BATTALION OIL CORP - Quarter Report: 2016 September (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2016
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number: 001-35467

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


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

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

(832) 538-0300
(Registrant's telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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

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

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


Large Accelerated Filer o		Accelerated Filer ý		Non-Accelerated Filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o

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

At November 4, 2016, 92,638,093 shares of the Registrant's Common Stock were outstanding.

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		Page

PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Stockholders' Equity	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Unaudited Condensed Consolidated Financial Statements	10
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	51
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	69
ITEM 4.	Controls and Procedures	70
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings	71
ITEM 1A.	Risk Factors	71
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	76
ITEM 3.	Defaults Upon Senior Securities	76
ITEM 4.	Mine Safety Disclosures	76
ITEM 5.	Other Information	76
ITEM 6.	Exhibits	77
Signatures		79

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Special note regarding forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition or divestiture opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2015 and herein (Part II, Item 1A), as well as the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

•: volatility in commodity prices for oil and natural gas, including the current sustained decline in the price for oil;
•: our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and develop our undeveloped acreage positions;
•: our ability to replace our oil and natural gas reserves and production;
•: we have historically had substantial indebtedness and we may incur more debt in the future;
•: higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;
•: the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
•: our ability to successfully develop our large inventory of undeveloped acreage in our resource plays;
•: our ability to retain key members of senior management, the board of directors, and key technical employees;
•: access to and availability of water and other treatment materials to carry out fracture stimulations in our resource plays;
•: access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices;
•: contractual limitations that affect our management's discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;
•: the potential for production decline rates for our wells to be greater than we expect;
•: competition, including competition for acreage in our resource plays;
•: environmental risks;
•: drilling and operating risks;

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•: exploration and development risks;
•: the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations);
•: general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;
•: social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or acts of terrorism or sabotage;
•: other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;
•: our ability to successfully integrate acquired oil and natural gas businesses and operations;
•: the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management's time and energy;
•: the insurance coverage maintained by us may not adequately cover all losses that we may sustain;
•: title to the properties in which we have an interest may be impaired by title defects;
•: senior management's ability to execute our plans to meet our goals;
•: the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars; and
•: our dependency on the skill, ability and decisions of third party operators of the oil and natural gas properties in which we have a non-operated working interest.

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

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PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Successor			Predecessor

	Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016			Three Months Ended September 30, 2015
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	21,260		$	74,002		$	121,845
Natural gas		823			2,610			5,058
Natural gas liquids		798			2,488			2,615

Total oil, natural gas and natural gas liquids sales		22,881			79,100			129,518
Other		226			247			421

Total operating revenues		23,107			79,347			129,939

Operating expenses:
Production:
Lease operating		3,791			12,473			22,248
Workover and other		1,565			6,801			4,769
Taxes other than income		2,173			7,442			12,102
Gathering and other		2,637			7,376			9,091
Restructuring		—			95			434
General and administrative		16,681			17,317			21,027
Depletion, depreciation and accretion		9,051			25,618			77,071
Full cost ceiling impairment		420,934			—			511,882

Total operating expenses		456,832			77,122			658,624

Income (loss) from operations		(433,725	)		2,225			(528,685	)
Other income (expenses):
Net gain (loss) on derivative contracts		(7,575	)		17,783			204,621
Interest expense and other, net		(5,479	)		(16,136	)		(57,977	)
Reorganization items		(556	)		913,722			—
Gain (loss) on extinguishment of debt		—			—			535,141

Total other income (expenses)		(13,610	)		915,369			681,785

Income (loss) before income taxes		(447,335	)		917,594			153,100
Income tax benefit (provision)		(3,357	)		8,666			(6,025	)

Net income (loss)		(450,692	)		926,260			147,075
Series A preferred dividends		—			(2,451	)		(4,196	)
Preferred dividends and accretion on redeemable noncontrolling interest		(791	)		(7,388	)		(19,351	)

Net income (loss) available to common stockholders	$	(451,483	)	$	916,421		$	123,528



Net income (loss) per share of common stock:
Basic	$	(4.96	)	$	7.58		$	1.05



Diluted	$	(4.96	)	$	6.06		$	0.88



Weighted average common shares outstanding:
Basic		91,071			120,905			117,211



Diluted		91,071			151,876			150,958

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (Continued)

(In thousands, except per share amounts)

	Successor			Predecessor

	Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016			Nine Months Ended September 30, 2015
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	21,260		$	248,064		$	404,368
Natural gas		823			9,511			17,595
Natural gas liquids		798			7,929			10,572

Total oil, natural gas and natural gas liquids sales		22,881			265,504			432,535
Other		226			1,339			1,622

Total operating revenues		23,107			266,843			434,157

Operating expenses:
Production:
Lease operating		3,791			50,032			81,266
Workover and other		1,565			22,507			11,614
Taxes other than income		2,173			24,453			37,246
Gathering and other		2,637			29,279			30,583
Restructuring		—			5,168			2,664
General and administrative		16,681			83,641			68,098
Depletion, depreciation and accretion		9,051			120,555			297,409
Full cost ceiling impairment		420,934			754,769			2,014,518
Other operating property and equipment impairment		—			28,056			—

Total operating expenses		456,832			1,118,460			2,543,398

Income (loss) from operations		(433,725	)		(851,617	)		(2,109,241	)
Other income (expenses):
Net gain (loss) on derivative contracts		(7,575	)		(17,998	)		216,805
Interest expense and other, net		(5,479	)		(122,249	)		(180,206	)
Reorganization items		(556	)		913,722			—
Gain (loss) on extinguishment of debt		—			81,434			557,907
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			—			(8,219	)

Total other income (expenses)		(13,610	)		854,909			586,287

Income (loss) before income taxes		(447,335	)		3,292			(1,522,954	)
Income tax benefit (provision)		(3,357	)		8,666			(6,224	)

Net income (loss)		(450,692	)		11,958			(1,529,178	)
Series A preferred dividends		—			(8,847	)		(13,999	)
Preferred dividends and accretion on redeemable noncontrolling interest		(791	)		(35,905	)		(39,069	)

Net income (loss) available to common stockholders	$	(451,483	)	$	(32,794	)	$	(1,582,246	)



Net income (loss) per share of common stock:
Basic	$	(4.96	)	$	(0.27	)	$	(15.28	)



Diluted	$	(4.96	)	$	(0.27	)	$	(15.28	)



Weighted average common shares outstanding:
Basic		91,071			120,513			103,525



Diluted		91,071			120,513			103,525

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	Successor			Predecessor

	September 30, 2016			December 31, 2015
Current assets:
Cash	$	2,011		$	8,026
Accounts receivable		125,244			173,624
Receivables from derivative contracts		70,835			348,861
Restricted cash		165			16,812
Prepaids and other		7,713			9,270

Total current assets		205,968			556,593

Oil and natural gas properties (full cost method):
Evaluated		1,202,727			7,060,721
Unevaluated		329,218			1,641,356

Gross oil and natural gas properties		1,531,945			8,702,077
Less—accumulated depletion		(429,361	)		(5,933,688	)

Net oil and natural gas properties		1,102,584			2,768,389

Other operating property and equipment:
Gas gathering and other operating assets		38,097			130,090
Less—accumulated depreciation		(203	)		(22,435	)

Net other operating property and equipment		37,894			107,655

Other noncurrent assets:
Receivables from derivative contracts		2,816			16,614
Debt issuance costs, net		—			7,633
Funds in escrow and other		1,786			1,808

Total assets	$	1,351,048		$	3,458,692



Current liabilities:
Accounts payable and accrued liabilities	$	170,992		$	295,085
Liabilities from derivative contracts		1,415			—
Other		4,938			163

Total current liabilities		177,345			295,248

Long-term debt, net		1,004,524			2,873,637
Other noncurrent liabilities:
Liabilities from derivative contracts		1,122			290
Asset retirement obligations		31,082			46,853
Other		4,139			6,264
Commitments and contingencies (Note 10)
Mezzanine equity:
Redeemable noncontrolling interest		—			183,986
Stockholders' equity:
Predecessor Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 244,724 shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding		—			—
Predecessor Common stock: 1,340,000,000 shares of $0.0001 par value authorized; 122,523,559 shares issued and outstanding		—			12
Predecessor Additional paid-in capital		—			3,283,097
Successor Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 92,638,093 shares issued and outstanding		9			—
Successor Additional paid-in capital		584,310			—
Retained earnings (accumulated deficit)		(451,483	)		(3,230,695	)

Total stockholders' equity		132,836			52,414

Total liabilities and stockholders' equity	$	1,351,048		$	3,458,692

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Preferred Stock					Common Stock

	Preferred Stock					Common Stock						Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity
	Shares			Amount		Shares			Amount			Additional Paid-In Capital			Accumulated Deficit			Stockholders' Equity
Balances at December 31, 2014 (Predecessor)		345		$	—		85,562		$	8		$	2,995,436		$	(1,223,275	)	$	1,772,169
Net income (loss)		—			—		—			—			—			(1,922,621	)		(1,922,621	)
Dividends on Series A preferred stock		—			—		1,354			1			9,801			(17,979	)		(8,177	)
Conversion of Series A preferred stock		(100	)		—		3,258			—			—			—			—
Preferred dividends on redeemable noncontrolling interest		—			—		—			—			—			(12,614	)		(12,614	)
Accretion of redeemable noncontrolling interest		—			—		—			—			—			(53,561	)		(53,561	)
Change in fair value of redeemable noncontrolling interest		—			—		—			—			—			(645	)		(645	)
Common stock issuance		—			—		1,888			—			15,356			—			15,356
Common stock issuance on conversion of senior notes		—			—		28,955			3			231,380			—			231,383
Modification of February 2012 Warrants		—			—		—			—			14,129			—			14,129
Offering costs		—			—		—			—			(1,871	)		—			(1,871	)
Long-term incentive plan grants		—			—		2,048			—			—			—			—
Long-term incentive plan forfeitures		—			—		(388	)		—			—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(153	)		—			(947	)		—			(947	)
Share-based compensation		—			—		—			—			19,813			—			19,813

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)		—			—		—			—			—			(450,692	)		(450,692	)
Preferred dividends on redeemable noncontrolling interest		—			—		—			—			—			(791	)		(791	)
Long-term incentive plan grants		—			—		2,638			—			—			—			—
Share-based compensation		—			—		—			—			13,196			—			13,196

Balances at September 30, 2016 (Successor)		—		$	—		92,638		$	9		$	584,310		$	(451,483	)	$	132,836

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Successor			Predecessor

	Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016			Nine Months Ended September 30, 2015
Cash flows from operating activities:
Net income (loss)	$	(450,692	)	$	11,958		$	(1,529,178	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		9,051			120,555			297,409
Full cost ceiling impairment		420,934			754,769			2,014,518
Other operating property and equipment impairment		—			28,056			—
Share-based compensation, net		13,196			4,876			11,245
Unrealized loss (gain) on derivative contracts		30,338			263,732			93,972
Amortization and write-off of deferred loan costs		—			6,371			6,002
Non-cash interest and amortization of discount and premium		377			1,515			2,029
Reorganization items		560			(929,084	)		—
Loss (gain) on extinguishment of debt		—			(81,434	)		(557,907	)
Loss (gain) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			—			8,219
Accrued settlements on derivative contracts		(22,695	)		—			(37,803	)
Other income (expense)		(94	)		(4,233	)		5,805
Change in assets and liabilities:
Accounts receivable		12,541			47,920			75,331
Prepaids and other		(81	)		(4,329	)		2,216
Accounts payable and accrued liabilities		(1,113	)		(45,324	)		(59,664	)

Net cash provided by (used in) operating activities		12,322			175,348			332,194

Cash flows from investing activities:
Oil and natural gas capital expenditures		(10,289	)		(226,617	)		(531,741	)
Other operating property and equipment capital expenditures		(231	)		(950	)		(9,913	)
Funds held in escrow and other		(1,721	)		(207	)		2,988

Net cash provided by (used in) investing activities		(12,241	)		(227,774	)		(538,666	)

Cash flows from financing activities:
Proceeds from borrowings		30,000			886,000			1,579,000
Repayments of borrowings		(32,000	)		(727,648	)		(1,392,000	)
Cash payments to Noteholders and Preferred Holders		(10,013	)		(97,521	)		—
Debt issuance costs		—			(1,977	)		(25,703	)
Series A preferred dividends		—			—			(4,656	)
Common stock issued		—			—			15,354
Offering costs and other		—			(511	)		(2,982	)

Net cash provided by (used in) financing activities		(12,013	)		58,343			169,013

Net increase (decrease) in cash		(11,932	)		5,917			(37,459	)
Cash at beginning of period		13,943			8,026			43,713

Cash at end of period	$	2,011		$	13,943		$	6,254



Supplemental cash flow information:
Cash paid (received) for reorganization items	$	(4	)	$	15,362		$	—
Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	—		$	(23,966	)	$	(442	)
Asset retirement obligations		8			939			2,405
Series A preferred dividends paid in common stock		—			—			9,803
Preferred dividends on redeemable noncontrolling interest paid-in-kind		791			9,329			9,340
Accretion of redeemable noncontrolling interest		—			26,576			29,084
Change in fair value of redeemable noncontrolling interest		—			—			645
Accrued debt issuance costs		—			1,176			—
Common stock issued on conversion of senior notes		—			—			231,383
Third Lien Notes issued on conversion of senior notes		—			—			1,017,994

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

Halcón Resources Corporation (Halcón or the Company) is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned and controlled subsidiaries. The Company operates in one segment focused 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 property 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 February 26, 2016. Please refer to the notes in the 2015 Annual Report on Form 10-K when reviewing interim financial results, though, as described below, such prior financial statements may not be comparable to the interim financial statements due to the adoption of fresh-start accounting on September 9, 2016.

Emergence from Voluntary Reorganization under Chapter 11

On July 27, 2016 (the Petition Date), the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a joint prepackaged plan of reorganization (the Plan). On September 8, 2016, the Bankruptcy Court entered an order confirming the Plan and on September 9, 2016, the Plan became effective (the Effective Date) and the Halcón Entities emerged from chapter 11 bankruptcy. The Company's subsidiary, HK TMS, LLC which was divested on September 30, 2016, was not part of the chapter 11 bankruptcy filings. See Note 2, "Reorganization," for further details on the Company's chapter 11 bankruptcy and the Plan and Note 4, "Divestiture" 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) No. 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, September 9, 2016. As a result of the adoption of fresh-start accounting, the Company's unaudited condensed consolidated financial statements subsequent to September 9, 2016 may not be comparable to its unaudited condensed consolidated financial statements prior to 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.

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

Use of Estimates

The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue, 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, 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 are uncertain and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's unaudited condensed consolidated financial statements.

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

Accounts Receivable and Allowance for Doubtful Accounts

The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. There were no material allowances for doubtful accounts as of September 30, 2016 (Successor) or December 31, 2015 (Predecessor).

Other Operating Property and Equipment

Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year or 10-year estimated useful life applicable to gas gathering systems 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. With the adoption of fresh-start accounting, the Company recorded its gas gathering systems and equipment at fair value totaling approximately $16.3 million as of the fresh-start reporting date. Refer to Note 3, "Fresh-start Accounting," for a discussion of the valuation approach used.

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

Other operating assets 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, 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. With the adoption of fresh-start accounting, the Company recorded its other operating assets at fair value totaling approximately $21.8 million as of the fresh-start reporting date. Refer to Note 3, "Fresh-start Accounting," for a discussion of the valuation approach used.

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 an asset's undiscounted cash flows, then the Company recognizes an impairment loss for the difference between the carrying amount and the current fair value. The Company also 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 three months ended March 31, 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, which resulted in negative net cash flows due to insufficient throughput of natural gas volumes and certain fixed costs necessary to operate and maintain the assets. This estimation includes the use of unobservable inputs, such as estimated future production, and 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.

Recently Issued Accounting Pronouncements

In August 2016, the FASB issued Accounting Standards Update (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.

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

In March 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-09, Compensation—Stock Compensation (ASU 2016-09). For public business entities, ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. The areas for simplification in this ASU involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Some of the areas for simplification apply only to nonpublic entities. As there are multiple amendments in this ASU, the FASB has issued guidance on how an entity should apply each amendment, either prospectively or retrospectively. The Company adopted ASU 2016-09 on September 9, 2016. See Note 12, "Stockholders' Equity" for further details.

In March 2016, the FASB issued ASU No. 2016-06, Contingent Put and Call Options in Debt Instruments (ASU 2016-06). For public business entities, ASU 2016-06 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. ASU 2016-06 provides new guidance that simplifies the analysis of whether a contingent put or call option in a debt instrument qualifies as a separate derivative. An entity should apply the amendments in this ASU on a modified retrospective basis to existing debt instruments as of the beginning of the fiscal year for which the amendments are effective. 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 process of assessing the effects of the application of the new guidance.

In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (ASU 2015-17) to simplify the presentation of deferred income taxes. Under ASU 2015-17, all deferred tax assets and liabilities, along with any related valuation allowance, are required to be classified as noncurrent on the balance sheet. Effective December 31, 2015, the Company early adopted ASU 2015-17, on a prospective basis, which resulted in the reclassification of its current deferred tax assets and liabilities as a non-current deferred tax asset and liability, net of the valuation allowance, in the accompanying unaudited condensed consolidated balance sheets. No prior periods were retrospectively adjusted.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). For public business entities, ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and early adoption is permitted. The amendments in this ASU require that an acquirer, in a business combination, recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. To simplify the accounting for adjustments made to provisional amounts recognized in a business combination, the amendments in this ASU eliminate the requirement to retrospectively

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account for those adjustments, and instead present separately on the face of the income statement or disclose in the footnotes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods. The adoption of ASU 2015-16 did not have an impact to the Company's financial statements or disclosures.

In April 2015, the FASB issued ASU No. 2015-05, Intangibles—Goodwill and Other—Internal-Use Software (ASU 2015-05). ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. For public business entities, the guidance is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. An entity can elect to adopt the guidance either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. Early adoption is permitted. The Company adopted prospectively and it did not have a material impact to the Company's financial statements or disclosures.

In February 2015, the FASB issued ASU No. 2015-02, Amendments to the Consolidation Analysis (ASU 2015-02). The amendments in ASU 2015-02 eliminate the previous presumption that a general partner controls a limited partner. ASU 2015-02 may impact the Company's accounting for its general partner interest in SBE Partners LP (SBE Partners), which is currently accounted for as an equity method investment. ASU 2015-02 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Entities may apply the guidance using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the first fiscal year adopted or it may apply the amendment retrospectively. The adoption of ASU 2015-02 did not have an impact on the Company's accounting for its general partner interest in SBE Partners, LP.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (ASU 2014-15). ASU 2014-15 is effective for annual reporting periods (including interim periods within those periods) ending after December 15, 2016. Early application is permitted with companies applying the guidance prospectively. The amendments in ASU 2014-15 create a new ASC Sub-topic 205-40, Presentation of Financial Statements—Going Concern and require management to assess for each annual and interim reporting period if conditions exist that raise substantial doubt about an entity's ability to continue as a going concern. The rule requires various disclosures depending on the facts and circumstances surrounding an entity's ability to continue as a going concern. Effective June 30, 2016, the Company early adopted ASU 2014-15 on a prospective basis.

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

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 process of assessing the effects of the application of the new guidance.

2. REORGANIZATION

On June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company's 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the 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 Company's plan of reorganization (the Plan) and on September 9, 2016, the Halcón Entities emerged from chapter 11 bankruptcy.

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

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

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2. REORGANIZATION (Continued)

$15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims;

•: the general unsecured claims were unimpaired and paid in full in the ordinary course;
•: all outstanding shares of the Predecessor Company's Series A Preferred Stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and
•: all of the Predecessor Company's outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests.

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 12, "Stockholders' Equity," and other future issuances of equity interests.

See Note 6, "Debt," and Note 12, "Stockholders' Equity," for further information regarding the Company's Successor and Predecessor debt and equity instruments.

3. FRESH-START ACCOUNTING

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

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

Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company's long-term debt, stockholders' equity and working capital. The estimated Enterprise Value at the Effective Date is below the midpoint of the Court approved range of $1.6 billion to $1.8 billion,

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3. FRESH-START ACCOUNTING (Continued)

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 are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment.

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

	September 9, 2016

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

Fair Value of Successor common stock	$	554,432

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3. FRESH-START ACCOUNTING (Continued)

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

	September 9, 2016

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

Reorganization Value of Successor assets	$	1,843,626

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. FRESH-START ACCOUNTING (Continued)

Condensed Consolidated Balance Sheet

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

	As of September 9, 2016

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

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

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

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

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

Other operating property and equipment:
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

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3. FRESH-START ACCOUNTING (Continued)

Reorganization adjustments

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


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

Total Uses	$	97,521

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


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

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

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

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


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

Cancellation of Predecessor Company equity	$	3,254,642

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

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3. FRESH-START ACCOUNTING (Continued)

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

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


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

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

Fresh-start accounting adjustments

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

9): In estimating the fair value of its gas gathering and other operating assets, the Company used a combination of the income, cost, and market approaches.

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

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

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

10): Reflects the adjustment of the Company's equity method investment in SBE Partners, L.P. to fair value based on an income approach, which calculated the discounted cash flows of the Company's share of the partnership's interest in oil and gas proved reserves. The anticipated cash flows of the reserve were risked by reserve category and discounted at 10.5%. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts' estimated prices.
11): Records an intangible liability of approximately $8.3 million, $4.5 million of which was recorded as current, to adjust the Company's active rig contract to fair value at September 9, 2016. The intangible liability will be amortized over the remaining life of the contract through July 2018.
12): Reflects the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of September 9, 2016, adjusted for inflation and then discounted at the appropriate credit-adjusted risk free rate ranging from 5.5% to 6.6% depending on the life of the well. The fair value of asset retirement obligations was estimated at $32.5 million, approximately $0.3 million of which was recorded as current. Refer to Note 9, "Asset Retirement Obligations" for further details of the Company's asset retirement obligations.
13): Reflects the adjustment of the 2020 Second Lien Notes and the 2022 Second Lien Notes to fair value. The fair value estimate was based on quoted market prices from trades of such debt on September 9, 2016. Refer to Note 6, "Debt" for definitions of and further information regarding the 2020 Second Lien Notes and 2022 Second Lien Notes.
14): Reflects the adjustment of the Company's redeemable noncontrolling interest and related embedded derivative of HK TMS, LLC to fair value. The fair value of the redeemable noncontrolling interest was estimated at $41.1 million and the embedded derivative was estimated at zero. For purposes of estimating the fair values, an income approach was used that estimated fair value based on the anticipated cash flows associated with HK TMS, LLC's proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 12.5%. The value of the redeemable noncontrolling interest was further reduced by a probability factor of the potential assignment of the common shares of HK TMS, LLC to Apollo Global Management, which occurred subsequent to the fresh-start date. Refer to Note 4, "Divestiture," for further information regarding the divestiture of HK TMS, LLC on September 30, 2016.
15): Reflects the cumulative effect of the fresh-start accounting adjustments discussed above.

Reorganization Items

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

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

	Successor			Predecessor

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

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

4. DIVESTITURE

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 classified as "Mezzanine Equity" on the unaudited condensed consolidated balance sheets of HK TMS, from and after such date. Refer to Note 11, "Mezzanine Equity" for further details of the accounting considerations for HK TMS.

Effective with the HK TMS Divestiture, all of the Successor Company's existing 100% owned subsidiaries are joint and several, full and unconditional guarantors of its long-term debt obligations and the Successor Company has no independent assets or operations. As a consequence, the Successor Company has discontinued the presentation of condensed consolidating financial statements which separately presented HK TMS's non-guarantor financial position, statements of operations and statements of cash flows.

5. OIL AND NATURAL GAS PROPERTIES

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

With the adoption of fresh-start accounting, the Company recorded its oil and natural properties at fair value as of September 9, 2016. The Company's evaluated and unevaluated properties were assigned

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values of $1.2 billion and $332.1 million, respectively. Refer to Note 3, "Fresh-start Accounting," for a discussion of the valuation approach used.

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

Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Predecessor Company determined capitalized interest by multiplying the Predecessor Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool. The capitalized interest amounts were recorded as additions to unevaluated oil and natural gas properties on the unaudited condensed consolidated balance sheets. For the period from January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), the Company capitalized interest costs of $68.2 million and $80.0 million, respectively. Upon the adoption of fresh-start accounting, the Successor Company revised its accounting policy on the capitalization of interest and expects future capitalized interest amounts to be minimal.

At September 30, 2016, the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended September 30, 2016 of the West Texas Intermediate (WTI) crude oil spot price of $41.68 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended September 30, 2016 of the Henry Hub natural gas price of $2.28 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at September 30, 2016 (Successor) exceeded the ceiling amount by $420.9 million ($268.1 million after taxes, before valuation allowance) which resulted in a ceiling test impairment of that amount for the period of September 10, 2016 through September 30, 2016 (Successor). The impairment at September 30, 2016 reflects the differences between the first day of the month average prices for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date of September 9, 2016.

At June 30, 2016 (Predecessor) and March 31, 2016 (Predecessor), the Company recorded a full cost ceiling impairment before income taxes of $257.9 million ($163.1 million after taxes, before valuation allowance) and $496.9 million ($315.1 million after taxes, before valuation allowance), respectively. The ceiling test impairments at March 31, 2016 and June 30, 2016, were driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculations since December 31, 2015, when the first-day-of-month 12-month average price for crude oil was $50.28 per barrel. The impairment at March 31, 2016 also reflects the transfer of the remaining

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5. OIL AND NATURAL GAS PROPERTIES (Continued)

unevaluated Utica / Point Pleasant (Utica) and TMS properties of approximately $330.4 million and $74.8 million, respectively, to the full cost pool. As discussed above, the Company considers the facts and circumstances around its unevaluated properties that may indicate impairment on a quarterly basis. For the quarter ended March 31, 2016, management concluded that it was no longer probable that capital would be available or approved to continue exploratory drilling activities in the Company's Utica or TMS acreage positions in advance of the related lease expirations due to the Company's evaluation of strategic alternatives to reduce its debt and preserve liquidity in light of continued low commodity prices, together with a reduction of the Company's exploration department and the Company's intent to expend capital only on its most economical and proven areas.

At September 30, 2015 (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 September 30, 2015 of the WTI crude oil spot price of $59.21 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended September 30, 2015 of the Henry Hub natural gas price of $3.06 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at September 30, 2015 (Predecessor) exceeded the ceiling amount by $511.9 million ($322.3 million after taxes before valuation allowance) which resulted in a ceiling test impairment of that amount for the quarter. At June 30, 2015 (Predecessor) and March 31, 2015 (Predecessor), the Company recorded full cost ceiling impairments before income taxes of $948.6 million ($597.3 million after taxes before valuation allowance) and $554.0 million ($348.8 million after taxes before valuation allowance), respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014, when the first-day-of-the-month average price for crude oil was $94.99 per barrel.

The Company recorded the full cost ceiling test impairments in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

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6. DEBT

As of September 30, 2016 (Successor) and December 31, 2015 (Predecessor), the Company's long-term debt consisted of the following (in thousands):

	Successor		Predecessor

	September 30, 2016		December 31, 2015
Successor senior revolving credit facility	$	228,000	$	—
Predecessor senior revolving credit facility		—		62,000
8.625% senior secured second lien notes due 2020⁽¹⁾		670,715		687,797
12.0% senior secured second lien notes due 2022⁽²⁾		105,809		111,598
13.0% senior secured third lien notes due 2022⁽³⁾⁽⁸⁾		—		1,009,585
9.25% senior notes due 2022⁽⁴⁾⁽⁸⁾		—		51,887
8.875% senior notes due 2021⁽⁵⁾⁽⁸⁾		—		347,671
9.75% senior notes due 2020⁽⁶⁾⁽⁸⁾		—		336,470
8.0% convertible note due 2020⁽⁷⁾⁽⁸⁾		—		266,629

	$	1,004,524	$	2,873,637

(1): Amount is net of $12.2 million unamortized debt issuance costs at December 31, 2015 (Predecessor). Amount is net of a $29.3 million discount at September 30, 2016 (Successor).
(2): Amount is net of $1.2 million unamortized debt issuance costs at December 31, 2015 (Predecessor). Amount is net of a $7.0 million discount at September 30, 2016 (Successor).
(3): Amount is net of $8.4 million unamortized debt issuance costs at December 31, 2015 (Predecessor).
(4): Amount is net of $0.8 million unamortized debt issuance costs at December 31, 2015 (Predecessor).
(5): Amount is net of a $1.0 million unamortized discount at December 31, 2015 (Predecessor) related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $5.5 million at December 31, 2015 (Predecessor). Amount is net of $5.8 million unamortized debt issuance costs at and December 31, 2015 (Predecessor). See "8.875% Senior Notes" below for more details.
(6): Amount is net of a $1.9 million unamortized discount at December 31, 2015 (Predecessor) related to the issuance of the original 2020 Notes. The unamortized premium related to the additional 2020 Notes was approximately $2.6 million at December 31, 2015 (Predecessor). Amount is net of $4.3 million unamortized debt issuance costs at December 31, 2015 (Predecessor). See "9.75% Senior Notes" below for more details.
(7): Amount is net of a $23.0 million unamortized discount at December 31, 2015 (Predecessor). See "8.0% Convertible Note" below for more details.
(8): These notes were cancelled on September 9, 2016 upon emergence from chapter 11 bankruptcy. Contractual interest expense not accrued or recorded on pre-petition debt as a result of the chapter 11 bankruptcy amounted to $25.2 million for the period from July 27, 2016 to September 9, 2016.

Successor Senior Revolving Credit Facility

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

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financial institutions party thereto, as lenders, which refinanced the DIP facility, discussed below. The Senior Credit Agreement currently provides for a $600.0 million senior secured reserve-based revolving credit facility. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of the Company's 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120th day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, 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). The Company may be required to make mandatory prepayments under the Senior Credit Agreement in connection with certain borrowing base deficiencies. 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 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, commencing with the fiscal quarter ending December 31, 2016. At September 30, 2016, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

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

At September 30, 2016, the Company had approximately $228.0 million of indebtedness outstanding, approximately $5.0 million letters of credit outstanding and approximately $367.0 million of borrowing capacity available under the Senior Credit Agreement.

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6. DEBT (Continued)

DIP Facility

In connection with the chapter 11 bankruptcy proceedings, the Predecessor Company entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and to replace it upon emergence with a $600.0 million senior secured reserve-based revolving credit facility, discussed above. Proceeds from the DIP Facility were used to refinance borrowings under the Predecessor Credit Agreement (defined below). Availability under the DIP Facility was $500.0 million upon interim approval by the Bankruptcy Court, and rose to $600.0 million upon entry of a final order. The DIP Facility was refinanced by the Senior Credit Agreement, upon emergence from chapter 11 bankruptcy. Loans under the DIP Facility bore 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 fluctuated based on the utilization of the DIP Facility.

Predecessor Senior Revolving Credit Facility

On February 8, 2012, the Predecessor Company entered into a senior secured revolving credit agreement (the Predecessor Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Predecessor Credit Agreement provided for a $1.5 billion facility with a borrowing base of $700.0 million. Amounts outstanding under the Predecessor Credit Agreement bore interest at specified margins over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% for Eurodollar-based loans. These margins fluctuated based on the utilization of the facility. Proceeds from the DIP Facility were used to refinance borrowings under the Company's Predecessor Credit Agreement.

8.625% Senior Secured Second Lien Notes

On May 1, 2015, 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 placement. 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 Predecessor Company used the net proceeds from the offering to repay the majority of the then outstanding borrowings under its Predecessor Credit Agreement.

The 2020 Second Lien Notes bear interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year. The 2020 Second Lien Notes will mature on February 1, 2020. The 2020 Second Lien Notes are secured by second-priority liens on substantially all of the Company's and its subsidiaries' assets to the extent such assets secure the Company's Senior Credit Agreement and its 2022 Second Lien Notes (defined below) (the Collateral). Pursuant to the terms of an Intercreditor Agreement, dated May 1, 2015, as amended by those certain Priority Confirmation Joinders, dated September 10, 2015 and December 21, 2015, in connection with the issuance of the Third Lien Notes and the 2022 Second Lien Notes (discussed below), respectively (the Intercreditor Agreement), the security interest in those assets that secure the 2020 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 2020 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 such assets. The Collateral does not include any of the assets of the

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Company's future unrestricted subsidiaries. In accordance with the terms of the Plan, the 2020 Second Lien Notes were unimpaired and reinstated upon the Company's emergence from the chapter 11 bankruptcy.

As discussed in Note 3, "Fresh-start Accounting," on September 9, 2016, the Company adjusted the 2020 Second Lien Notes to fair value of $679.0 million by recording a discount of $21.0 million to be amortized over the remaining life of the 2020 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 2020 Second Lien Note Supplemental Indenture) to the Indenture dated as of May 1, 2015 with respect to the Company's 2020 Second Lien Notes (the 2020 Second Lien Note Indenture). The 2020 Second Lien Note Supplemental Indenture amended the 2020 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2020 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 $8.6 million to holders of the 2020 Second Lien Notes and recorded an additional discount of approximately $8.6 million.

The remaining unamortized discount was $29.3 million at September 30, 2016.

12.0% Senior Secured Second Lien Notes

On December 21, 2015, 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, beginning on February 15, 2016. The 2022 Second Lien Notes will mature on February 15, 2022. The 2022 Second Lien Notes are secured by second-priority liens on 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 equal with the liens that secure the 2020 Second Lien Notes and 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 and effectively equal to the 2020 Second Lien Notes, in each case 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 2020 Second Lien Notes, using the effective interest method.

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6. DEBT (Continued)

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 $7.0 million at September 30, 2016.

13.0% Senior Secured Third Lien Notes

On September 10, 2015, the Predecessor Company issued approximately $1.02 billion aggregate principal amount of new 13.0% senior secured third lien notes due 2022 (the Third Lien Notes) in a private placement in exchange for approximately $497.2 million principal amount of its then outstanding 9.75% senior notes due 2020, $774.7 million principal amount of its then outstanding 8.875% senior notes due 2021 and $294.4 million principal amount of its then outstanding 9.25% senior notes due 2022 in privately negotiated transactions with certain holders of its senior unsecured notes. The Predecessor Company recorded the issuance of the Third Lien Notes at par and also recognized a $535.1 million net gain on the extinguishment of debt, as a $548.2 million gain on the exchanges was partially offset by the writedown of $13.1 million associated with related issuance costs and discounts and premiums for the respective notes. The net gain was recorded in "Gain (loss) on extinguishment of debt" in the unaudited condensed consolidated statements of operation for the three months ended September 30, 2015 (Predecessor). The Third Lien Notes bore interest at a rate of 13.0% per annum and were scheduled to mature on February 15, 2022.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the Third Lien Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

9.25% Senior Notes

On August 13, 2013, the Predecessor Company issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting offering fees and expenses) were used to repay a portion of the then outstanding borrowings under the Company's Predecessor Credit Agreement. The 2022 Notes bore interest at a rate of 9.25% per annum and were scheduled to mature on February 15, 2022.

During the first quarter of 2016, the Predecessor Company repurchased $15.5 million principal amount of 2022 Notes for cash at prevailing market prices at the time of the transactions and recognized an $11.1 million net gain on the extinguishment of debt.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the 2022 Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

8.875% Senior Notes

On November 6, 2012, the Predecessor Company issued $750.0 million aggregate principal amount of its 8.875% senior notes due 2021 (the 2021 Notes), at a price to the initial purchasers of 99.247% of

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

par. The net proceeds from the offering of approximately $725.6 million (after deducting offering fees and expenses) and were used to fund a portion of the cash consideration paid in the Williston Basin Acquisition. On January 14, 2013, the Predecessor Company issued an additional $600.0 million aggregate principal amount of the 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes of approximately $619.5 million (after offering fees and expenses) were used to repay all of the then outstanding borrowings under the Predecessor Credit Agreement and for general corporate purposes, including funding a portion of the Predecessor Company's 2013 capital expenditures program. These notes were issued as "additional notes" under the indenture governing the 2021 Notes and under the indenture were treated as a single series with substantially identical terms as the 2021 Notes previously issued.

The 2021 Notes bore interest at a rate of 8.875% per annum and were scheduled to mature on May 15, 2021. In conjunction with the issuance of the 2021 Notes, the Predecessor Company recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. In conjunction with the issuance of the additional 2021 Notes, the Predecessor Company recorded a premium of approximately $30.0 million to be amortized over the remaining life of the additional 2021 Notes using the effective interest method.

During the first quarter of 2016, the Predecessor Company repurchased $51.8 million principal amount of the 2021 Notes for cash at prevailing market prices at the time of the transactions and recognized a $47.5 million net gain on the extinguishment of debt.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the 2021 Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

9.75% Senior Notes

On July 16, 2012, the Predecessor Company issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million (after deducting offering fees and expenses) and were used to fund a portion of the cash consideration paid in the merger with GeoResources, Inc., and the acquisition of certain oil and gas leaseholds located in East Texas. On December 19, 2013, the Predecessor Company issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.3 million (after deducting offering fees and expenses) were used to repay a portion of the then outstanding borrowings under the Predecessor Credit Agreement. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

The 2020 Notes bore interest at a rate of 9.75% per annum and were scheduled to mature on July 15, 2020. In conjunction with the issuance of the 2020 Notes, the Predecessor Company recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. In conjunction with the issuance of the additional 2020 Notes, the Predecessor Company recorded a premium of approximately $11.0 million to be amortized over the remaining life of the additional 2020 Notes using the effective interest method.

During the first quarter of 2016, the Predecessor Company repurchased $24.5 million principal amount of the 2020 Notes for cash at prevailing market prices at the time of the transactions and recognized a $22.8 million net gain on the extinguishment of debt.

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6. DEBT (Continued)

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the 2020 Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

8.0% Convertible Note

On February 8, 2012, the Predecessor Company issued to HALRES, LLC (HALRES), a note in the principal amount of $275.0 million due 2017 (the Convertible Note) together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. The Convertible Note bore interest at a rate of 8% per annum. Through the March 31, 2014 interest payment date, the Predecessor Company was permitted to elect to pay the interest in kind, by adding to the principal of the Convertible Note, all or any portion of the interest due on the Convertible Note. The Predecessor Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and added $3.2 million, $5.7 million and $5.8 million of interest incurred, respectively, to the Convertible Note, increasing the principal amount to $289.7 million. On March 9, 2015, the Predecessor Company entered into an amendment (the HALRES Note Amendment) to its Convertible Note, which extended the maturity date of the Convertible Note by three years and adjusted the conversion price of the Convertible Note from $22.50 per share to $12.20 per share. The Predecessor Company accounted for the HALRES Note Amendment as a debt extinguishment and recorded a net gain of $7.3 million in "Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants" in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2015 (Predecessor).

On September 9, 2016, and upon emergence from chapter 11 bankruptcy, the Convertible Note was cancelled. Refer to Note 2, "Reorganization," for further details.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. For the period from January 1, 2016 through September 9, 2016, the Predecessor Company expensed $7.9 million of debt issuance costs in conjunction with debt repurchases, decreases in the borrowing base under the Predecessor Credit Agreement, and refinancing of the Predecessor Credit Agreement. At December 31, 2015 (Predecessor), the Company had approximately $40.3 million of debt issuance costs capitalized related to its Predecessor senior secured and unsecured debt. 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 Company's Predecessor Credit Agreement are presented in "Debt issuance costs, net", and the debt issuance costs for the Company's senior unsecured debt are presented in "Long-term debt, net" within total liabilities on the unaudited condensed consolidated balance sheet at December 31, 2015 (Predecessor).

7. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820, Fair Value Measurements (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's unaudited condensed consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of September 30, 2016 (Successor) and December 31, 2015 (Predecessor) (in thousands):

	Successor

	September 30, 2016
	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	73,651	$	—	$	73,651



Liabilities
Liabilities from derivative contracts	$	—	$	2,507	$	30	$	2,537

	Predecessor


	December 31, 2015
	Level 1		Level 2		Level 3		Total
Assets
Receivables from derivative contracts	$	—	$	365,475	$	—	$	365,475



Liabilities
Liabilities from derivative contracts	$	—	$	105	$	185	$	290

Derivative contracts listed above as Level 2 include collars, swaps and swaptions 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" in the Company's 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

Derivative contracts listed above as Level 3 include extendable collars that are carried at fair value. The significant unobservable inputs for these Level 3 contracts include unpublished forward strip prices and market volatilities. The following table sets forth a reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy (in thousands):

	Significant Unobservable Inputs (Level 3)

	Successor			Predecessor
	September 30, 2016			December 31, 2015
Beginning Balance	$	(185	)	$	(1,319	)
Net gain (loss) on derivative contracts		155			1,134

Ending Balance	$	(30	)	$	(185	)

	Successor		Predecessor

	Period from September 10, 2016 through September 30, 2016		Period from January 1, 2016 through September 9, 2016		December 31, 2015
Change in unrealized gains (losses) included in earnings related to derivatives still held at September 30, 2016 (Successor), September 9, 2016 (Predecessor), and December 31, 2015 (Predecessor)	$	18	$	137	$	(185	)

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

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

December 31, 2015 (Predecessor) (excluding discounts, premiums and debt issuance costs) (in thousands):

	Successor				Predecessor

	September 30, 2016				December 31, 2015
Debt	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
8.625% senior secured second lien notes	$	700,000	$	707,000	$	700,000	$	479,500
12.0% senior secured second lien notes		112,826		112,826		112,826		77,286
13.0% senior secured third lien notes⁽¹⁾		—		—		1,017,970		333,385
9.25% senior notes⁽¹⁾		—		—		52,694		14,422
8.875% senior notes⁽¹⁾		—		—		348,944		95,506
9.75% senior notes⁽¹⁾		—		—		340,035		93,068
8.0% convertible note⁽¹⁾		—		—		289,669		87,393

	$	812,826	$	819,826	$	2,862,138	$	1,180,560

⁽¹⁾: These notes were cancelled on September 9, 2016 upon emergence from chapter 11 bankruptcy.

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. The fair value of the Predecessor Company's Convertible Note was based on published market prices and risk-free rates.

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 three months ended March 31, 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.

As discussed in Note 6, "Debt" and in Note 12, "Stockholders' Equity," on May 6, 2015 (Predecessor), the HALRES Note Amendment and the Warrant Amendment became effective. The fair value estimates for the Convertible Note and the February 2012 Warrants included the use of observable inputs such as the Predecessor Company's stock price, expected volatility, and credit spread and the risk-free rate. The use of these observable inputs results in the fair value estimates being classified as Level 2.

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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES

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

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

At September 30, 2016 (Successor) and December 31, 2015 (Predecessor), the Company's crude oil and natural gas derivative positions consisted of swaps, swaptions, costless put/call "collars," and extendable costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. 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. Extendable collars are costless put/call contracts that may be extended annually at the option of the counterparty on a designated date. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

At September 30, 2016 (Successor), the Company had 37 open commodity derivative contracts summarized in the following tables: one natural gas collar arrangement, 18 crude oil collar arrangements, 12 crude oil swaps, five crude oil swaptions and one crude oil extendable collar.

At December 31, 2015 (Predecessor), the Company had 36 open commodity derivative contracts summarized in the following tables: one natural gas collar arrangement, 16 crude oil collar arrangements, 13 crude oil swaps, five crude oil swaptions and one crude oil extendable collar.

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

unaudited condensed consolidated balance sheets as of September 30, 2016 (Successor) and December 31, 2015 (Predecessor) (in thousands):

		Asset derivative contracts					Liability derivative contracts

		Successor		Predecessor			Successor			Predecessor
Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	September 30, 2016		December 31, 2015		Balance sheet location	September 30, 2016			December 31, 2015


Commodity contracts	Current assets—receivables from derivative contracts	$	70,835	$	348,861	Current liabilities—liabilities from derivative contracts	$	(1,415	)	$	—
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		2,816		16,614	Other noncurrent liabilities—liabilities from derivative contracts		(1,122	)		(290	)

Total derivatives not designated as hedging contracts under ASC 815		$	73,651	$	365,475		$	(2,537	)	$	(290	)

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

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

		Successor			Predecessor
Derivatives not designated as hedging contracts under ASC 815	Location of gain or (loss) recognized in income on derivative contracts	Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016			Three Months Ended September 30, 2015
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(30,338	)	$	(39,451	)	$	89,741
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		22,763			57,234			114,880

Total net gain (loss) on derivative contracts		$	(7,575	)	$	17,783		$	204,621

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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

		Successor			Predecessor
		Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016
								Nine Months Ended September 30, 2015
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815

Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(30,338	)	$	(263,732	)	$	(93,972	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		22,763			245,734			310,777

Total net gain (loss) on derivative contracts		$	(7,575	)	$	(17,998	)	$	216,805

At September 30, 2016 (Successor) and December 31, 2015 (Predecessor), the Company had the following open crude oil and natural gas derivative contracts:

			Successor

			September 30, 2016
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
October 2016 - December 2016⁽¹⁾	Collars	Natural Gas		184,000	$4.00	$	4.00	$4.22	$	4.22
October 2016 - December 2016⁽²⁾⁽³⁾	Collars	Crude Oil		920,000	60.00 - 90.00		74.30	64.00 - 95.10		80.26
October 2016 - December 2016⁽⁴⁾⁽⁵⁾	Swaps	Crude Oil		1,104,000	62.00 - 91.73		84.91
January 2017 - December 2017	Collars	Crude Oil		3,923,750	47.00 - 60.00		51.29	52.00 - 76.84		60.41

			Predecessor


			December 31, 2015
					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
January 2016 - June 2016	Collars	Crude Oil		182,000	$90.00	$	90.00	$96.85	$	96.85
January 2016 - December 2016	Collars	Natural Gas		732,000	4.00		4.00	4.22		4.22
January 2016 - December 2016⁽²⁾	Collars	Crude Oil		4,392,000	60.00 - 90.00		71.91	64.00 - 95.10		77.71
January 2016 - December 2016⁽⁴⁾	Swaps	Crude Oil		4,758,000	62.00 - 91.73		85.43
January 2017 - December 2017	Collars	Crude Oil		1,368,750	50.00 - 60.00		57.33	70.00 - 76.84		74.16

(1): Subsequent to September 30, 2016, the Successor Company entered into a natural gas collar for 5,000 MMBtu per day for 2017 at a floor of $3.15 per MMBtu and a ceiling of $3.50 per MMBtu.
(2): Includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $60.00 per Bbl and a ceiling of $75.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2017.
(3): Subsequent to September 30, 2016, the Successor Company entered into crude oil collars totaling 4,000 barrels per day for 2017 at floors ranging from $49.40 to $51.50 per barrel and ceilings ranging from $54.40 to $56.50 per barrel.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

(4): Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended by the counterparty at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.
(5): Subsequent to September 30, 2016, the Successor Company entered into crude oil swaps totaling 4,000 barrels per day for the fourth quarter of 2016 at $50.00 per barrel.

The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at September 30, 2016 (Successor) and December 31, 2015 (Predecessor) (in thousands):

	Derivative Assets						Derivative Liabilities

	Successor			Predecessor			Successor			Predecessor
	Successor			Predecessor			Successor			Predecessor
	September 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015

Offsetting of Derivative Assets and Liabilities
Gross Amounts Presented in the Consolidated Balance Sheet	$	73,651		$	365,475		$	(2,537	)	$	(290	)
Amounts Not Offset in the Consolidated Balance Sheet		(2,506	)		(53	)		2,408			52

Net Amount	$	71,145		$	365,422		$	(129	)	$	(238	)

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

9. ASSET RETIREMENT OBLIGATIONS

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. ASSET RETIREMENT OBLIGATIONS (Continued)

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


Liability for asset retirement obligations as of December 31, 2015 (Predecessor)	$	47,016
Liabilities settled and divested		(180	)
Additions		1,044
Acquisitions		75
Accretion expense		1,414

Liability for asset retirement obligations as of September 9, 2016 (Predecessor)	$	49,369



Fair value fresh-start adjustment	$	(16,883	)

Liability for asset retirement obligations as of September 9, 2016 (Successor)	$	32,486
Liabilities settled and divested⁽¹⁾		(1,211	)
Additions		8
Accretion expense		131

Liability for asset retirement obligations as of September 30, 2016 (Successor)	$	31,414

(1): See Note 4, "Divestiture," for further information.

10. COMMITMENTS AND CONTINGENCIES

Commitments

The Company leases corporate office space in Houston, Texas and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $0.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and $5.9 million for the period of January 1, 2016 through September 9, 2016 (Predecessor). Rent expense was approximately $6.4 million for the nine months ended September 30, 2015 (Predecessor). In connection with the chapter 11 bankruptcy, the Company modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. Future obligations associated with the Company's operating leases are presented in the table below (in thousands):


Remaining period in 2016	$	867
2017		3,493
2018		3,540
2019		2,997
2020		1,811
Thereafter		3,677

Total	$	16,385

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS AND CONTINGENCIES (Continued)

In addition, the Company has commitments for certain equipment under long-term operating lease agreements, namely drilling rigs, with various expiration dates through 2018. In the first quarter of 2016, the Company entered into an amendment to one of its drilling rig contracts with an original term ending date of August 31, 2016, whereby, as of April 5, 2016 (Predecessor), the Company early terminated the rig contract, incurred a termination fee of approximately $1.2 million and reduced its 2016 drilling commitments by extending part of the contract term on another of its drilling rig contracts out further in 2018. In January 2015, the Company made the decision to early terminate a drilling rig contract in response to the decline in crude oil prices, and the Company incurred an early termination fee of $6.0 million, paid over the first half of 2015 (Predecessor). If certain requirements are not met by two separate trigger dates, the first being January 1, 2017 and the second being January 12, 2020, the Company may incur up to an additional $3.0 million in connection with this drilling rig contract. Rig termination fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations.

In addition, the Company has two drilling rig commitments, for which the Company is incurring a stacking fee of $16,000 and $17,000 per day. The contract terms for these drilling rig commitments extend through the second quarter of 2017 and 2018, respectively. Rig stacking fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations. Early termination of the Company's additional drilling rig commitments would result in termination penalties approximating $13.0 million, which would be in lieu of the remaining $18.2 million of drilling rig commitments as of September 30, 2016 (Successor).

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. As of September 30, 2016 (Successor), the Company had in place eight long-term crude oil contracts and five long-term natural gas contracts in this area. Under the terms of these contracts, the Company has committed a substantial portion of its Bakken/Three Forks production 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.

Contingencies

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

11. MEZZANINE EQUITY

On June 16, 2014 (Predecessor), funds and accounts managed by Apollo contributed $150 million in cash to HK TMS, a Delaware limited liability company, which was then wholly owned by the Company and held all of the Company's undeveloped acreage in the TMS formation, located in Mississippi and Louisiana, in exchange for the issuance by HK TMS of 150,000 preferred shares. At the closing, the Company also contributed $50 million in cash to HK TMS. Holders of the HK TMS preferred shares were to receive quarterly cash dividends of 8% cumulative perpetual per annum,

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. MEZZANINE EQUITY (Continued)

subject to HK TMS' option to pay such dividends "in-kind" through the issuance of additional preferred shares. The preferred shares were expected to be automatically redeemed and cancelled when the holders receive cash dividends and distributions on the preferred shares equating to the greater of a 12% annual rate of return plus principal and 1.25 times their investment plus applicable fees (the Redemption Price), subject to adjustment under certain circumstances. The preferred shares had a liquidation preference in the event of dissolution in an amount equal to the Redemption Price plus any unpaid dividends not otherwise included in the calculation of the Redemption Price through the date of liquidation payment. HK TMS was also allowed to redeem the preferred shares at any time after December 31, 2016 by paying the Redemption Price, and under certain circumstances it would have been required to redeem the preferred shares for the Redemption Price plus certain fees. On September 30, 2016, certain wholly-owned subsidiaries of the Successor Company executed an Assignment and Assumption Agreement with an affiliate of Apollo pursuant to which 100% of the Membership Interests in HK TMS were assigned to Apollo. In exchange for the assignment, Apollo assumed all obligations relating to such Membership Interests. See Note 4, "Divestiture," for further information regarding the HK TMS Divestiture.

On June 1, 2015 (Predecessor), HK TMS and Apollo entered into an amendment to the original agreement (the HK TMS Amendment) which, among other things, i) committed HK TMS to drill a minimum of 6.5 net wells in each of the five consecutive twelve month periods beginning December 31, 2015 and ii) allowed for the redemption of preferred shares at the Redemption Price between March 1, 2016 and June 30, 2016 at the election of Apollo to the extent there was available cash above the minimum cash balance, which is discussed further below. For any commitment period in which HK TMS did not meet its drilling obligation, HK TMS would have been required to use available cash, above the minimum cash balance, to redeem preferred shares at the Redemption Price.

The preferred shares were classified as "Redeemable noncontrolling interest" and included in "Mezzanine equity" between total liabilities and stockholders' equity on the unaudited condensed consolidated balance sheets pursuant to ASC 480-10-S99-3A. 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 "Redeemable noncontrolling interest" on the unaudited condensed consolidated balance sheets and within "Preferred dividends and accretion on redeemable noncontrolling interest" on the unaudited condensed consolidated statements of operations. In accordance with ASC 480-10-S99-3A, an adjustment to the carrying amount presented in "Mezzanine equity" was recognized as charges against retained earnings and reduced income available to common shareholders in the calculation of earnings per share.

HK TMS was required to maintain a minimum cash balance equal to two quarterly dividend payments, of approximately $3.5 million each, plus $10.0 million, which was presented on the unaudited condensed consolidated balance sheets in "Restricted cash" at December 31, 2015 (Predecessor).

In March 2015 (Predecessor), Apollo delivered a withdrawal notice to HK TMS indicating their election not to acquire additional preferred shares in HK TMS (the Withdrawal Notice). Upon issuance of the Withdrawal Notice, HK TMS incurred a fee escalating from $2.50 per share to $20.00 per share for the next eight full fiscal quarters for any preferred shares then outstanding, which began in the quarter ended June 30, 2015 (the Withdrawal Exit Fee). The Withdrawal Exit Fee would have been payable upon redemption of the preferred shares and was recorded at fair value within "Other

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. MEZZANINE EQUITY (Continued)

noncurrent liabilities" on the unaudited condensed consolidated balance sheets at December 31, 2015 (Predecessor).

The following table sets forth a reconciliation of the changes in fair value of the embedded derivative associated with the amended transaction, which is classified as Level 3 in the fair value hierarchy (in thousands):

	Embedded derivative

Balance at December 31, 2015 (Predecessor)	$	6,100
Change in fair value		(5,734	)

Balance at September 9, 2016 (Predecessor)	$	366



Fair value fresh-start adjustment	$	(366	)

Balance at September 9, 2016 (Successor) and at September 30, 2016 (Successor)	$	—

The Company recorded the following activity related to the preferred shares recorded in "Mezzanine equity" on the unaudited condensed consolidated balance sheets for the period presented (in thousands, except share amounts):

	Redeemable noncontrolling interest

	Shares			Amount
Balances at December 31, 2015 (Predecessor)		165,639		$	183,986
Dividends paid in-kind		9,329			9,329
Accretion of redeemable noncontrolling interest		—			26,576

Balances at September 9, 2016 (Predecessor)		174,968		$	219,891



Fair value fresh-start adjustment		—		$	(178,821	)

Balances at September 9, 2016 (Successor)		174,968		$	41,070
Dividends paid in-kind		791			791
HK TMS Divestiture⁽¹⁾		(175,759	)		(41,861	)

Balance at September 30, 2016 (Successor)		—		$	—

(1): See Note 4, "Divestiture," for further information regarding the HK TMS Divestiture.

For the period of September 10, 2016 through September 30, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor), HK TMS issued 791 and 9,329 additional preferred shares to Apollo for dividends paid-in-kind, respectively. For the nine months ended September 30, 2015 (Predecessor), HK TMS issued 9,340 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. Upon the election of in-kind dividends, HK TMS was required to pay a fee of $5.00 per preferred share then outstanding (PIK Exit Fee). Such fees would have been due upon redemption of the preferred shares and were

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. MEZZANINE EQUITY (Continued)

recorded at fair value within "Other noncurrent liabilities" on the unaudited condensed consolidated balance sheets.

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

12. STOCKHOLDERS' EQUITY

Common Stock

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

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the 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 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 Company from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code. Additionally, the Company's 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred), was cancelled pursuant to the Plan, and no shares of Series A Preferred are outstanding.

Warrants

On September 9, 2016, upon the emergence from chapter 11 bankruptcy, all existing February 2012 warrants were cancelled and the 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 "Successor Additional paid-in capital" on the unaudited condensed consolidated balance sheet at September 30, 2016 (Successor). The holders are entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020. See Note 2, "Reorganization" for further details.

Incentive Plans

Immediately prior to emergence from chapter 11 bankruptcy, the 2006 Long-Term Incentive Plan (Predecessor Incentive Plan) of the Predecessor Company was cancelled and all share-based compensation awards granted thereunder were either vested or cancelled and the former board of directors 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, are 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,

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. STOCKHOLDERS' EQUITY (Continued)

performance bonuses, stock awards and other incentive awards. As of September 30, 2016 (Successor), a maximum of 2.4 million shares of common stock 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 period from September 10, 2016 through September 30, 2016 (Successor), the period from July 1, 2016 through September 9, 2016 (Predecessor) and the period from January 1, 2016 through September 9, 2016 (Predecessor) the Company recognized $13.2 million, $1.2 million, and $4.9 million, respectively, of share-based compensation expense. For the three and nine months ended September 30, 2015 (Predecessor), the Company recognized $3.0 million and $11.2 million, respectively, of share-based compensation expense. Share-based compensation expense is recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

Stock Options

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.

During the period from September 10, 2016 through September 30, 2016 (Successor), in accordance with the terms of the Plan, the Company granted stock options under the 2016 Incentive Plan covering 5.0 million shares of common stock to employees of the Company. These stock options have an exercise price of $9.24 per share with a weighted average exercise price of $9.24 per share. These awards 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. At September 30, 2016 (Successor), the Company had $29.8 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.9 years.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. STOCKHOLDERS' EQUITY (Continued)

The following table sets forth the stock option transactions for the period from September 10, 2016 through September 30, 2016 (Successor):

		Weighted Average Exercise Price Per Share		Aggregate Intrinsic Value(1) (In thousands)

Outstanding at September 9, 2016 (Successor)	—	$	—	$	—	—
Granted	5,000		9.24
Exercised	—		—
Forfeited	—		—

Outstanding at September 30, 2016 (Successor)	5,000	$	9.24	$	714	10.0

(1): The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. No stock options were exercised during the period from September 10, 2016 through September 30, 2016 (Successor).

The assumptions used in calculating the Black-Scholes-Merton valuation model fair value of the Successor Company's stock options for the period from September 10, 2016 through September 30, 2016 (Successor) are set forth in the following table:

	Stock Option Valuation Assumptions

Weighted average value per option granted during the period	$	6.15
Assumptions:
Stock price volatility⁽¹⁾		56.3	%
Risk free rate of return		1.3	%
Expected term		6 years

(1): Due to the Company's limited historical data, expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available.

Restricted Stock

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.

During the period from September 10, 2016 through September 30, 2016 (Successor), in accordance with the terms of the Plan, the Company granted 2.6 million shares of restricted stock under the 2016 Incentive Plan to non-employee directors and employees of the Company. These restricted shares were granted at prices ranging from $7.82 to $9.24 per share with a weighted average price of $9.17 per share. Non-employee directors' shares vest six-months from the date of grant. For restricted stock awards granted on September 12, 2016 (Successor), half vested immediately on the date

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. STOCKHOLDERS' EQUITY (Continued)

of the grant and the remaining half will vest on the first anniversary of the date of grant. At September 30, 2016 (Successor), the Company had $12.0 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 0.9 years.

The following table sets forth the restricted stock transactions for the period from September 10, 2016 through September 30, 2016 (Successor):

			Weighted Average Grant Date Fair Value Per Share		Aggregate Intrinsic Value(1) (In thousands)

Unvested shares outstanding at September 9, 2016 (Successor)	—		$	—	$	—
Granted	2,638			9.17
Vested	(1,250	)		9.24
Forfeited	—			—

Unvested shares outstanding at September 30, 2016 (Successor)	1,388		$	9.10	$	13,020

(1): The intrinsic value of restricted stock was calculated as the closing market price on September 30, 2016 of the underlying stock multiplied by the number of restricted shares. The total fair value of shares vested was $11.5 million for the period from September 10, 2016 to September 30, 2016 (Successor).

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. EARNINGS PER COMMON SHARE

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

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

	Successor			Predecessor

	Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016		Three Months Ended September 30, 2015
Basic:
Net income (loss) available to common stockholders	$	(451,483	)	$	916,421	$	123,528



Weighted average basic number of common shares outstanding		91,071			120,905		117,211

Basic net income (loss) per share of common stock	$	(4.96	)	$	7.58	$	1.05



Diluted:
Net income (loss) available to common stockholders	$	(451,483	)	$	916,421	$	123,528



Interest on Convertible Note, net		—			1,522		4,664
Series A preferred dividends		—			2,451		4,196

Net income (loss) available to common stockholders after assumed conversions	$	(451,483	)	$	920,394	$	132,388



Weighted average basic number of common shares outstanding		91,071			120,905		117,211
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive		Anti-dilutive
Exercise of February 2012 Warrants		—			Anti-dilutive		Anti-dilutive
Exercise of warrants		Anti-dilutive			—		—
Vesting of restricted shares		Anti-dilutive			Anti-dilutive		Anti-dilutive
Vesting of performance units		—			—		—
Conversion of Convertible Note		—			23,743		23,744
Conversion of Series A Preferred Stock		—			7,228		10,003

Weighted average diluted number of common shares outstanding		91,071			151,876		150,958

Diluted net income (loss) per share of common stock	$	(4.96	)	$	6.06	$	0.88

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. EARNINGS PER COMMON SHARE (Continued)

	Successor			Predecessor

	Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016			Nine Months Ended September 30, 2015
Basic:
Net income (loss) available to common stockholders	$	(451,483	)	$	(32,794	)	$	(1,582,246	)



Weighted average basic number of common shares outstanding		91,071			120,513			103,525

Basic net income (loss) per share of common stock	$	(4.96	)	$	(0.27	)	$	(15.28	)



Diluted:
Net income (loss) available to common stockholders	$	(451,483	)	$	(32,794	)	$	(1,582,246	)



Interest on Convertible Note, net		—			—			—
Series A preferred dividends		—			—			—

Net income (loss) available to common stockholders after assumed conversions	$	(451,483	)	$	(32,794	)	$	(1,582,246	)



Weighted average basic number of common shares outstanding		91,071			120,513			103,525
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		—			Anti-dilutive			Anti-dilutive
Exercise of warrants		Anti-dilutive			—			—
Vesting of restricted shares		Anti-dilutive			Anti-dilutive			Anti-dilutive
Vesting of performance units		—			—			—
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		91,071			120,513			103,525

Diluted net income (loss) per share of common stock	$	(4.96	)	$	(0.27	)	$	(15.28	)

Common stock equivalents, including stock options, warrants, restricted shares, convertible debt and preferred stock totaling 11.1 million, 11.9 million and 43.6 million shares for the period from September 10, 2016 through September 30, 2016 (Successor), the period from July 1, 2016 through September 9, 2016 (Predecessor), the period from January 1, 2016 through September 9, 2016 (Predecessor), respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

Common stock equivalents, including stock options, warrants and restricted shares totaling 13.1 million shares for the three months ended September 30, 2015 (Predecessor) 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. EARNINGS PER COMMON SHARE (Continued)

debt, and preferred stock totaling 47.8 million shares for the nine months ended September 30, 2015 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss.

14. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

	Successor		Predecessor

	September 30, 2016		December 31, 2015
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	62,010	$	55,129
Joint interest accounts		38,832		67,626
Accrued settlements on derivative contracts		22,695		47,011
Affiliated partnership		221		176
Other		1,486		3,682

	$	125,244	$	173,624



Prepaids and other:
Prepaids	$	7,641	$	4,585
Inventory		—		4,635
Other		72		50

	$	7,713	$	9,270



Accounts payable and accrued liabilities:
Trade payables	$	37,605	$	47,261
Accrued oil and natural gas capital costs		33,991		54,651
Revenues and royalties payable		62,516		64,002
Accrued interest expense		12,666		88,499
Accrued employee compensation		7,102		2,829
Accrued lease operating expenses		11,837		20,036
Drilling advances from partners		93		7,964
Income taxes payable		3,863		9,172
Affiliated partnership		297		365
Other		1,022		306

	$	170,992	$	295,085

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

The following discussion is intended to assist in understanding our results of operations for the period of September 10, 2016 through September 30, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor) and the three and nine months ended September 30, 2015 (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, 2015, though as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see "Special note regarding forward-looking statements."

Overview

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas. In the years since, we 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 consist of proved reserves and undeveloped acreage positions in unconventional liquids-rich basins/fields, including the Bakken/Three Forks formations in North Dakota and the Eagle Ford formation in East Texas, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of continued production and broad flexibility to direct our capital resources to projects with the greatest potential returns.

Our average daily oil and natural gas production decreased in the first nine months of 2016 when compared to the same period in the prior year as we have curtailed our drilling and completion activities in response to the sustained decline in commodity prices. We have focused our drilling efforts on our most economic areas in the current price environment. During the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), production averaged 33,333 barrels of oil equivalent (Boe) per day (Boe/d) and 36,787 Boe/d, respectively, compared to average daily production of 41,696 Boe/d during the first nine months of 2015 (Predecessor). During the first nine months of 2016 (for the combined Successor and Predecessor periods), we participated in the drilling of 65 gross (21.2 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

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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 we significantly curtailed our capital spending, reduced operating costs, and have 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 October 2016 of $48.24 per Bbl, and holding it constant for two months to create a trailing 12-month period of average prices, that is more reflective of recent price trends, our ceiling test limitation would not have generated an additional impairment. Sustained lower commodity prices will continue to have a material impact upon our full cost ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

Reorganization

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 decision to continue to produce at current 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, 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 current 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:

•: the Predecessor Credit Agreement was refinanced and replaced with the DIP Facility, which was subsequently converted into the Senior Credit Agreement (see below for credit agreement definitions and further details regarding the credit agreements);

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

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

Fresh-start Accounting

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 may not be 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.

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HK TMS Divestiture

On September 30, 2016, 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. In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests, which were classified as "Mezzanine Equity" on the unaudited condensed consolidated balance sheets of HK TMS, from and after such date. The Tuscaloosa Marine Shale properties generated net production of approximately 530 Boe/d during the three months ended June 30, 2016 (Predecessor) and had 1.1 MMBoe of proved reserves at December 31, 2015 (Predecessor).

Successor Senior Revolving Credit Facility

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, which refinanced the DIP Facility, discussed below. The Senior Credit Agreement currently provides for a $600.0 million senior secured reserve-based revolving credit facility. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of our 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120^th day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, 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). We may be required to make mandatory prepayments under the Senior Credit Agreement in connection with certain borrowing base deficiencies. 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.

DIP Facility

In connection with the chapter 11 bankruptcy proceedings, we entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP

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Facility) and to replace it upon emergence with a $600.0 million senior secured reserve-based revolving credit facility, discussed above. Proceeds from the DIP Facility were used to refinance borrowings under our Predecessor Credit Agreement. Availability under the DIP Facility was $500.0 million upon interim approval by the Bankruptcy Court, and rose to $600.0 million upon entry of a final order. The DIP Facility was refinanced by the Senior Credit Agreement on the Effective Date. Loans under the DIP Facility bore 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 fluctuated based on the utilization of the DIP Facility.

Capital Resources and Liquidity

Our near-term capital spending requirements are expected to be funded with cash flows from operations and borrowings under our Senior Credit Agreement. On the Effective Date, we entered into 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 currently provides for a $600.0 million senior secured reserve-based revolving credit facility. The next borrowing base redetermination is scheduled for May 2017. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of the Company's 8.625% senior secured second lien notes due 2020, if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120^th day. 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). We may be required to make mandatory prepayments under the Senior Credit Agreement in connection with certain borrowing base deficiencies. 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 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 period 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, commencing with the fiscal quarter ending December 31, 2016. At September 30, 2016, we had approximately $228.0 million of indebtedness outstanding, $5.0 million letters of credit outstanding and approximately $367.0 million of borrowing capacity available under our Senior Credit Agreement. At September 30, 2016, 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 the Predecessor 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

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reorganization (as described above). Upon consummation of the Plan and emergence from chapter 11 bankruptcy, approximately $2.0 billion of our debt obligations were cancelled, reducing our ongoing interest obligations by more than $200 million annually.

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. 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. We therefore continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling success.

We use derivative instruments to provide partial protection against declines in oil and natural gas prices. The total volumes we hedge vary from period to period based on our view of current and future market conditions. Currently, we have approximately 77% of anticipated remaining 2016 oil production hedged at a weighted average price of $76.60 per Bbl. However, beyond 2016, we have currently hedged only a limited amount of our anticipated production. Sustained low commodity prices may adversely impact our liquidity and cash flows from operations. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivatives contracts for speculative trading purposes.

Cash Flow

Our primary sources of cash for the following periods presented were from operating and financing activities. In 2016, cash generated by operating and financing activities was used to fund our drilling and completion program and to support our reorganization Plan, as discussed above. See "Results of Operations" for a review of the impact of prices and volumes on sales. The period from of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) are distinct reporting periods as a result of our emergence from chapter 11 bankruptcy on September 9, 2016 and may not be comparable to prior periods.

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

	Successor			Predecessor

	Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016			Nine Months Ended September 30, 2015
Cash flows provided by (used in) operating activities	$	12,322		$	175,348		$	332,194
Cash flows provided by (used in) investing activities		(12,241	)		(227,774	)		(538,666	)
Cash flows provided by (used in) financing activities		(12,013	)		58,343			169,013

Net increase (decrease) in cash	$	(11,932	)	$	5,917		$	(37,459	)

Operating Activities. Net cash provided by operating activities for the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were $12.3 million and $175.3 million, respectively, compared to $332.2 million generated during the nine months ended September 30, 2015 (Predecessor). Historically, key drivers of net operating cash flows are commodity prices, production volumes, operating costs and realized settlements on our derivative contracts.

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

The $332.2 million of operating cash flows for the nine months ended September 30, 2015 (Predecessor) primarily reflect the impact of realized settlements on our derivative contracts, which largely mitigated the decrease in revenues due to lower commodity prices, as compared to the prior year period. Cash operating expenses also decreased over the prior year period.

Investing Activities. The primary driver of cash used in investing activities is capital spending, specifically on drilling and completions. Net cash used in investing activities for the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) was $12.2 million and $227.8 million, respectively, compared to $538.7 million used in investing activities during the nine months ended September 30, 2015 (Predecessor).

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

During the first nine months of 2015 (Predecessor), we spent $531.7 million on oil and natural gas capital expenditures, of which $418.7 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, leasing and seismic data. We significantly decreased our planned capital spending, as compared to capital expenditure levels in prior years, in response to the significant decrease in crude oil prices since mid-year 2014, and due to the expectation that prices may not recover in the near term. Cash paid for drilling and completion costs during the first nine

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months of 2015 were attributable to both costs incurred before we slowed our drilling and completion program and costs related to wells spud or drilled during the period.

Financing Activities. Net cash flows used in financing activities for the period of September 10, 2016 through September 30, 2016 (Successor) were $12.0 million. Net cash flows provided by financing activities for the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor) were $58.3 million and $169.0 million, respectively.

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

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

The primary drivers of cash provided by financing activities for the nine months ended September 30, 2015 were net borrowings on our Predecessor Credit Agreement. During the first nine months of 2015, cash flows from financing activities were modestly impacted by sales of our Predecessor common stock. For the nine months ended September 30, 2015 (Predecessor), we sold approximately 1.9 million shares of our Predecessor common stock for net proceeds of approximately $15.1 million.

Contractual Obligations

The following table summarizes our contractual obligations and commitments by payment periods as of September 30, 2016 (Successor).

	Payments Due by Period

Contractual Obligations	Total		Remaining period in 2016		Years 2017 - 2018		Years 2019 - 2020		Years 2021 and Beyond
Successor senior revolving credit facility	$	228,000	$	—	$	—	$	228,000	$	—
8.625% senior secured second lien notes due 2020		700,000		—		—		700,000		—
12.0% senior secured second lien notes due 2022		112,826		—		—		—		112,826
Interest expense on long-term debt⁽¹⁾		305,383		21,087		168,698		100,404		15,194
Operating leases		16,385		867		7,033		4,808		3,677
Drilling rig commitments		18,200		2,576		15,624		—		—
Rig stacking commitments		14,665		3,003		11,662		—		—

Total contractual obligations	$	1,395,459	$	27,533	$	203,017	$	1,033,212	$	131,697

(1): Future interest expense was calculated based on interest rates and amounts outstanding at September 30, 2016 less required annual repayments.

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We lease corporate office space in Houston, Texas and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $0.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and $5.9 million for the period January 1, 2016 through September 30, 2016 (Predecessor). Rent expense was approximately $6.4 million for the nine months ended September 30, 2015 (Predecessor). In connection with the chapter 11 bankruptcy, we modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. Future obligations associated with our operating leases are presented in the table above.

In addition, we have commitments for certain equipment under long-term operating lease agreements, namely drilling rigs, with various expiration dates through 2018. In the first quarter of 2016, we entered into an amendment to one of our drilling rig contracts with an original term ending date of August 31, 2016, whereby, as of April 5, 2016 (Predecessor), we early terminated the rig contract, incurred a termination fee of approximately $1.2 million and reduced our 2016 drilling commitments by extending part of the contract term on another of our drilling rig contracts out further in 2018. In January 2015 (Predecessor), we made the decision to early terminate a drilling rig contract in response to the decline in crude oil prices, and as such, we incurred an early termination fee of $6.0 million, paid over the first half of 2015. If certain requirements are not met by two separate trigger dates, the first being January 1, 2017 and the second being January 12, 2020, we may incur up to an additional $3.0 million in connection with this drilling rig contract. Rig termination fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations.

In addition, we have two drilling rig commitments, for which we are incurring a stacking fee of $16,000 and $17,000 per day. The contract terms for these drilling rig commitments extends through the second quarter of 2017 and 2018, respectively. Rig stacking fees are expensed as incurred within "Gathering and other" on the unaudited condensed consolidated statements of operations. Early termination of our other drilling rig commitments would result in termination penalties approximating $13.0 million, which would be in lieu of the remaining $18.2 million of drilling rig commitments as of September 30, 2016 (Successor).

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. As of September 30, 2016 (Successor), we had in place eight long-term crude oil contracts and five long-term natural gas contracts in this area. Under the terms of these contracts, we have committed a substantial portion of our Bakken/Three Forks production 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.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, except as described below.

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Fresh-start accounting

Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in ASC 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 3, "Fresh-Start Accounting," for further details.

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Results of Operations

Three Months Ended September 30, 2016 and 2015

The table included below sets forth financial information for the periods presented. The period of September 10, 2016 through September 30, 2016 (Successor Company) and the period of July 1, 2016 through September 9, 2016 (Predecessor Company) are distinct reporting periods as a result of our application of fresh-start accounting upon our emergence from chapter 11 bankruptcy on September 9, 2016 and may not be comparable to prior periods.

	Successor			Predecessor

In thousands (except per unit and per Boe amounts)	Period from September 10, 2016 through September 30, 2016			Period from July 1, 2016 through September 9, 2016			Three Months Ended September 30, 2015
Net income (loss)	$	(450,692	)	$	926,260		$	147,075
Operating revenues:
Oil		21,260			74,002			121,845
Natural gas		823			2,610			5,058
Natural gas liquids		798			2,488			2,615
Other		226			247			421
Operating expenses:
Production:
Lease operating		3,791			12,473			22,248
Workover and other		1,565			6,801			4,769
Taxes other than income		2,173			7,442			12,102
Gathering and other		2,637			7,376			9,091
Restructuring		—			95			434
General and administrative:
General and administrative		3,485			16,093			17,992
Share-based compensation		13,196			1,224			3,035
Depletion, depreciation and accretion:
Depletion—Full cost		8,716			24,115			74,651
Depreciation—Other		204			1,120			1,967
Accretion expense		131			383			453
Full cost ceiling impairment		420,934			—			511,882
Other income (expenses):
Net gain (loss) on derivative contracts		(7,575	)		17,783			204,621
Interest expense and other, net		(5,479	)		(16,136	)		(57,977	)
Reorganization items		(556	)		913,722			—
Gain (loss) on extinguishment of debt		—			—			535,141
Income tax benefit (provision)		(3,357	)		8,666			(6,025	)
Production:
Oil—MBbls		533			1,844			2,993
Natural Gas—Mmcf		521			1,718			2,300
Natural gas liquids—MBbls		80			315			371
Total MBoe(1)		700			2,445			3,748
Average daily production—Boe/d(1)		33,333			34,437			40,739
Average price per unit(2):
Oil price—Bbl	$	39.89		$	40.13		$	40.71
Natural gas price—Mcf		1.58			1.52			2.20
Natural gas liquids price—Bbl		9.98			7.90			7.05
Total per Boe(1)		32.69			32.35			34.56
Average cost per Boe:
Production:
Lease operating	$	5.42		$	5.10		$	5.94
Workover and other		2.24			2.78			1.27
Taxes other than income		3.10			3.04			3.23
Gathering and other		3.77			3.02			2.43
Restructuring		—			0.04			0.12
General and administrative:
General and administrative		4.98			6.58			4.80
Share-based compensation		18.85			0.50			0.81
Depletion		12.45			9.86			19.92

(1): Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.
(2): Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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Oil, natural gas and natural gas liquids revenues were $22.9 million, $79.1 million and $129.5 million for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. Average realized prices (excluding the effects of hedging arrangements) were $32.69 per Boe, $32.35 per Boe and $34.56 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. Oil and natural gas prices are inherently volatile and have decreased significantly since mid-year 2014 and have remained low throughout 2016. Average daily production has decreased, as we have curtailed our drilling in response to the decline in commodity prices.

Lease operating expenses on a per Boe basis were $5.42 per Boe, $5.10 per Boe and $5.94 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. The decrease in lease operating expenses per Boe from 2015 levels is primarily due to price decreases from our vendors in light of the current commodity price environment.

Workover and other expenses on a per Boe basis were $2.24 per Boe, $2.78 per Boe and $1.27 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. The increased costs per Boe in 2016 relate primarily to workovers in our Bakken area, specifically costs spent to restore production on wells with downhole problems and well casing repairs.

Taxes other than income on a per Boe basis were $3.10 per Boe, $3.04 per Boe and $3.23 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (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.

Gathering and other expenses on a per Boe basis were $3.77 per Boe, $3.02 per Boe and $2.43 per Boe, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (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. For the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), we stacked two rigs in response to the sustained decline in commodity prices. For the three months ended September 30, 2015 (Predecessor), we had only one rig stacked.

For the period of September 10, 2016 through September 30, 2016 (Successor), and July 1, 2016 through September 9, 2016 (Predecessor) and for the three months ended September 30, 2015 (Predecessor), we incurred zero, $0.1 million and $0.4 million, respectively, in severance costs and accelerated stock-based compensation expense related to reductions in our workforce.

General and administrative expense was $3.5 million, $16.1 million and $18.0 million, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. General and administrative expenses in 2016 have been impacted by costs incurred with efforts to restructure our indebtedness.

Share-based compensation expense was $13.2 million, $1.2 million and $3.0 million, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through

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September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. Share-based compensation expense decreased in the Predecessor periods due to a reduction in our workforce and increased in the Successor period due to equity awards made in conjunction with our emergence from chapter 11 bankruptcy. A portion of these awards vested immediately on the day of the grant.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. On a per unit basis, depletion expense was $12.45 per Boe, $9.86 per Boe and $19.92 per Boe, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. The decrease in depletion expense and the depletion rate per Boe from 2015 levels is attributable to decreases in the amortizable base due to our full cost ceiling test impairments.

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling", based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves using the first-day-of-the-month average price for the 12-months ended September 30, 2016. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $420.9 million for the period of September 10, 2016 through September 30, 2016 (Successor). The impairment at September 30, 2016 primarily reflects the pricing differences between the first-day-of-the-month average price for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date of September 9, 2016. We recorded a full cost ceiling test impairment before income taxes of $511.9 million for the three months ended September 30, 2015 (Predecessor). The ceiling test impairment at September 30, 2015 was driven by a 17% decrease in the first-day-of-the-month average prices for crude oil used in the ceiling test calculation since the prior period, which was $71.68 per barrel at June 30, 2015. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. See "Overview" for a discussion of potential future ceiling impairments in an environment of sustained lower commodity prices.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2016 (Successor), we had a $73.7 million derivative asset, $70.8 million of which was classified as current and we had a $2.5 million derivative liability, $1.4 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $7.6 million ($30.3 million net unrealized loss and $22.7 million net realized gain on settled contracts) and a net derivative gain of $17.8 million ($39.4 million net unrealized loss and $57.2 million net realized gain on settled contracts) for the period of September 10, 2016 through September 30, 2016 (Successor) and for the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. For the three months ended September 30, 2015 (Predecessor), we

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recorded a net derivative gain of $204.6 million ($89.7 million net unrealized gain and $114.9 million net realized gain on settled contracts).

Interest expense and other was $5.5 million, $16.1 million and $58.0 million for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. Capitalized interest for the period of July 1, 2016 through September 9, 2016 (Predecessor) and three months ended September 30, 2015 (Predecessor) was $15.2 million and $28.8 million, respectively. Upon the adoption of fresh-start accounting, we revised our accounting policy on the capitalization of interest and did not capitalize interest for the period of September 10, 2016 through September 30, 2016 (Successor). Gross interest expense was $5.4 million, $39.6 million and $86.1 million for the period of September 10, 2016 through September 30, 2016 (Successor), the period of July 1, 2016 through September 9, 2016 (Predecessor) and the three months ended September 30, 2015 (Predecessor), respectively. 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 chapter 11 bankruptcy proceedings.

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

During the three months ended September 30, 2015 (Predecessor), we entered into separate, privately negotiated exchange agreements with holders of our senior unsecured notes whereby we issued approximately $1.02 billion aggregate principal amount of Third Lien Notes in exchange for approximately $1.57 billion aggregate principal amount of senior unsecured notes held by such holders. For the three months ended September 30, 2015 (Predecessor) we recorded a net gain on the extinguishment of debt of $535.1 million, as a $548.2 million gain on the exchange agreements was partially offset by the writedown of $13.1 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes exchanged.

We recorded an income tax provision of $3.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and an income tax benefit of $8.7 million for the period of July 1, 2016 through September 9, 2016 (Predecessor) relating to our estimated 2016 alternative minimum tax liability and the reversal of the Predecessor 2015 alternative minimum tax liability, respectively. We recorded an income tax provision of $6.0 million for the three months ended September 30, 2015 (Predecessor), related to estimated alternative minimum tax of $5.0 million and Texas franchise tax of $1.0 million.

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Nine Months Ended September 30, 2016 and 2015

The table included below sets forth financial information for the periods presented. The period of September 10, 2016 through September 30, 2016 (Successor Company) and the period of January 1, 2016 through September 9, 2016 (Predecessor Company) are distinct reporting periods as a result of our application of fresh-start accounting upon our emergence from chapter 11 bankruptcy on September 9, 2016 and may not be comparable to prior periods.

	Successor			Predecessor

In thousands (except per unit and per Boe amounts)	Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016			Nine Months Ended September 30, 2015
Net income (loss)	$	(450,692	)	$	11,958		$	(1,529,178	)
Operating revenues:
Oil		21,260			248,064			404,368
Natural gas		823			9,511			17,595
Natural gas liquids		798			7,929			10,572
Other		226			1,339			1,622
Operating expenses:
Production:
Lease operating		3,791			50,032			81,266
Workover and other		1,565			22,507			11,614
Taxes other than income		2,173			24,453			37,246
Gathering and other		2,637			29,279			30,583
Restructuring		—			5,168			2,664
General and administrative:
General and administrative		3,485			78,765			56,853
Share-based compensation		13,196			4,876			11,245
Depletion, depreciation and accretion:
Depletion—Full cost		8,716			114,775			289,959
Depreciation—Other		204			4,366			6,119
Accretion expense		131			1,414			1,331
Full cost ceiling impairment		420,934			754,769			2,014,518
Other operating property and equipment impairment		—			28,056			—
Other income (expenses):
Net gain (loss) on derivative contracts		(7,575	)		(17,998	)		216,805
Interest expense and other, net		(5,479	)		(122,249	)		(180,206	)
Reorganization items		(556	)		913,722			—
Gain (loss) on extinguishment of debt		—			81,434			557,907
Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants		—			—			(8,219	)
Income tax benefit (provision)		(3,357	)		8,666			(6,224	)
Production:
Oil—MBbls		533			7,118			9,096
Natural Gas—Mmcf		521			6,560			7,444
Natural gas liquids—MBbls		80			1,096			1,046
Total MBoe(1)		700			9,307			11,383
Average daily production—Boe(1)		33,333			36,787			41,696
Average price per unit(2):
Oil price—Bbl	$	39.89		$	34.85		$	44.46
Natural gas price—Mcf		1.58			1.45			2.36
Natural gas liquids price—Bbl		9.98			7.23			10.11
Total per Boe(1)		32.69			28.53			38.00
Average cost per Boe:
Production:
Lease operating	$	5.42		$	5.38		$	7.14
Workover and other		2.24			2.42			1.02
Taxes other than income		3.10			2.63			3.27
Gathering and other		3.77			3.15			2.69
Restructuring		—			0.56			0.23
General and administrative:
General and administrative		4.98			8.46			4.99
Share-based compensation		18.85			0.52			0.99
Depletion		12.45			12.33			25.47

(1): Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.
(2): Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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Oil, natural gas and natural gas liquids revenues were $22.9 million, $265.5 million and $432.5 million for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. Average realized prices (excluding the effects of hedging arrangements) were $32.69 per Boe, $28.53 per Boe and $38.00 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. Oil and natural gas prices are inherently volatile and have decreased significantly since mid-year 2014 and have remained low throughout 2016. Average daily production has decreased, as we have curtailed our drilling in response to the decline in commodity prices.

Lease operating expenses on a per Boe basis were $5.42 per Boe, $5.38 per Boe and $7.14 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. The decrease in lease operating expenses per Boe from 2015 levels is primarily due to price decreases from our vendors in light of the current commodity price environment.

Workover and other expenses on a per Boe basis were $2.24 per Boe, $2.42 per Boe and $1.02 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. The increased costs from 2015 levels relate primarily to workovers in our Bakken area, specifically costs spent to restore production on wells with downhole problems and well casing repairs.

Taxes other than income on a per Boe basis were $3.10 per Boe, $2.63 per Boe and $3.27 per Boe for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (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.

Gathering and other expenses on a per Boe basis were $3.77 per Boe, $3.15 per Boe and $2.69 per Boe, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (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. For the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), we stacked one to two rigs (one was stacked since May 2015 and another was stacked in March 2016) in response to the sustained decline in commodity prices. For the nine months ended September 30, 2015 (Predecessor), we had only one rig stacked.

For the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and for the nine months ended September 30, 2015 (Predecessor), we incurred zero, $5.2 million and $2.7 million, respectively, in severance costs and accelerated stock-based compensation expense related to reductions in our workforce.

General and administrative expense was $3.5 million, $78.8 million and $56.9 million, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. General and administrative expenses have increased from 2015 levels due to costs incurred with efforts to restructure our indebtedness.

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Share-based compensation expense was $13.2 million, $4.9 million and $11.2 million, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. Share-based compensation expense decreased in the Predecessor periods due to a reduction in our workforce and increased in the Successor period due to equity awards made in conjunction with our emergence from chapter 11 bankruptcy. A portion of these awards vested immediately on the day of the grant.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. On a per unit basis, depletion expense was $12.45 per Boe, $12.33 per Boe and $25.47 per Boe, for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. The decrease in depletion expense and the depletion rate per Boe from 2015 levels is attributable to decreases in the amortizable base due to our full cost ceiling test impairments.

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. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $420.9 million for the period of September 10, 2016 through September 30, 2016 (Successor). The impairment at September 30, 2016 primarily reflects the pricing differences between the first-day-of-the-month average price for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date, September 9, 2016. We recorded a full cost ceiling test impairment before income taxes of $754.8 million for the period January 1, 2016 through September 9, 2016 (Predecessor). The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. We recorded a full cost ceiling test impairment before income taxes of $2.0 billion for the nine months ended September 30, 2015 (Predecessor). The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014. 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. See "Overview" for a discussion of potential future ceiling impairments in an environment of sustained lower commodity prices.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we record the net change in the mark-to-market value of these derivative contracts in our unaudited condensed consolidated statements of operations. At September 30, 2016 (Successor), we had a $73.7 million derivative asset, $70.8 million of which was classified as current and we had a $2.5 million derivative liability, $1.4 million of which was classified as current associated with these contracts. We recorded a net derivative loss of $7.6 million ($30.3 million net unrealized loss and $22.7 million net realized gain on settled contracts) and $18.0 million ($263.7 million net unrealized loss and

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$245.7 million net realized gain on settled contracts) for the period of September 10, 2016 through September 30, 2016 (Successor) and for the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. For the nine months ended September 30, 2015 (Predecessor), we recorded a net derivative gain of $216.8 million ($94.0 million net unrealized loss and $310.8 million net realized gain on settled contracts).

Interest expense and other was $5.5 million, $122.2 million and $180.2 million for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. Capitalized interest for the period of January 1, 2016 through September 9, 2016 (Predecessor) and nine months ended September 30, 2015 (Predecessor) was $68.2 million and $80.3 million, respectively. Upon the adoption of fresh-start accounting, we revised our accounting policy on the capitalization of interest and did not capitalize interest for the period of September 10, 2016 through September 30, 2016 (Successor). Gross interest expense was $5.4 million, $195.7 million and $254.9 million for the period of September 10, 2016 through September 30, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the nine months ended September 30, 2015 (Predecessor), respectively. The decrease in gross interest expense from 2015 levels was primarily due to the discontinuance of interest expense on our senior notes that were cancelled as part of our chapter 11 bankruptcy proceedings.

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

During the three months ended March 31, 2016 (Predecessor), we repurchased approximately $91.8 million principal amount of our 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 writedown of $0.7 million associated with related issuance costs and discounts and premiums for the respective notes. During the nine months ended September 30, 2015 (Predecessor), we entered into separate, privately negotiated exchange agreements with holders of our senior unsecured notes whereby we issued approximately $1.02 billion aggregate principal amount of Third Lien Notes in exchange for approximately $1.57 billion aggregate principal amount of senior unsecured notes held by such holders. For the nine months ended September 30, 2015 (Predecessor) we recorded a net gain on the extinguishment of debt of $535.1 million, as a $548.2 million gain on the exchange agreements was partially offset by the writedown of $13.1 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes exchanged. In addition, we also entered into several exchange agreements with holders of our senior unsecured notes whereby the holders agreed to exchange an aggregate $258.0 million principal amount of their senior unsecured notes for our common stock. As a result of these debt for equity exchanges, for the nine months ended September 30, 2015 (Predecessor) we recorded a net gain on the extinguishment of debt of $22.8 million, as a $26.6 million gain on the exchanges was partially offset by the writedown of $3.8 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes exchanged.

During the nine months ended September 30, 2015 (Predecessor), we entered into an amendment to our Convertible Note and to the February 2012 Warrants, in which we recorded a net gain on the

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extinguishment of the Convertible Note of $5.9 million and a net loss on the modification of the February 2012 Warrants of $14.1 million.

We recorded an income tax provision of $3.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and an income tax benefit of $8.7 million for the period January 1, 2016 through September 9, 2016 (Predecessor) relating to our estimated 2016 alternative minimum tax liability and the reversal of the Predecessor estimated 2015 alternative minimum tax liability, respectively. We recorded an income tax provision of $6.2 million for the nine months ended September 30, 2015 (Predecessor), related to estimated alternative minimum tax of $5.1 million and Texas franchise tax of $1.1 million.

Recently Issued Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable; therefore, we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and 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 current and 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 and currently we have hedged only a limited amount of our anticipated production beyond 2016 due to low commodity prices. As a consequence our future performance is subject to increased commodity price risks and our future cash flows from operations may be subject to greater volatility than historically. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competitive market makers. We did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 8, "Derivative and Hedging Activities" for additional information.

Fair Market Value of Financial Instruments

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

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Interest Rate Sensitivity

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

At September 30, 2016, the principal amount of our debt was approximately $1.0 billion, of which approximately 78% bears interest at a weighted average fixed interest rate of 9.1% per year. The remaining 22% of our total debt at September 30, 2016 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 September 30, 2016, the weighted average interest rate on our variable rate debt was 3.8% per year. If the balance of our variable rate debt at September 30, 2016 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.9 million per year.

Item 4. Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of September 30, 2016. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.

We did not have any change in our internal controls over financial reporting during the three months ended September 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There have been no changes to the risk factors described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, except as described below.

Our actual financial results may vary materially from the projections that we filed with the bankruptcy court in connection the confirmation of our plan of reorganization.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of our plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

Our historical financial information may not be indicative of our future financial performance.

On the effective date of our emergence from bankruptcy on September 9, 2016 we adopted fresh-start accounting, as a consequence of which our assets and liabilities were adjusted to fair values and our accumulated deficit was restated to zero. Accordingly, our financial condition and results of operations following our emergence from chapter 11 may not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, as a result of the implementation of our plan of reorganization and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.

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

Under the Plan, the composition of our Board of Directors (the Board) changed significantly from an eleven member Board with terms of one year to, upon emergence, nine member Board, structured into three tiers and classified into staggered three year terms. Only three of our current directors served on our Board previously. Our new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

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

Funds advised by Franklin Advisors, Inc. and Ares Management LLC currently hold approximately 37% and 20%, respectively, of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

We are currently out of compliance with the New York Stock Exchange's average market capitalization requirement and are at risk of the NYSE delisting our common stock, which could materially impair the liquidity and value of our common stock.

Our common stock is currently listed on the New York Stock Exchange (the NYSE). On August 12, 2016, we were notified by the NYSE that the average market capitalization of our common stock was less than $50 million over a 30 trading day period, at the same time as our stockholders' equity was less than $50 million. In accordance with NYSE rules, we timely submitted a plan to regain compliance with the average market capitalization requirement, which we successfully executed as a consequence of our emergence from chapter 11 bankruptcy effective September 9, 2016. However, the NYSE has indicated it may take up to two calendar quarters for notice from the NYSE that listing compliance has been regained.

A delisting of our common stock, either as result of a failure to regain compliance with the NYSE's average market capitalization requirement or the Company's failure to satisfy other qualitative or quantitative standards for continued listing on the NYSE, could reduce the liquidity and market price of our common stock.

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into a registration rights agreement with certain of those investors pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could cause the market price of our common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We are currently authorized to issue 1.0 billion shares of common stock and 1.0 million shares of preferred stock, with such designations, rights, preferences, privileges and restrictions as determined by our board of directors. As of September 30, 2016, we had outstanding approximately 92.6 million shares of common stock and warrants and options to purchase an aggregate of 9.7 million shares of our common stock. We have also reserved an additional 2.4 million shares for future issuance to our directors, officers and employees as restricted stock or stock option awards pursuant to our 2016 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy

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our obligations upon the exercise of warrants and options, or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

Our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

In general, under Section 382 of the Internal Revenue Code of 1986, as amended, a corporation that undergoes an "ownership change" is subject to limitations on its ability to utilize its pre-change net operating losses (NOLs), to offset future taxable income. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years).

As of December 31, 2015, we reported consolidated federal pretax NOL carryforwards of approximately $1.5 billion. We believe we experienced an ownership change in September 2016 as a result of the consummation of our plan of reorganization under chapter 11 of the U.S. Bankruptcy Code. Limitations imposed on our ability to use NOLs to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.

We are subject to complex federal, state, local and other laws and regulations that frequently are amended to impose more stringent requirements that could adversely affect the cost, manner or feasibility of doing business.

Companies that explore for and develop, produce, sell and transport oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax and environmental, health and safety laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

•: water discharge and disposal permits for drilling operations;
•: drilling bonds;
•: drilling permits;
•: reports concerning operations;
•: air quality, air emissions, noise levels and related permits;
•: spacing of wells;
•: rights-of-way and easements;
•: unitization and pooling of properties;
•: pipeline construction;
•: gathering, transportation and marketing of oil and natural gas;
•: taxation; and
•: waste transport and disposal permits and requirements.

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Failure to comply with applicable laws may result in the suspension or termination of operations and subject us to liabilities, including administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, the laws governing our operations or the enforcement thereof could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

Under environmental, health and safety laws and regulations, we also could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages including the assessment of natural resource damages. Such laws may impose strict as well as joint and several liability for environmental contamination, which could subject us to liability for the conduct of others or for our own actions that were in compliance with all applicable laws at the time such actions were taken. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to regulation by oil and natural gas producing states relating to conservation practices and protection of correlative rights. The North Dakota Industrial Commission (NDIC), the State's chief energy regulator, for example, approved comprehensive rules in 2016 for the conservation of crude oil and natural gas that address site construction, gathering pipelines and spill containment. Such regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. Delays in obtaining regulatory approvals or necessary permits, the failure to obtain a permit or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on, develop or produce our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. By way of example, in 2015 the EPA lowered the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, the new standard eventually could result in more stringent emissions controls and additional permitting obligations for our operations.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing. Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

In the United States, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

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At the federal level, the Obama Administration pledged for the Paris Agreement to meet an economy-wide target in 2025 of reducing greenhouse gas emissions by 26-28% below the 2005 level. Towards that end, federal agencies have been addressing climate change through a variety of administrative actions. The EPA has issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. Beyond measuring and reporting, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, the President released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and gas sector. Towards that end, the EPA released five draft white papers on methane and volatile organic compound emissions and mitigation measures for natural gas compressors, hydraulically fractured oil wells, pneumatic devices, well liquids unloading facilities and natural gas production and transmission facilities. Building on its white papers and the public input on those documents, the EPA issued final rules in 2016 for new and modified oil and gas production sources (including hydraulically fractured oil wells, natural gas well sites, natural gas processing plants, natural gas gathering and boosting stations and natural gas transmission sources) to reduce emissions of methane as well as volatile organic compound and toxic pollutants. In addition, the BLM has proposed standards for reducing venting and flaring on public lands. The EPA and BLM actions are part of a series of steps by the Administration that are intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand for our products.

Requirements to reduce gas flaring in North Dakota could have an adverse effect on our operations.

Wells in the Bakken/Three Forks formations in North Dakota, where we have significant operations, yield natural gas as a byproduct of oil production. Bottlenecks in the gas gathering network in certain areas resulted in some of that natural gas being flared instead of processed. In 2014, the NDIC issued an order to reduce the volume of natural gas flared from oil wells in the Bakken/Three Forks formations. The State's current objectives are to cause operators to capture 85% of the natural gas by November 1, 2016, 88% by November 1, 2018 and 91-93% by November 1, 2020. In addition, the NDIC is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. These capture requirements and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

Crude oil from the Bakken/Three Forks formations may pose unique hazards that may have an adverse effect on our operations.

The United States Department of Transportation (USDOT) has concluded that crude oil from the Bakken / Three Forks formations has a higher volatility than most other crude oil from the United States and thus is more ignitable and flammable. Based on that information, and several fires involving

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rail transportation of crude oil, USDOT imposed additional requirements for shipping crude oil by rail. Beyond that, the rail industry has adopted increased precautions for crude shipments. Any restrictions that significantly affect transportation of crude oil production could materially and adversely affect our financial condition, results of operations and cash flows.

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

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

		Average Price Paid Per Share

July 2016 (Predecessor)	132	$	0.48	—	—
August 2016 (Predecessor)	26		0.38	—	—
September 1 - 9, 2016 (Predecessor)	391,960		0.32	—	—

September 10 - 30, 2016 (Successor)	—	$	—	—	—

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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

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


2.1		Order of the Bankruptcy Court, dated September 8, 2016, confirming the Amended Joint Prepackaged Plan of Reorganization of Halcón Resources Corporation, et al, under Chapter 11 of the Bankruptcy Code, together with such Amended Joint Prepackaged Plan of Reorganization (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed September 9, 2016).

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		First Supplemental Indenture dated as of September 28, 2016, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 8.625% Senior Secured Notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed September 30, 2016).

4.2		First Supplemental Indenture dated as of September 28, 2016, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 12.0% Second Lien Senior Secured Notes due 2022 (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed September 30, 2016).

10.1		Senior Secured Revolving Credit Agreement, dated as of September 9, 2016, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 9, 2016).

10.2		Registration Rights Agreement, dated as of September 9, 2016, by and among Halcón Resources Corporation and the Holders parties thereto (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed September 9, 2016).

10.3		Warrant Agreement, dated as of September 9, 2016, by and between Halcón Resources Corporation and U.S. Bank National Association, as warrant agent (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed September 9, 2016).

10.4	†	Halcón Resources Corporation 2016 Long-Term Incentive Plan, effective as of September 9, 2016 (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed September 9, 2016).

10.5		Assignment and Assumption Agreement, dated as of September 30, 2016, among Halcón Energy Properties, Inc., Halcón Gulf States, LLC and Apollo HK TMS Investment Holdings, L.P. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed October 5, 2016).

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

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

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

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

101.INS	*	XBRL Instance Document

101.SCH	*	XBRL Taxonomy Extension Schema Document

101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	*	XBRL Taxonomy Extension Definition Document

101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document

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

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SIGNATURES

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


	HALCÓN RESOURCES CORPORATION
November 9, 2016	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board, Chief Executive Officer and President
November 9, 2016	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
November 9, 2016	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Senior Vice President, Chief Accounting Officer and Controller