	)		224,281
Amortization and write-off of deferred loan costs		896			3,024
Amortization of discount and premium		1,887			1,269
Loss (gain) on extinguishment of debt		56,898			(81,434	)
Accrued settlements on derivative contracts		(3,520	)		(23,072	)
Other income (expense)		(1,004	)		3,973
Change in assets and liabilities:
Accounts receivable		34,982			72,286
Prepaids and other		91			(4,535	)
Accounts payable and accrued liabilities		14,655			(20,161	)

Net cash provided by (used in) operating activities		122,643			142,743

Cash flows from investing activities:
Oil and natural gas capital expenditures		(121,210	)		(170,416	)
Proceeds received from sale of oil and natural gas properties		477,306			(407	)
Acquisition of oil and natural gas properties		(907,487	)		158
Acquisition of other operating property and equipment		(25,538	)		—
Other operating property and equipment capital expenditures		(13,735	)		(886	)
Proceeds received from sale of other operating property and equipment		10,352			115
Funds held in escrow and other		285			59

Net cash provided by (used in) investing activities		(580,027	)		(171,377	)

Cash flows from financing activities:
Proceeds from borrowings		1,235,000			425,000
Repayments of borrowings		(1,118,000	)		(395,648	)
Premium paid to repurchase the 2020 Second Lien Notes		(30,917	)		—
Debt issuance costs		(16,823	)		(1,186	)
Preferred stock issued		400,055			—
Offering costs and other		(11,934	)		(385	)

Net cash provided by (used in) financing activities		457,381			27,781

Net increase (decrease) in cash		(3	)		(853	)
Cash at beginning of period		24			8,026

Cash at end of period	$	21		$	7,173



Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	—		$	(2,387	)
Asset retirement obligations		(5,972	)		919
Accretion of non-cash preferred dividend		48,007			—
Preferred dividends on redeemable noncontrolling interest paid-in-kind		—			6,655
Accretion of redeemable noncontrolling interest		—			21,862
Accrued debt issuance costs		(45	)		904
Accrued offering costs		(3	)		—

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

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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"

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

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 El Halcón Divestiture (see to Note 4, "Acquisitions and Divestitures," for information on the Pecos County Acquisition and the El Halcón Divestiture), including the gain on sale 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.

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 June 30, 2017 (Successor) or December 31, 2016 (Successor).

Gas gathering systems 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

calculated using the straight-line method over a 30-year, 20-year, or 10-year estimated useful life applicable to gas gathering systems, a water recycling facility and a compressed natural gas facility, respectively. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

Other operating assets 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 calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years 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 gas gathering systems and equipment and other operating assets acquired and divested during the period.

The Company reviews its gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its gas gathering systems and other operating assets at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. For the six months ended June 30, 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 "Gas gathering and other operating assets" 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 systems 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 systems being classified as Level 3.

In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). For public business entities, ASU 2017-01 is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2017. The amendments in this ASU should be applied prospectively on or after the effective date. The ASU was issued to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The Company 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, 2016, or after December 2017, if companies choose to elect the deferred adoption date approved by the FASB. Early adoption is not permitted. 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 2014-09 effective January 1, 2018.

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 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:

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.

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 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):

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

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:
Gas gathering and other operating assets		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


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

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 Southern Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $703.9 million, subject to customary post-closing adjustments (the Pecos County Acquisition). The Pecos County Acquisition closed on February 28, 2017. 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 8% Automatically Convertible Preferred Stock.

The transaction had an effective date of November 1, 2016, and was subject to customary closing conditions, as well as the execution and delivery of certain other agreements.

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.

The following table summarizes the consideration paid to acquire the Pecos County Assets, as well as the preliminary 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: Estimated post-effective closing date adjustments⁽²⁾		(4,816	)

Final estimated consideration transferred	$	699,049



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	$	702,004



Estimated Fair Value of Assets Acquired:
Evaluated oil and natural gas properties⁽³⁾⁽⁴⁾	$	150,275
Unevaluated oil and natural gas properties⁽³⁾⁽⁴⁾		525,350
Gas gathering and other operating assets⁽⁵⁾		26,379

Amount attributable to assets acquired	$	702,004

(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 the closing of the Pecos County Acquisition have been reflected as adjustments to the purchase price consideration. At closing, a net $1.1 million was identified as reductions to the purchase price consideration for post effective date activities from November 1, 2016 through December 31, 2016. Estimates have been made to reflect expected purchase price consideration adjustments for the post effective date period from January 1, 2017 through February 28, 2017 (the closing date).
(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.
(5): In estimating the fair value of the Pecos County Assets' gas gathering and other operating assets, 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 six months ended June 30, 2017 and 2016 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 six months ended June 30, 2017 and 2016 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.

The Company's historical financial information was adjusted to give effect to the pro forma events that are directly attributable to Pecos County Assets and are factually supportable. The unaudited pro forma consolidated results include the historical revenues and expenses of assets acquired and liabilities assumed, with the following adjustments:

For the six months ended June 30, 2017 (Successor), the Company recognized $14.1 million of oil, natural gas and natural gas liquids and other revenue related to the Pecos County Assets and $4.2 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 $0.9 million related to the Pecos County Acquisition for the six months ended June 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.

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 its 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 $483.5 million, subject to post-closing adjustments (the El Halcón Divestiture). The effective date of the sale was January 1, 2017 and the transaction closed on March 9, 2017. The sale properties included acreage prospective for the Eagle Ford formation in East Texas and related gas gathering and other operating assets. 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, gas gathering and other operating assets and liabilities transferred on a fair value basis. Approximately $10.2 million was allocated to gas gathering and other operating assets and approximately $477.3 million was allocated to the Company's oil and natural gas properties.

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 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 initially recognized a gain on the sale of $231.2 million during the three months ended March 31, 2017 (Successor). This gain increased by $4.5 million during the three months ended June 30, 2017 (Successor) as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in "Gain (loss) on sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

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 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 six months ended June 30, 2016 (Predecessor), HK TMS issued 6,655 additional preferred shares to Apollo for dividends paid-in-kind. 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."

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 six months ended June 30, 2016 (Predecessor), the Company capitalized interest costs of $52.9 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.

At June 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 June 30, 2017 of the West Texas Intermediate (WTI) crude oil spot price of $48.95 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2017 of the Henry Hub natural gas price of $3.01 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2017 (Successor) did not exceed the ceiling amount.

At June 30, 2016 (Predecessor), the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2016 of the WTI crude oil spot price of $43.12 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2016 of the Henry Hub natural gas price of $2.24 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2016 exceeded the ceiling amount by $257.9 million ($163.1 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. The impairment at June 30, 2016 (Predecessor) primarily reflects a 7% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $46.26 per barrel at March 31, 2016. At March 31, 2016 (Predecessor), the Company recorded a full cost ceiling impairment before income taxes of $496.9 million ($315.1 million after taxes, before valuation allowance). The impairment at March 31, 2016 (Predecessor) reflects additional transfers 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 and, to a lesser extent, an 8% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $50.28 per barrel at December 31, 2015. As discussed above, the Company considers the facts and circumstances around its unevaluated properties that may indicate impairment on a quarterly basis. 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 long-term debt while preserving liquidity in light of 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 impairment in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets.

Changes in 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.

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

On the Effective Date, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $650.0 million. The maturity date of the Senior Credit Agreement is July 28, 2021. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if the Company has outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, the Company may also be required to make mandatory prepayments.

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 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 June 30, 2017 (Successor), under the effective borrowing base of $650.0 million, the Company had $153.0 million of indebtedness outstanding, approximately $6.4 million letters of credit outstanding and approximately $490.6 million of borrowing capacity available under the Senior Credit Agreement.

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, 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.

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 Predecessor Company recorded the issuance of the 2022 Second Lien Notes at par.

Interest on the 2022 Second Lien Notes accrues at a rate of 12.0% per annum, payable semi-annually on February 15 and August 15 of each year. The 2022 Second Lien Notes will mature on February 15, 2022. The 2022 Second Lien Notes are secured by second-priority liens on substantially all of the Company's, and certain subsidiaries of the Company (the Guarantors') assets to the extent such assets secure the Company's Senior Credit Agreement (the Collateral). Pursuant to the terms of the Intercreditor Agreement, dated December 21, 2015, the security interest in the Collateral securing the 2022 Second Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2022 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness to the extent of the value of the Collateral. 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.

As discussed in Note 3, "Fresh-start Accounting," on September 9, 2016, the Company adjusted the 2022 Second Lien Notes to fair value of $107.2 million by recording a discount of $5.7 million to be amortized over the remaining life of the 2022 Second Lien Notes, using the effective interest method.

In addition, on September 28, 2016, the Company, each of its guarantors and U.S. Bank National Association, as trustee, entered into a supplemental indenture (the 2022 Second Lien Note Supplemental Indenture) to the Indenture dated as of December 21, 2015 with respect to the Company's 2022 Second Lien Notes (the 2022 Second Lien Note Indenture). The 2022 Second Lien Note Supplemental Indenture amended the 2022 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2022 Second Lien Note Supplemental Indenture became operative upon the consummation of the consent solicitation on September 30, 2016. The Company paid an aggregate consent fee of approximately $1.4 million to holders of the 2022 Second Lien Notes and recorded an additional discount of approximately $1.4 million.

The remaining unamortized discount was $6.3 million at June 30, 2017 (Successor).

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 $833.4 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 (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) on the 2025 Notes redeemed during the twelve month period indicated beginning on February 15 of the years indicated below:

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.

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 six months ended June 30, 2017 (Successor), the Company capitalized approximately $16.6 million of debt issuance costs related to the 2025 Notes. As part of the Company's reorganization, all debt issuance costs related to the Company's Predecessor debt were extinguished. The debt issuance costs for the Successor Company's senior unsecured debt are presented in "Long-term debt, net" within total liabilities on the unaudited condensed consolidated balance sheet at June 30, 2017 (Successor).

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 June 30, 2017 (Successor) and December 31, 2016 (Successor) (in thousands):

Derivative contracts listed above as Level 2 include collars and swaps that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8, "Derivative and Hedging Activities," for additional discussion of derivatives.

The Company's derivative contracts are with major financial 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 June 30, 2017 (Successor) and December 31, 2016 (Successor) (excluding discounts and debt issuance costs) (in thousands):

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.

During the six months ended June 30, 2016 (Predecessor), the Company recorded a non-cash impairment charge of $28.1 million related to its gas gathering systems. 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.

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.

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 June 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. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) and the relevant price index at which the oil production is sold (i.e. Cushing). A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company 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 June 30, 2017 (Successor), the Company had 44 open commodity derivative contracts summarized in the following tables: eight natural gas collar arrangements, two natural gas basis swaps, eight crude oil basis swaps and 26 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. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets (in thousands):

The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's unaudited condensed consolidated statements of operations (in thousands):

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

		Successor		Predecessor			Successor		Predecessor
Derivatives not designated as hedging contracts under ASC 815	Location of gain or (loss) recognized in income on derivative contracts	Three Months Ended June 30, 2017		Three Months Ended June 30, 2016			Six Months Ended June 30, 2017		Six Months Ended June 30, 2016


Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	18,005	$	(135,303	)	$	42,219	$	(224,281	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		6,151		80,780			8,335		188,500

Total net gain (loss) on derivative contracts		$	24,156	$	(54,523	)	$	50,554	$	(35,781	)

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

			Successor

			June 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
July 2017 - December 2017	Basis Swap	Natural Gas		920,000	$—	$	—	$—	$	—	$(0.40) - $(0.41)	$	(0.40	)
July 2017 - December 2017	Collars	Natural Gas		3,680,000	3.00 - 3.26		3.13	3.38 - 3.76		3.53
July 2017 - December 2017	Collars	Crude Oil		3,910,000	47.00 - 60.00		51.30	52.00 - 76.84		58.40
January 2018 - December 2018	Basis Swap	Crude Oil		2,555,000	—		—	—		—	(1.05) - (1.50)		(1.29	)
January 2018 - December 2018	Basis Swap	Natural Gas		1,825,000	—		—	—		—	(0.40) - (0.41)		(0.40	)
January 2018 - December 2018	Collars	Natural Gas		3,650,000	3.00 - 3.03		3.01	3.22 - 3.39		3.32
January 2018 - December 2018	Collars	Crude Oil		2,190,000	45.00 - 53.00		50.17	55.25 - 60.00		58.54
July 2018 - December 2018	Basis Swap	Crude Oil		828,000	—		—	—		—	(1.12) - (1.18)		(1.15	)
January 2019 - December 2019	Basis Swap	Crude Oil		2,372,500	—		—	—		—	(1.12) - (1.33)		(1.20	)

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):

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

The 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 gas gathering systems and equipment, the Company records an ARO when the system is placed in service and it can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work when it is required. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes a portion of the cost in "Oil and natural gas properties" or "Other operating property and equipment" during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in "Depletion, depreciation and accretion" expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

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

The Company leases corporate office space in Houston, Texas; and Denver, Colorado as well as other field office locations. Rent expense was approximately $2.0 million and $4.3 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. Future obligations associated with the Company's operating leases are presented in the table below (in thousands):

As of June 30, 2017 (Successor), the Company has the following active drilling rig and hydraulic fracturing commitments (in thousands):

As of June 30, 2017 (Successor), termination of the Company's active drilling rig and hydraulic fracturing commitments would require early termination penalties of $9.7 million, which would be in lieu of paying the remaining active commitments of $34.6 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):

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 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 increases in depths in the acreage to be purchased by the Company. 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 plans to drill a commitment well on the Northern Tract by September 1, 2017, to earn the option to acquire the Northern Tract acreage for $13,000 per acre by December 31, 2017. On June 20, 2017 (Successor), the Company entered into an additional option agreement with the private company for the right to purchase up to 7,680 additional net acres located in Ward and Winkler Counties, Texas. The Company also paid $5.0 million and plans to drill a commitment well by December 1, 2017, to earn the option to

acquire the additional acreage for $10,000 per acre by March 31, 2018. These option purchase agreements are 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 Bakken/Three Forks formations in North Dakota and the Southern Delaware Basin in West Texas. As of June 30, 2017 (Successor), the Company had in place ten long-term crude oil contracts and nine long-term natural gas contracts in these areas. Under the terms of these contracts, the Company has committed a substantial portion of its production from these areas for periods ranging from one to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. Historically, the Company has been able to meet its delivery commitments.

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

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 Securities and Exchange Commission (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 the unaudited condensed consolidated statements of operations. The preferred dividend was charged against additional paid-in capital since no retained earnings were available.

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.

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.

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 written consent. As of June 30, 2017 (Successor) and December 31, 2016 (Successor), a maximum of 7.1 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 six months ended June 30, 2017 (Successor) the Company recognized $12.9 million and $21.3 million, respectively, of share-based compensation expense. For the three and six months ended June 30, 2016 (Predecessor), the Company recognized $1.5 million and $3.7 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.

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 six months ended June 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 with a weighted average exercise price of $7.72. At June 30, 2017 (Successor), the Company had $23.1 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.4 years.

No options were granted during the six months ended June 30, 2016 (Predecessor). At June 30, 2016 (Predecessor), the Company had $2.8 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.2 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.

From time to time, the Company grants shares of restricted stock to employees and non-employee directors of the Company. Employee shares typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six months from the date of grant. Certain shares granted under the 2016 Incentive Plan specifically related to the Company's emergence from chapter 11 bankruptcy have previously vested, or will vest on or before September 30, 2017.

During the six months ended June 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 with a weighted average price of $7.07. At June 30, 2017 (Successor), the Company had $13.9 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 0.8 years.

No restricted shares were granted during the six months ended June 30, 2016 (Predecessor). At June 30, 2016 (Predecessor), the Company had $5.2 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 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.

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			Successor		Predecessor

	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016			Six Months Ended June 30, 2017		Six Months Ended June 30, 2016
Basic:
Net income (loss) available to common stockholders	$	(27,029	)	$	(382,353	)	$	161,522	$	(949,215	)



Weighted average basic number of common shares outstanding		143,545			120,708			117,554		120,360

Basic net income (loss) per share of common stock	$	(0.19	)	$	(3.17	)	$	1.37	$	(7.89	)



Diluted:
Net income (loss) available to common stockholders	$	(27,029	)	$	(382,353	)	$	161,522	$	(949,215	)



Weighted average basic number of common shares outstanding		143,545			120,708			117,554		120,360
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive		Anti-dilutive
Exercise of February 2012 Warrants		—			Anti-dilutive			—		Anti-dilutive
Exercise of warrants		Anti-dilutive			—			Anti-dilutive		—
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			655		Anti-dilutive
Vesting of performance units		—			—			—		—
Conversion of preferred stock		Anti-dilutive			—			Anti-dilutive		—
Conversion of Convertible Note		—			Anti-dilutive			—		Anti-dilutive
Conversion of Series A Preferred Stock		—			Anti-dilutive			—		Anti-dilutive

Weighted average diluted number of common shares outstanding		143,545			120,708			118,209		120,360

Diluted net income (loss) per share of common stock	$	(0.19	)	$	(3.17	)	$	1.37	$	(7.89	)

Common stock equivalents, including stock options, restricted shares, warrants, and preferred stock totaling 18.1 million and 14.8 million shares for the three and six months ended June 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 44.6 million and 45.2 million shares for the three and six months ended June 30, 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 due to the net losses.

	Successor

	June 30, 2017		December 31, 2016
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	68,402	$	86,433
Joint interest accounts		29,954		39,828
Accrued settlements on derivative contracts		3,520		18,599
Affiliated partnership		74		268
Other		22,300		2,634

	$	124,250	$	147,762



Prepaids and other:
Prepaids	$	6,785	$	6,704
Other		54		236

	$	6,839	$	6,940



Accounts payable and accrued liabilities:
Trade payables	$	36,103	$	24,364
Accrued oil and natural gas capital costs		62,437		32,967
Revenues and royalties payable		60,675		79,147
Accrued interest expense		27,753		31,146
Accrued employee compensation		5,500		3,428
Accrued lease operating expenses		13,735		14,077
Drilling advances from partners		5,992		422
Income taxes payable		10,750		250
Affiliated partnership		360		323
Other		—		60

	$	223,305	$	186,184

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 its 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 sales price of $1.4 billion (the Williston Divestiture). The effective date of the proposed sale is June 1, 2017, and the Company expects to close the transaction in September 2017.

Purchase Agreement, the Purchaser paid into escrow a deposit totaling $140.0 million, which amount will be applied to the purchase price if the transaction closes.

The completion of the divestiture of the Williston Assets is subject to customary closing conditions, including among others, (i) the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and (ii) that the aggregate downward adjustment (if any) to the purchase price does not exceed 15% of the purchase price, or $210.0 million. The Purchase Agreement also includes closing conditions relating to the Company's obtaining the Stockholders' Consent (defined below) and the Noteholders' Consent (defined below), the Company's having mailed a definitive information statement on Schedule 14C to its stockholders at least 20 calendar days prior to the closing date and the Company's having entered into certain hedging transactions for the Purchaser (or the Purchaser's designee).

The Purchase Agreement contains customary termination rights, including among others, the termination rights described below. Either party may terminate the Purchase Agreement if certain closing conditions have not been satisfied, or the transaction has not closed on or before October 31, 2017, subject to certain exceptions, and limited extensions in the event (i) certain disputed environmental or title matters have been referred to a third party expert for resolution, that would otherwise result in an aggregate downward adjustment to the purchase price of an amount exceeding 15% of the purchase price, (ii) either party is exercising certain cure rights or (iii) the SEC elects to review the information statement on Schedule 14C such that the Company is precluded from mailing the definitive information statement on Schedule 14C at least 20 calendar days prior to the closing date.

The Sellers may terminate the Purchase Agreement prior to August 11, 2017, in order to enter into a third party's "superior proposal" subject to compliance with the terms of the Purchase Agreement.

If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the Williston Divestiture may not be completed. The Purchaser has paid into escrow a deposit totalling $140.0 million (the Deposit). The Deposit is refundable only in specified circumstances if the transaction is not consummated.

If the Sellers terminate the Purchase Agreement because the Purchaser failed to make true and correct representations and warranties, perform and comply with covenants, or make deliveries required under the Purchase Agreement, then the Sellers will be entitled to the Deposit as liquidated damages, as the Sellers' sole and exclusive remedy. If the Sellers fail to make true and correct representations and warranties, perform and comply with all covenants, or make deliveries required under the Purchase Agreement (unless the Sellers (a) enter into a "superior proposal agreement"; (b) fail to obtain the Stockholders' Consent; (c) fail to obtain the Noteholders' Consent; or (d) fail to use commercially reasonable efforts to attempt, on the Purchaser's behalf, to enter into certain hedging transactions), then the Purchaser is entitled to (i) seek specific performance of the terms of the Purchase Agreement by the Sellers, or (ii) terminate the Purchase Agreement and receive a return of the Deposit and seek damages from the Sellers up to the amount of the Deposit. If the Sellers terminate the Purchase Agreement to enter into a third party's "superior proposal agreement" (as defined in the Purchase Agreement) or if either the Sellers or the Purchaser terminates the Purchase Agreement pursuant to its terms for reasons other than those discussed above, then the Purchaser is entitled to the Deposit as its sole and exclusive remedy.

There can be no assurance that the Company will consummate the Williston Divestiture on the terms or timing described or at all. Assuming the Williston Divestiture closes in accordance with the terms of the Purchase Agreement, the Company intends to use the net proceeds from the Williston Divestiture to fund, contemporaneously with such closing, the redemption of all of its outstanding 12% senior secured second lien notes due 2022, to fund an offer to repurchase a portion of the 2025 Notes as provided in the Consent Solicitation, discussed below, to repay amounts outstanding under the Company's revolving credit facility and for general corporate purposes, including funding potential acquisitions and planned drilling expenditures.

Prior to July 31, 2017, the date stipulated in the Purchase Agreement, the Sellers entered into the required hedging transactions for the Purchaser.

On July 10, 2017, the Company entered into a Support Agreement (the Support Agreement) with certain holders of the 2025 Notes (collectively, the Supporting Noteholders) pursuant to which the Supporting Noteholders agreed to cause valid consents to be given to certain proposed amendments to the Indenture governing its 2025 Notes in the event it elected to conduct a consent solicitation of all holders of such notes in favor of such amendments. The Supporting Noteholders and their respective affiliates, including certain private funds and accounts they manage, hold, in the aggregate, approximately 56% of the principal amount of the Company's outstanding 2025 Notes.

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 Indenture from approximately 99% of the holders of the 2025 Notes. The amendments to the Indenture will, among other things, exempt the Williston Divestiture from certain provisions of the indenture triggered upon a sale of "all or substantially all of the assets" of the Company. In the event the Company consummates the Williston Divestiture, it will be required to make a cash offer to purchase from all holders up to 50% of the principal balance of any 2025 Notes outstanding on a prorated basis at 103.0% of principal plus accrued and unpaid interest. Consenting noteholders received a consent fee of 2.0% of principal, or $16.9 million.

Halcón is a Delaware corporation subject to the Delaware General Corporation Law, as amended (DGCL). Under Section 271(a) of the DGCL, a Delaware corporation may not sell all or substantially all of its assets without the approval and authorization of a majority of the outstanding stock of Halcón entitled to vote thereon. The Williston Divestiture may constitute a sale of "substantially all" of the consolidated assets of the Company for purposes of Section 271(a) of the DGCL, and therefore the Company elected to obtain stockholder authorization and approval of the Williston Divestiture.

On July 11, 2017, holders of a majority of Halcón's outstanding voting stock (the Majority Stockholders) executed and delivered to Halcón a written consent in lieu of a special meeting of the stockholders (the Stockholders' Consent). The written consent delivered by the Majority Stockholders authorized and approved the Williston Divestiture. Because the Majority Stockholders have approved the Williston Divestiture through execution of the written consent in accordance with the DGCL, Halcón's certificate of incorporation and bylaws, Halcón does not intend to solicit proxies from, or hold a meeting of, stockholders to approve such transaction. Halcón will file a definitive information statement with the SEC regarding this majority stockholder action and mail such information statement to its stockholders, notifying them that the Majority Stockholders have consented to the sale of the Williston Assets.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 2017 (Successor) and 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."

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004, recapitalized on February 8, 2012 and reorganized on September 9, 2016. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in select prospect areas. In the years since, we have primarily focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays. Our oil and natural gas assets currently consist of proved reserves and undeveloped acreage positions in multiple unconventional liquids-rich basins/fields. As discussed below in more detail under "Recent Developments," we have recently acquired certain properties in the Southern Delaware Basin, divested our assets located in the El Halcón area of East Texas and entered into an agreement to sell our operated assets located in the Williston Basin, which is expected to close in September 2017. After giving effect to these recent acquisition and divestiture activities, our properties and drilling activities will be focused in the Southern Delaware Basin, where we have an extensive drilling inventory that we believe offers more attractive economics. The pending divestiture of the Williston Assets, defined below, will improve liquidity and significantly reduce our debt, better enabling us to accelerate development of our Southern Delaware Basin properties and execute our growth plans in the basin.

Our average daily oil and natural gas production decreased slightly in the first six months of 2017 (Successor) when compared to the same period in the prior year due to the divestiture of the El Halcón Assets in the first 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 increased production from our Bakken/Three Forks area since the prior year period. During the first six months of 2017 (Successor), production averaged 37,387 Boe/d compared to average daily production of 37,703 Boe/d during the first six months of 2016 (Predecessor). During the first six months of 2017 (Successor), we participated in the drilling of 54 gross (9.6 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 operating costs, and incurred substantial asset impairments, primarily as a result of the full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for July 1, 2017 of $46.04 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.

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 sales price of $1.4 billion, subject to adjustment (the Williston Divestiture). The effective date of the proposed sale is June 1, 2017, and we expect to close the transaction in September 2017. Estimated proved reserves associated with these properties accounted for approximately 104.9 MMBoe, or approximately 71% of our year-end 2016 proved reserves. For the quarter ended June 30, 2017, these properties produced approximately 28,700 Boe/d, or approximately 79% of our average daily production for the quarter.

The sales price is subject to 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. Pursuant to the terms of the Purchase Agreement, the Purchaser paid into escrow a deposit totaling $140.0 million, which amount will be applied to the purchase price if the transaction closes.

The completion of Williston Divestiture is subject to customary closing conditions, including among others, (i) the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and (ii) that the aggregate downward adjustment (if any) to the purchase price does not exceed 15% of the purchase price, or $210.0 million. The Purchase Agreement also includes closing conditions relating to us obtaining the Stockholders' Consent (defined below) and the Noteholders' Consent (defined below), having mailed a definitive information statement on Schedule 14C to our stockholders at least 20 calendar days prior to the closing date and having entered into certain hedging transactions for the Purchaser (or the Purchaser's designee).

15% of the purchase price, (ii) either party is exercising certain cure rights or (iii) the Securities and Exchange Commission (the SEC) elects to review the information statement on Schedule 14C such that we are precluded from mailing the definitive information statement on Schedule 14C at least 20 calendar days prior to the closing date.

We may terminate the Purchase Agreement prior to August 11, 2017, in order to enter into a third party's "superior proposal" subject to compliance with the terms of the Purchase Agreement.

If the Sellers terminate the Purchase Agreement because the Purchaser failed to make true and correct representations and warranties, perform and comply with covenants, or make deliveries required under the Purchase Agreement, then the Sellers will be entitled to the Deposit as liquidated damages, as the Sellers' sole and exclusive remedy. If the Sellers fail to make true and correct representations and warranties, perform and comply with all covenants, or make deliveries required under the Purchase Agreement (unless the Sellers (a) enter into a "superior proposal agreement"; (b) fail to obtain the Stockholders' Consent; (c) fail to obtain the Noteholders' Consent; or (d) fail to use commercially reasonable efforts to attempt, on Purchaser's behalf, to enter into certain hedging transactions), then the Purchaser is entitled to (i) seek specific performance of the terms of the Purchase Agreement by the Sellers, or (ii) terminate the Purchase Agreement and receive a return of the Deposit and seek damages from the Sellers up to the amount of the Deposit. If the Sellers terminate the Purchase Agreement to enter into a third party's "superior proposal agreement" (as defined in the Purchase Agreement) or if either the Sellers or the Purchaser terminates the Purchase Agreement pursuant to its terms for reasons other than those discussed above, then the Purchaser is entitled to the Deposit as its sole and exclusive remedy.

There can be no assurance that we will consummate the Williston Divestiture on the terms or timing described or at all. Assuming the Williston Divestiture closes in accordance with the terms of the Purchase Agreement, we intend to use the net proceeds from the Williston Divestiture to fund, contemporaneously with such closing, the redemption of all of our outstanding 12% senior secured second lien notes due 2022, to fund an offer to repurchase a portion of the 6.75% senior notes due 2025 (the 2025 Notes) as provided in the Consent Solicitation, discussed below, to repay amounts outstanding under our senior revolving credit facility and for general corporate purposes, including funding potential acquisitions and planned drilling expenditures.

Prior to July 31, 2017, the date stipulated in the Purchase Agreement, the Sellers entered into the required hedging transactions for the Purchaser.

On July 10, 2017, we entered into a Support Agreement (the Support Agreement) with certain holders of the 2025 Notes (collectively, the Supporting Noteholders) pursuant to which the Supporting Noteholders agreed to cause valid consents to be given to certain proposed amendments to the Indenture governing our 2025 Notes in the event we elected to conduct a consent solicitation of all holders of such notes in favor of such amendments. The Supporting Noteholders and their respective affiliates, including certain private funds and accounts they manage, hold, in the aggregate, approximately 56% of the principal amount of our outstanding 2025 Notes.

On July 25, 2017, we concluded a consent solicitation of the holders of the 2025 Notes (the Consent Solicitation) and obtained consents to amend the Indenture from approximately 99% of the holders of the 2025 Notes. The amendments to the Indenture will, among other things, exempt the Williston Divestiture from certain provisions of the indenture triggered upon a sale of "all or substantially all of the assets" of ours. In the event we consummate the Williston Divestiture, we will be

required to make a cash offer to purchase from all holders up to 50% of the principal balance of any 2025 Notes outstanding on a prorated basis at 103.0% of principal plus accrued and unpaid interest. Consenting noteholders received a consent fee of 2.0% of principal, or $16.9 million.

We are a Delaware corporation subject to the Delaware General Corporation Law, as amended (DGCL). Under Section 271(a) of the DGCL, a Delaware corporation may not sell all or substantially all of its assets without the approval and authorization of a majority of the outstanding stock of Halcón entitled to vote thereon. The Williston Divestiture may constitute a sale of "substantially all" of the consolidated assets of ours for purposes of Section 271(a) of the DGCL, and therefore we elected to obtain stockholder authorization and approval of the Williston Divestiture.

On July 14, 2017, we filed unaudited pro forma condensed combined financial information as of March 31, 2017, and for the year ended December 31, 2016 and the quarter ended March 31, 2017, as Exhibit 99.1 to our current report on Form 8-K, which gives effect to, among other things, the Williston Divestiture and the repurchase of all of the 12% senior secured second lien notes due 2022 and a portion of the 2025 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 $833.4 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.

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 $483.5 million, subject to post-closing adjustments (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 include approximately 80,500 net acres prospective 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 $231.2 million during the three months ended March 31, 2017 (Successor). This gain increased by $4.5 million during the three months ended June 30, 2017 (Successor) as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in "Gain (loss) on sale of oil and natural gas properties," on the unaudited condensed consolidated statements of operations.

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 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 Southern 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 Southern Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $703.9 million, subject to post-closing adjustments (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 two rigs in this area.

The purchase price was subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. 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 Southern Delaware Basin Assets (Ward County, Texas)

Northern Tract by September 1, 2017, to earn the option to acquire the Northern Tract acreage for $13,000 per acre by December 31, 2017. On June 20, 2017 (Successor), we entered into an additional option agreement with the private company for the right to purchase up to 7,680 additional net acres located in Ward and Winkler Counties, Texas. We also paid $5.0 million and plan to drill a commitment well by December 1, 2017, to earn the option to acquire the additional acreage for $10,000 per acre by March 31, 2018.

The prices of crude oil and natural gas have declined dramatically since mid-year 2014, having recently reached multi-year lows, 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. These market dynamics have led many to conclude that commodity prices are likely to remain lower for a prolonged period. 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 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:

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.

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 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.

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).

On the Effective Date, we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $650.0 million. If the aforementioned Williston Divestiture is completed, we expect a significant reduction to the current borrowing base. The maturity date of the Senior Credit Agreement is July 28, 2021. The borrowing base will be redetermined semi-annually, with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. We may elect, at our 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). Additionally, if we have outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, we may also be required to make mandatory prepayments.

The Senior Credit Agreement 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 4.75:1.00 initially, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00.

Our near-term capital spending requirements are expected to be funded with cash flows from operations 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 4.75:1.00 initially, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00. At June 30, 2017 (Successor), under the effective borrowing base of $650.0 million, we had $153.0 million of indebtedness outstanding, $6.4 million letters of credit outstanding and approximately $490.6 million of borrowing capacity available under our Senior Credit Agreement. We expect that our borrowing base will be substantially reduced upon the closing of the Williston Divestiture and that we will apply a portion of the net proceeds from the sale to repay

amounts outstanding under the Senior Credit Agreement. At June 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 consummation of the Plan and 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 new 6.75% senior unsecured notes due 2025 and repurchased the remaining 2020 Second Lien Notes, lowering our interest obligations approximately $3.0 million per year and extending the maturity date of our senior notes from 2020 to 2025.

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

Our primary sources of cash for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor) were from operating and financing activities. In the first six months of 2017, cash generated by financing activities, as well as proceeds from the sale of the El Halcón Assets, were used

to fund our acquisition initiatives, including 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.

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor) were $122.6 million and $142.7 million, respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs and historically, realized settlements on our derivative contracts.

The $122.6 million of operating cash flows for the six months ended June 30, 2017 (Successor) primarily reflect the impact of increased commodity prices, which served to increase operating revenues approximately 36% as compared to the prior year period. Additionally, cash paid for interest and general and administrative expenses decreased since the prior year period. These cash flow increases were largely offset by decreases in realized settlements on our derivative contracts.

The $142.7 million of operating cash flows for the six months ended June 30, 2016 (Predecessor) primarily reflect the $188.5 million of realized settlements on our derivative contracts, which mitigated decreases in revenues due to the low commodity price environment.

Investing Activities. Net cash used in investing activities was approximately $580.0 million and $171.4 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. For the six months ended June 30, 2017 (Successor), investing cash flows primarily reflect the acquisition of oil and natural gas properties offset by proceeds from the sale of non-core oil and natural gas properties. Historically, the primary driver of cash used in investing activities was the acquisition of unevaluated leasehold acreage coupled with our drilling and completion activities.

During the first six months of 2017 (Successor), we incurred cash expenditures of $705.3 million to acquire the Pecos County Assets of which $679.8 million related to the oil and natural gas properties and $25.5 million related to the gas gathering and other operating assets. In addition to the Pecos County Assets, we spent $227.7 million on other acquisitions, primarily in the Southern Delaware Basin to increase our position in the area. We spent $121.2 million on oil and natural gas capital expenditures, of which $110.2 million related to drilling and completion costs. Proceeds from the sale of the El Halcón Assets were $487.5 million and served to largely offset cash outflows for acquisitions, of which $477.3 million related to the oil and natural gas properties divested and $10.2 million related to the gas gathering and other operating assets divested.

During the first six months of 2016 (Predecessor), we spent $170.3 million on oil and natural gas capital expenditures, of which $109.4 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, leasing and seismic data. In response to the dramatic decline in crude oil prices since mid-year 2014 and due to the expectation that prices may not recover in the near term, we budgeted to run an average of 1.3 rigs during 2016, and therefore planned for capital expenditures to be lower than previous years.

Financing Activities. Net cash flows provided by financing activities were $457.4 million and $27.8 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

During the first six 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 $833.4 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 outstanding 2020 Second Lien Notes. We repurchased and redeemed approximately $700.0 million principal amount of our 8.625% senior secured second lien notes due 2020. 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. 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 first six months ended June 30, 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.

The following summarizes our contractual obligations and commitments by payment periods as of June 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	$	153,000	$	—	$	—	$	153,000	$	—
12.0% senior secured second lien notes due 2022⁽¹⁾		112,826		—		—		—		112,826
6.75% senior notes due 2025⁽²⁾		850,000		—		—		—		850,000
Interest expense on long-term debt⁽³⁾		436,637		40,259		161,034		156,930		78,414
Operating leases		13,610		1,695		6,427		3,308		2,180
Drilling rig & hydraulic fracturing commitments⁽⁴⁾		34,588		18,344		16,244		—		—
Rig stacking commitments		6,482		2,222		1,260		3,000		—

Total contractual obligations	$	1,607,143	$	62,520	$	184,965	$	316,238	$	1,043,420

We lease corporate office space in Houston, Texas and Denver, Colorado as well as other field office locations. Rent expense was approximately $2.0 million and $4.3 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

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 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 increases in depths in the acreage to be purchased by us. 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 plan to drill a commitment well on the Northern Tract by September 1, 2017, to earn the option to acquire the Northern Tract acreage for $13,000 per acre by December 31, 2017. On June 20, 2017 (Successor), we entered into an additional option agreement with the private company for the right to purchase up to 7,680 additional net acres located in Ward and Winkler Counties, Texas. We also paid $5.0 million and plan to drill a commitment well by December 1, 2017, to earn the option to acquire the additional acreage for $10,000 per acre by March 31, 2018. The option agreements are not included in the tables above.

We have entered into various long-term gathering, transportation and sales contracts with respect to production from the Bakken/Three Forks formations in North Dakota and the Southern Delaware Basin in West Texas. As of June 30, 2017 (Successor), we had in place ten long-term crude oil contracts and nine long-term natural gas contracts in these areas. Under the terms of these contracts, we have committed a substantial portion of our production from these areas for periods ranging from one to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. Historically, we have been able to meet our delivery commitments.

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.

We reported net income of $20.2 million and a net loss of $374.3 million for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. 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

	Successor			Predecessor
	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016
In thousands (except per unit and per Boe amounts)
In thousands (except per unit and per Boe amounts)
Net income (loss)	$	20,177		$	(374,303	)
Operating revenues:
Oil		108,695			99,095
Natural gas		5,946			3,159
Natural gas liquids		5,306			3,504
Other		190			389
Operating expenses:
Production:
Lease operating		20,380			16,981
Workover and other		7,128			7,915
Taxes other than income		10,727			9,753
Gathering and other		11,812			10,519
Restructuring		50			189
General and administrative:
General and administrative		13,979			23,201
Share-based compensation		12,943			1,507
Depletion, depreciation and accretion:
Depletion—Full cost		30,405			37,719
Depreciation—Other		1,168			1,434
Accretion expense		389			518
Full cost ceiling impairment		—			257,869
(Gain) loss on sale of oil and natural gas properties		(4,500	)		—
Other income (expenses):
Net gain (loss) on derivative contracts		24,156			(54,523	)
Interest expense and other, net		(19,635	)		(58,322	)
Production:
Oil—MBbls		2,470			2,498
Natural Gas—Mmcf		2,579			2,322
Natural gas liquids—MBbls		405			380
Total MBoe(1)		3,304			3,265
Average daily production—Boe/d(1)		36,308			35,879
*Average price per unit(2)***:
Oil price—Bbl	$	44.01		$	39.67
Natural gas price—Mcf		2.31			1.36
Natural gas liquids price—Bbl		13.10			9.22
Total per Boe(1)		36.30			32.39
Average cost per Boe:
Production:
Lease operating	$	6.17		$	5.20
Workover and other		2.16			2.42
Taxes other than income		3.25			2.99
Gathering and other		3.58			3.22
Restructuring		0.02			0.06
General and administrative:
General and administrative		4.23			7.11
Share-based compensation		3.92			0.46
Depletion		9.20			11.55

Oil, natural gas and natural gas liquids revenues were $119.9 million and $105.8 million for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. Average realized prices (excluding the effects of hedging arrangements) were $36.30 per Boe and $32.39 per Boe for the three months ended June 30, 2017 (Successor) and 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 increased slightly in the three months ended June 30, 2017 (Successor) when compared to the same period in the prior year. Production associated with the acquisition of the Pecos County Assets and increased production from our Bakken/Three Forks area since the prior year period served to offset the production decrease from the divestiture of the El Halcón Assets in the first quarter of 2017.

Lease operating expenses were $20.4 million and $17.0 million for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. The increase in lease operating expenses during 2017 relates to costs in our Bakken/Three Forks area, where we have focused our drilling over the past year and increased our well inventory. On a per unit basis, lease operating expenses were $6.17 per Boe and $5.20 per Boe for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Workover and other expenses were $7.1 million and $7.9 million for the three months ended June 30, 2017 (Successor) and 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 $2.16 per Boe and $2.42 per Boe for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Taxes other than income were $10.7 million and $9.8 million for the three months ended June 30, 2017 (Successor) and 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 $3.25 per Boe and $2.99 per Boe for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Gathering and other expenses were $11.8 million and $10.5 million for the three months ended June 30, 2017 (Successor) and 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 $9.0 million and $7.1 million of expenses incurred for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively, relate to gathering and other fees paid on our oil and natural gas production. Also included are $1.9 million and $3.1 million of rig stacking or termination charges for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

During the three months ended June 30, 2017 (Successor), we incurred approximately $50,000 in severance costs related to the termination of certain employees in conjunction with the El Halcón Divestiture. During the three months ended June 30, 2016 (Predecessor), we incurred $0.2 million in severance costs and accelerated stock-based compensation expense related to a reduction in our workforce due to the decrease in our drilling and developmental activities planned for that year.

General and administrative expense was $14.0 million and $23.2 million, for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. General and administrative expense in the prior year period included $7.5 million in fees associated with the effort to restructure our indebtedness. 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 $4.23 per Boe and $7.11 per Boe for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Share-based compensation expense was $12.9 million and $1.5 million, for the three months ended June 30, 2017 (Successor) and 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 $9.20 per Boe and $11.55 per Boe for the three months ended June 30, 2017 (Successor) and 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.

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 June 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 June 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 $257.9 million for the three months ended June 30, 2016 (Predecessor). The impairment primarily reflects a 7% decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, which was $46.26 per barrel at March 31, 2016 (Predecessor). 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 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 initially recognized a gain on the sale of $231.2 million during the three months ended March 31, 2017 (Successor) and an additional gain of $4.5 million during the three months ended June 30, 2017 (Successor) as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil 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 June 30, 2017 (Successor), we had a $31.9 million derivative asset, $26.4 million of which was classified as current and we had a $0.6 million derivative liability, $0.3 million of which was classified as current associated with these contracts. We recorded a net derivative gain of $24.2 million ($18.0 million net unrealized gain and $6.2 million net realized gain on settled contracts) for the three months ended June 30, 2017 (Successor) compared to a net derivative loss of $54.5 million ($135.3 million net unrealized loss and $80.8 million net realized gain on settled contracts), in the same period in 2016 (Predecessor).

Interest expense and other was $19.6 million and $58.3 million for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. Capitalized interest for the three months ended June 30, 2017 (Successor) and 2016 (Predecessor) was zero and $20.9 million, respectively. Gross interest expense was $77.1 million for the three months ended June 30, 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.

We reported net income of $209.5 million and a net loss of $914.3 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. 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

	Six Months Ended June 30, 2017			Six Months Ended June 30, 2016

In thousands (except per unit and per Boe amounts)
Net income (loss)	$	209,529		$	(914,302	)
Operating revenues:
Oil		231,216			174,062
Natural gas		12,165			6,901
Natural gas liquids		11,331			5,441
Other		1,023			1,092
Operating expenses:
Production:
Lease operating		41,024			37,559
Workover and other		18,569			15,706
Taxes other than income		22,303			17,011
Gathering and other		23,754			21,903
Restructuring		805			5,073
General and administrative:
General and administrative		26,481			62,672
Share-based compensation		21,290			3,652
Depletion, depreciation and accretion:
Depletion—Full cost		61,805			90,660
Depreciation—Other		2,187			3,246
Accretion expense		856			1,031
Full cost ceiling impairment		—			754,769
(Gain) loss on sale of oil and natural gas properties		(235,690	)		—
Other operating property and equipment impairment		—			28,056
Other income (expenses):
Net gain (loss) on derivative contracts		50,554			(35,781	)
Interest expense and other, net		(44,478	)		(106,113	)
Gain (loss) on extinguishment of debt		(56,898	)		81,434
Income tax benefit (provision)		(12,000	)		—
Production:
Oil—MBbls		5,101			5,274
Natural Gas—Mmcf		5,018			4,842
Natural gas liquids—MBbls		830			781
Total MBoe(1)		6,767			6,862
Average daily production—Boe(1)		37,387			37,703
*Average price per unit(2)***:
Oil price—Bbl	$	45.33		$	33.00
Natural gas price—Mcf		2.42			1.43
Natural gas liquids price—Bbl		13.65			6.97
Total per Boe(1)		37.64			27.16
Average cost per Boe:
Production:
Lease operating	$	6.06		$	5.47
Workover and other		2.74			2.29
Taxes other than income		3.30			2.48
Gathering and other		3.51			3.19
Restructuring		0.12			0.74
General and administrative:
General and administrative		3.91			9.13
Share-based compensation		3.15			0.53
Depletion		9.13			13.21

Oil, natural gas and natural gas liquids revenues were $254.7 million and $186.4 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. Average realized prices (excluding the effects of hedging arrangements) were $37.64 per Boe and $27.16 per Boe for the six months ended June 30, 2017 (Successor) and 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 six months of 2017 (Successor) when compared to the same period in the prior year due to the divestiture of the El Halcón Assets in the first 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 increased production from our Bakken/Three Forks area since the prior year period.

Lease operating expenses were $41.0 million and $37.6 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor). The increase in lease operating expenses during 2017 relates to costs in our Bakken/Three Forks area, where we have focused our drilling over the past year and increased our well inventory. On a per unit basis, lease operating expenses were $6.06 per Boe and $5.47 per Boe for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Workover and other expenses were $18.6 million and $15.7 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. The increased costs in 2017 relate primarily to workovers in our Bakken/Three Forks area, where we've focused our drilling over the past year, increasing our well inventory, and where inclement weather conditions caused increased workover activity on our wells in the first quarter of 2017. On a per unit basis, workover and other expenses were $2.74 per Boe and $2.29 per Boe for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Taxes other than income were $22.3 million and $17.0 million for the six months ended June 30, 2017 (Successor) and 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 $3.30 per Boe and $2.48 per Boe for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Gathering and other expenses were $23.8 million and $21.9 million for the six months ended June 30, 2017 (Successor) and 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 $18.0 million and $14.8 million of expenses incurred for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively, relate to gathering and other fees paid on our oil and natural gas production. Also included are $4.6 million and $6.3 million of rig stacking or termination charges for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

During the six months ended June 30, 2017 (Successor), we incurred $0.8 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in conjunction with the El Halcón Divestiture. During the six months ended June 30, 2016 (Predecessor), we incurred $5.1 million in severance costs and accelerated stock-based compensation expense related to a reduction in our workforce due to the decrease in our drilling and developmental activities planned for that year.

General and administrative expense was $26.5 million and $62.7 million, for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. General and administrative expense in the prior year period included $29.5 million in 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 $3.91 per Boe and $9.13 per Boe for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively.

Share-based compensation expense was $21.3 million and $3.7 million, for the six months ended June 30, 2017 (Successor) and 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 $9.13 per Boe and $13.21 per Boe for the six months ended June 30, 2017 (Successor) and 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.

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 June 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 June 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 $754.8 million for the six months ended June 30, 2016 (Predecessor). The ceiling test impairments in 2016 were driven by decreases in the first-day-of-the-month average price for crude oil used in the ceiling test calculations since December 31, 2015, when the first-day-of-the-month average price for crude oil was $50.28 per barrel. 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.

We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the six months ended June 30, 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.

condensed consolidated statements of operations. At June 30, 2017 (Successor), we had a $31.9 million derivative asset, $26.4 million of which was classified as current and we had a $0.6 million derivative liability, $0.3 million of which was classified as current associated with these contracts. We recorded a net derivative gain of $50.6 million ($42.2 million net unrealized gain and $8.4 million net realized gain on settled contracts) for the six months ended June 30, 2017 (Successor) compared to a net derivative loss of $35.8 million ($224.3 million net unrealized loss and $188.5 million net realized gain on settled contracts) in the same period in 2016 (Predecessor).

Interest expense and other was $44.5 million and $106.1 million for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor), respectively. Capitalized interest for the six months ended June 30, 2017 (Successor) and 2016 (Predecessor) was zero and $52.9 million, respectively. Gross interest expense was $155.8 million for the six months ended June 30, 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.

During the six months ended June 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 provision of $12.0 million for the six months ended June 30, 2017 (Successor), representing the estimated alternative minimum tax generated primarily by the gain from the sale of the El Halcón Assets.

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

We are exposed to various risks, including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable; therefore, we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and 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.

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.

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

At June 30, 2017 (Successor), the principal amount of our debt was $1.1 billion, of which approximately 86.3% bears interest at a weighted average fixed interest rate of 7.4% per year. The remaining 13.7% of our total debt at June 30, 2017 (Successor) bears interest at floating or market interest rates that, at our option, are tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At June 30, 2017 (Successor), the weighted average interest rate on our variable rate debt was 4.7% per year. If the balance of our variable interest rate debt at June 30, 2017 (Successor) were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $0.7 million per year.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of June 30, 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 June 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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.

There can be no assurance that our divestiture of our Williston Basin operated assets will be consummated on the terms set forth in the Agreement of Sale and Purchase or at all.

On July 10, 2017, we and certain of our wholly-owned subsidiaries entered into an Agreement of Sale and Purchase for the sale of all of our operated oil and gas leases, oil and gas wells and associated assets located in the Williston Basin. The completion of the divestiture is subject to various closing conditions and termination rights. We cannot guarantee that the closing conditions set forth in the Agreement of Sale and Purchase will be satisfied or, even if satisfied, that no event of termination will take place. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed and we may not receive the benefits of the transaction while yet having incurred many of the expenses associated with it. Further, depending on the circumstances relating to the failure of the transaction to close, we might be subjected to additional costs, as well as reputational or other harm, which could, in turn, adversely impact our business, the trading price of our common stock and any future divestiture of our Williston Basin operated assets.

Our Williston Basin operated assets represent 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 six months ended June 20, 2017, our Williston Basin operated assets represented approximately 77% 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, will transform 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 Southern 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 affect on our results of operations, financial condition and prospects.

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 as of July 10, 2017, by and among Halcón Energy Properties, Inc., Halcón Operating Co., Inc., HRC Operating, LLC, and HRC Energy, LLC, as sellers, Halcón Williston I, LLC and Halcón Williston II, LLC, as the companies, Bruin Williston Holdings, LLC, as purchaser, and Halcón Resources Corporation, as guarantor (Incorporated by referenced to Exhibit 2.1 of our Current Report on Form 8-K filed July 11, 2017).

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).

10.1	†	Amendment No. 1 to the Halcón Resources Corporation 2016 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed May 4, 2017).

10.2		Support Agreement dated as of July 10, 2017, by and among Halcón Resources Corporation and the consenting noteholders named therein (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 11, 2017).

10.3		Second Amendment to Senior Secured Revolving Credit Agreement, dated July 12, 2017, by and among Halcón Resources Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders signatory thereto (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed July 14, 2017).

12.1	*	Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends

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


	HALCÓN RESOURCES CORPORATION
August 3, 2017	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board, Chief Executive Officer and President
August 3, 2017	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
August 3, 2017	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Senior Vice President, Chief Accounting Officer and Controller


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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


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



PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Stockholders' Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Unaudited Condensed Consolidated Financial Statements	9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	46
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	66
ITEM 4.	Controls and Procedures	67
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	68
ITEM 1A.	Risk Factors	68
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	68
ITEM 3.	Defaults Upon Senior Securities	68
ITEM 4.	Mine Safety Disclosures	69
ITEM 5.	Other Information	69
ITEM 6.	Exhibits	69
Signatures		71

	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


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


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


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


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

	Successor		Predecessor

	Six Months Ended June 30, 2017 (Unaudited)		Six Months Ended June 30, 2016 (Unaudited)



Revenue	$	263,637	$	201,411
Net income (loss)		216,553		(911,990	)
Net income (loss) available to common stockholders		168,546		(946,903	)
Pro forma net income (loss) per share of common stock:
Basic	$	1.43	$	(7.87	)
Diluted	$	1.43	$	(7.87	)

	Successor

	June 30, 2017
	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	31,866	$	—	$	31,866



Liabilities
Liabilities from derivative contracts	$	—	$	643	$	—	$	643

	Successor

	June 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		131,672		112,826		123,827
6.75% senior notes		850,000		765,408		—		—

	$	962,826	$	897,080	$	812,826	$	857,077

		Asset derivative contracts					Liability derivative contracts

		Successor					Successor
Derivatives not designated as hedging contracts under ASC 815	Balance sheet	June 30, 2017		December 31, 2016		Balance sheet	June 30, 2017			December 31, 2016
Commodity contracts	Current assets—receivables from derivative contracts	$	26,389	$	5,923	Current liabilities—liabilities from derivative contracts	$	(280	)	$	(16,434	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		5,477		—	Other noncurrent liabilities—liabilities from derivative contracts		(363	)		(486	)

Total derivatives not designated as hedging contracts under ASC 815		$	31,866	$	5,923		$	(643	)	$	(16,920	)

	Derivative Assets						Derivative Liabilities

	Successor						Successor
Offsetting of Derivative Assets and Liabilities	June 30, 2017			December 31, 2016			June 30, 2017			December 31, 2016
Gross Amounts Presented in the Consolidated Balance Sheet	$	31,866		$	5,923		$	(643	)	$	(16,920	)
Amounts Not Offset in the Consolidated Balance Sheet		(669	)		(5,283	)		642			5,075

Net Amount	$	31,197		$	640		$	(1	)	$	(11,845	)


Liability for asset retirement obligations as of December 31, 2016 (Successor)	$	32,375
Liabilities settled and divested⁽¹⁾		(8,342	)
Additions		176
Acquisitions⁽¹⁾		2,194
Accretion expense		856

Liability for asset retirement obligations as of June 30, 2017 (Successor)	$	27,259


Remaining period in 2017	$	1,695
2018		3,430
2019		2,997
2020		1,811
2021		1,497
Thereafter		2,180

Total	$	13,610

Year		Percentage

2020			105.063
2021			103.375
2022			101.688
2023 and thereafter			100.000


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

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

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

101.INS	*	XBRL Instance Document

101.SCH	*	XBRL Taxonomy Extension Schema Document

101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	*	XBRL Taxonomy Extension Definition Document

101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document