HALCON RESOURCES CORP (Form: 10-Q, Received: 11/09/2017 16:47:04)

HALCÓN RESOURCES CORPORATION

November 9, 2017

/s/ FLOYD C. WILSON

Floyd C. Wilson

Chairman of the Board, Chief Executive Officer and President

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

FORM 10-Q


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number: 001-35467

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


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

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

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

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

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

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company ý Emerging growth company o

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

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

At November 6, 2017, 149,596,067 shares of the Registrant's Common Stock were outstanding.

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

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Special note regarding forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, including, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, or financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2016, and Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, as well as the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

•: volatility in commodity prices for oil and natural gas;
•: our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and develop our undeveloped acreage position;
•: our ability to replace our oil and natural gas reserves and production;
•: the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management's time and energy;
•: our ability to successfully integrate acquired oil and natural gas businesses and operations;
•: we have historically had substantial indebtedness and we may incur more debt in the future;
•: higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;
•: the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
•: our ability to successfully develop our large inventory of undeveloped acreage in our resource play;
•: our ability to retain key members of senior management, the board of directors, and key technical employees;
•: access to and availability of water and other treatment materials to carry out fracture stimulations in our resource play;
•: access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices;
•: contractual limitations that affect our management's discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;
•: the potential for production decline rates for our wells to be greater than we expect;
•: competition, including competition for acreage in our resource play;

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

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

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PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Successor						Predecessor

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

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

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

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

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

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

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

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

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

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



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



Diluted	$	2.82		$	(4.96	)	$	6.06



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



Diluted		148,490			91,071			151,876

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (Continued)

(In thousands, except per share amounts)

	Successor						Predecessor

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

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

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

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

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

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

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

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

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

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



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



Diluted	$	4.52		$	(4.96	)	$	(0.27	)



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



Diluted		128,410			91,071			120,513

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	Successor

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

Total current assets		1,115,437			160,649

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

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

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

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

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

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

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



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

Total current liabilities		584,178			207,553

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

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

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

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Preferred Stock					Common Stock									Retained Earnings (Accumulated Deficit)

	Preferred Stock					Common Stock						Additional Paid-In Capital						Stockholders' Equity
	Shares			Amount		Shares			Amount			Additional Paid-In Capital						Stockholders' Equity
Balances at December 31, 2015 (Predecessor)		245		$	—		122,524		$	12		$	3,283,097		$	(3,230,695	)	$	52,414
Net income (loss)		—			—		—			—			—			11,958			11,958
Conversion of Series A preferred stock		(23	)		—		724			—			—			—			—
Preferred dividends on redeemable noncontrolling interest		—			—		—			—			—			(9,329	)		(9,329	)
Accretion of redeemable noncontrolling interest		—			—		—			—			—			(26,576	)		(26,576	)
Fair value of equity issued to Predecessor common stockholders		—			—		—			—			(22,176	)		—			(22,176	)
Cash payment to Preferred Holders		—			—		—			—			(11,100	)		—			(11,100	)
Reverse stock split rounding		—			—		5			—			—						—
Offering costs		—			—		—			—			(10	)		—			(10	)
Long-term incentive plan forfeitures		—			—		(517	)		—			—			—			—
Reduction in shares to cover individuals' tax withholding		—			—		(498	)		—			(176	)		—			(176	)
Share-based compensation		—			—		—			—			4,995			—			4,995

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



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

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




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

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



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

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

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Successor						Predecessor

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


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

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

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

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

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

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

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

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



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

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

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

Emergence from Voluntary Reorganization under Chapter 11

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

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

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

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

Use of Estimates

The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of Reorganization Value, Enterprise Value and the fair value of assets and liabilities recorded as a result of the adoption of fresh-start accounting, plus the estimated fair values of assets acquired and liabilities assumed in connection with the Pecos County Acquisition and the fair value of assets sold in connection with the Williston Divestiture and the El Halcón Divestiture (see Note 4, "Acquisitions and Divestitures," for information on the Pecos County Acquisition, the Williston Divestiture and the El Halcón Divestiture), including the gains on sales recorded, and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's unaudited condensed consolidated financial statements.

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

Accounts Receivable and Allowance for Doubtful Accounts

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

Other Operating Property and Equipment

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

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

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

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

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

Recently Issued Accounting Pronouncements

In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). For public business entities, ASU 2017-01 is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2017. The amendments in this ASU should be applied prospectively on or after the effective date. The ASU was issued to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as

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

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

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and early adoption is permitted. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity should apply the amendments in this ASU on a modified retrospective basis. The transition will require application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. The Company is in the early stages of assessing the effects of the application of the new guidance and the financial statement and disclosure impacts. The Company will adopt ASU 2016-02 no later than January 1, 2019.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2017. Early adoption is not permitted. The Company is in the process of assessing its contracts with customers and evaluating the effects of the new guidance on its financial statements and disclosures. This process includes evaluating certain components of its natural gas gathering and processing agreements to determine whether changes to revenues and expenses will be appropriate when complying with the new guidance. The adoption is not expected to have a significant impact on the Company's net income or cash flows from operations. The Company will adopt ASU 2014-09 effective January 1, 2018.

2. REORGANIZATION

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

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

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

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

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2. REORGANIZATION (Continued)

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

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

3. FRESH-START ACCOUNTING

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

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

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

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

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

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

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

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

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

	September 9, 2016

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

Fair Value of Successor common stock	$	554,432

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

	September 9, 2016

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

Reorganization Value of Successor assets	$	1,843,626

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3. FRESH-START ACCOUNTING (Continued)

Condensed Consolidated Balance Sheet

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

	As of September 9, 2016

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

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

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

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

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

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

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

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

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



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

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

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

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

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

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3. FRESH-START ACCOUNTING (Continued)

Reorganization adjustments

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


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

Total Uses	$	97,521

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


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

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

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

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


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

Cancellation of Predecessor Company equity	$	3,254,642

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

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

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


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

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

Fresh-start accounting adjustments

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

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

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

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

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

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

Reorganization Items

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

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

	Successor			Predecessor

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

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

4. ACQUISITIONS AND DIVESTITURES

Acquisitions

Delaware Basin Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017 (Successor), Halcón Energy Properties, Inc., a wholly owned subsidiary of the Company, entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which it agreed to acquire acreage and related assets in the Hackberry Draw area of the Delaware Basin, located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $699.2 million (the Pecos County Acquisition). The Pecos County Acquisition closed on February 28, 2017. The transaction had an effective date of November 1, 2016. The Company funded the Pecos County Acquisition with the net proceeds from the private placement of its preferred stock and borrowings under its Senior Credit Agreement. Refer to Note 11, "Stockholders' Equity," for further discussion of the Company's issuance of the Preferred Stock.

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

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


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

Final consideration transferred	$	699,188



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

Amount attributable to liabilites assumed		2,955

Total purchase price plus liabilities assumed	$	702,143



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

Amount attributable to assets acquired	$	702,143

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

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4. ACQUISITIONS AND DIVESTITURES (Continued)

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

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2017 (Successor) and the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) as though the Pecos County Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2016. The pro forma combined results of operations for the nine months ended September 30, 2017 (Successor) and the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) have been prepared by adjusting the historical results of the Company to include the historical results of the Pecos County Assets. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined Company for the periods presented or that may be achieved by the combined Company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Pecos County Acquisition or any estimated costs that will be incurred to integrate the Pecos County Assets. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors. Amounts included in the table below are rounded to thousands.

	Successor					Predecessor

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

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

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

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

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

Divestitures

Williston Basin Operated Assets

On July 10, 2017 (Successor), the Company and certain of its subsidiaries entered into an Agreement of Sale and Purchase (the Purchase Agreement) with Bruin Williston Holdings, LLC (the Purchaser) for the sale of all of the Company's operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of its subsidiaries (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion, subject to post-closing adjustments (the Williston Divestiture). The effective date of the sale was June 1, 2017 and the transaction closed on September 7, 2017. The Company is using the net proceeds from the sale to repay borrowings outstanding under its Senior Credit Agreement, repurchase approximately $425 million principal amount of the outstanding $850 million principal amount of its 6.75% senior unsecured notes, redeem all of its outstanding 12% second lien notes and for general corporate purposes.

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

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As discussed further in Note 5, "Oil and Natural Gas Properties," the Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the Williston Assets of $491.8 million during the three months ended September 30, 2017 (Successor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in "Gain (loss) on the sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

East Texas Eagle Ford Assets

On January 24, 2017 (Successor), certain of the Company's subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of the Company's oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total adjusted sales price of $491.1 million (the El Halcón Divestiture). The effective date of the sale was January 1, 2017 and the transaction closed on March 9, 2017. The Company used the net proceeds from the sale to repay borrowings outstanding under its Senior Credit Agreement and for general corporate purposes.

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

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the El Halcón Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of $235.7 million during the nine months ended September 30, 2017 (Successor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in "Gain (loss) on sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

HK TMS, LLC

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

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

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

5. OIL AND NATURAL GAS PROPERTIES

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

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

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

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5. OIL AND NATURAL GAS PROPERTIES (Continued)

At September 30, 2017 (Successor), the ceiling test value of the Company's reserves was calculated based on the first-day-of-the-month average for the 12-months ended September 30, 2017 of the West Texas Intermediate (WTI) crude oil spot price of $49.81 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended September 30, 2017 of the Henry Hub natural gas price of $3.00 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at September 30, 2017 (Successor) did not exceed the ceiling amount.

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

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

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

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

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6. DEBT

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

	Successor

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

	$	408,879	$	964,653

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

Senior Revolving Credit Facility

On September 7, 2017, the Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Senior Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. The Senior Credit Agreement amends and restates in its entirety the original Senior Secured Revolving Credit Agreement entered into on September 9, 2016. Pursuant to the Senior Credit Agreement, the lenders party thereto have agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a current borrowing base of $100.0 million. The maturity date of the Senior Credit Agreement is September 7, 2022. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The

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borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.25% to 2.25% for ABR-based loans or at specified margins over LIBOR of 2.25% to 3.25% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement).

Amounts outstanding under the Senior Credit Agreement are guaranteed by certain of the Company's direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries.

The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00. At September 30, 2017 (Successor), the Company was in compliance with the financial covenants under the Senior Credit Agreement.

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

At September 30, 2017 (Successor), under the then effective borrowing base of $140.0 million, the Company had no indebtedness outstanding, approximately $6.4 million letters of credit outstanding and approximately $133.6 million of borrowing capacity available under the Senior Credit Agreement.

8.625% Senior Secured Second Lien Notes

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

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

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

The Company recognized a loss on the extinguishment of debt, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes. The loss was recorded in "Gain (loss) on extinguishment of debt" on the unaudited condensed consolidated statements of operations.

12.0% Senior Secured Second Lien Notes

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

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

The Company recognized a loss on the extinguishment of debt, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the notes. The loss was recorded in "Gain (loss) on extinguishment of debt" on the unaudited condensed consolidated statements of operations.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

6.75% Senior Notes

On February 16, 2017 (Successor), the Company issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025 (the 2025 Notes) in a private placement exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (Securities Act), Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2017. The 2025 Notes will mature on February 15, 2025. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers' discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the private placement to fund the repurchase and redemption of the outstanding 2020 Second Lien Notes, as discussed above, and for general corporate purposes.

The 2025 Notes are governed by an Indenture, dated as of February 16, 2017 (as supplemented, the February 2017 Indenture) by and among the Company, the Guarantors and U.S. Bank National Association, as Trustee, which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The February 2017 Indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing wholly-owned subsidiaries. Halcón, the issuer of the 2025 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In connection with the sale of the 2025 Notes, on February 16, 2017, the Company, the Guarantors and J.P. Morgan Securities LLC, on behalf of itself and as representative of the initial purchasers, entered into a Registration Rights Agreement (the 2017 Registration Rights Agreement) pursuant to which the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 365 days after closing. In the event the Company fails to comply with its obligations under the 2017 Registration Rights Agreement, it will be subject to penalties in the form of additional interest payable on the 2025 Notes.

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DEBT (Continued)

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

Year		Percentage

2020			105.063
2021			103.375
2022			101.688
2023 and thereafter			100.000

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

On July 25, 2017, the Company concluded a consent solicitation of the holders of the 2025 Notes (the Consent Solicitation) and obtained consents to amend the February 2017 Indenture from approximately 99% of the holders of the 2025 Notes. As supplemented, the February 2017 Indenture amends provisions in order to exempt, among other things, the Williston Divestiture from certain provisions therein triggered upon a sale of "all or substantially all of the assets" of the Company. Consenting holders of the 2025 Notes received a consent fee of 2.0% of principal, or $16.9 million. The Company recorded the $16.9 million consent fees paid as a discount on the 2025 Notes during the three months ended September 30, 2017. The remaining unamortized discount on the $850 million principal amount of 2025 Notes was $16.7 million at September 30, 2017.

On September 7, 2017, the Company commenced an offer to purchase for cash up to $425.0 million of the $850.0 million outstanding aggregate principal amount of its 2025 Notes at 103.0% of principal plus accrued and unpaid interest. The consummation of the Williston Divestiture constituted a "Williston Sale" under the February 2017 Indenture, and the Company was required to make an offer to all holders of the 2025 Notes to purchase for cash an aggregate principal amount up to $425.0 million of the 2025 Notes. The offer to purchase expired on October 6, 2017, with notes representing in excess of $425.0 million of principal amount validly tendered. As a result, on October 10, 2017, the Company repurchased $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest. The repurchased 2025 Notes are presented in "Current portion of long-term debt, net" on the unaudited condensed consolidated balance sheet at September 30, 2017.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. During the nine months ended September 30, 2017 (Successor), the Company capitalized approximately $17.1 million of debt issuance costs related to the Senior Credit Agreement and the 2025 Notes. The debt issuance costs for the Successor Company's Senior Credit Agreement are presented in "Funds in escrow and other " and the debt issuance costs for the Company's senior unsecured debt are presented in "Current portion of long-term debt, net" and "Long-term debt, net" on the unaudited condensed consolidated balance sheets.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS

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

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

	Successor

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



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

	December 31, 2016

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



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

Derivative contracts listed above as Level 2 include collars and basis swaps that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

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

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

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

	Successor

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

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

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

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

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

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. FAIR VALUE MEASUREMENTS (Continued)

The Company follows the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company's initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management's expectation of future cost environments; consequently, the Company has designated these liabilities as Level 3. See Note 9, " Asset Retirement Obligations ," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

8. DERIVATIVE AND HEDGING ACTIVITIES

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

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

At September 30, 2017 (Successor), the Company's crude oil and natural gas derivative positions consisted of basis swaps and costless put/call "collars." At December 31, 2016 (Successor), the Company's derivative positions consisted of collars only. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) and the relevant price index at which the oil production is sold (i.e. Cushing). A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

At September 30, 2017 (Successor), the Company had 32 open commodity derivative contracts summarized in the following tables: four natural gas collar arrangements, 11 crude oil basis swaps and 17 crude oil collar arrangements.

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

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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

		Asset derivative contracts					Liability derivative contracts

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

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

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

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


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

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

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

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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


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

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

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

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

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

			Successor

			September 30, 2017
					Floors				Ceilings				Basis Differential
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
October 2017 - December 2017	Collars	Natural Gas		460,000	$	3.26	$	3.26	$	3.76	$	3.76	$	—	$	—
October 2017 - December 2017	Collars	Crude Oil		437,000		51.07 - 60.00		55.64		56.07 - 75.00		63.80
November 2017 - December 2017	Collars	Crude Oil		61,000		51.50		51.50		56.50		56.50
January 2018 - December 2018	Basis Swap	Crude Oil		2,555,000										(1.05) - (1.50)		(1.29	)
January 2018 - December 2018	Collars	Crude Oil		2,920,000		45.00 - 53.00		49.29		50.00 - 60.00		56.82
January 2018 - December 2018	Collars	Natural Gas		2,737,500		3.00 - 3.03		3.01		3.22 - 3.38		3.30
April 2018 - December 2018	Basis Swap	Crude Oil		275,000										(1.15)		(1.15	)
April 2018 - December 2018	Collars	Crude Oil		275,000		46.75		46.75		51.75		51.75
July 2018 - December 2018	Basis Swap	Crude Oil		1,012,000										(0.98) - (1.18)		(1.12	)
July 2018 - December 2018	Collars	Crude Oil		184,000		48.50		48.50		53.50		53.50
January 2019 - March 2019	Collars	Crude Oil		90,000		46.75		46.75		51.75		51.75
January 2019 - December 2019	Basis Swap	Crude Oil		3,467,500										(0.98) - (1.33)		(1.15	)

			Successor

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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

	Derivative Assets						Derivative Liabilities

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

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

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

9. ASSET RETIREMENT OBLIGATIONS

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. ASSET RETIREMENT OBLIGATIONS (Continued)

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


Liability for asset retirement obligations as of December 31, 2016 (Sucessor)	$	32,375
Liabilities settled and divested (1)		(31,743	)
Additions		286
Acquisitions (1)		2,194
Accretion expense		1,230
Revisions in estimated cash flows		782

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

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

10. COMMITMENTS AND CONTINGENCIES

Commitments

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


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

Total	$	12,647

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


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

Total	$	4,418

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS AND CONTINGENCIES (Continued)

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

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


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

Total	$	5,226

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

In December 2016 (Successor), the Company entered into an agreement with a private company for the right to purchase up to 15,040 net acres in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations for an initial purchase price of $11,000 per acre. The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. The agreement was subsequently amended on June 14, 2017 (Successor) to increase the purchase price of the Southern and Northern Tract acreage, from $11,000 per acre to $13,000 per acre, for rights to additional depths in the acreage under option. Pursuant to the terms of the agreement, the Company initially paid $5.0 million and drilled a commitment well on the Southern Tract and on June 15, 2017 (Successor) purchased the Southern Tract acreage for approximately $13,000 per acre. On June 15, 2017 (Successor), the Company also paid $5.0 million and recently drilled a commitment well on the Northern Tract, to earn the option to acquire the Northern Tract acreage for $13,000 per acre by December 31, 2017. This option purchase agreement is not included in the tables above.

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

Contingencies

From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company's management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. COMMITMENTS AND CONTINGENCIES (Continued)

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

11. STOCKHOLDERS' EQUITY

Preferred Stock and Non-Cash Preferred Stock Dividend

On January 24, 2017 (Successor) (the Commitment Date), the Company entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which was convertible into 10,000 shares of common stock. Also on January 24, 2017, the Company received an executed written consent in lieu of a stockholders' meeting authorizing and approving the conversion of the Preferred Stock into common stock. On February 27, 2017, the Company filed with the Delaware Secretary of State a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation), which created the series of preferred stock issued by the Company on that same date. The Company issued the Preferred Stock at $72,500 per share. Gross proceeds were approximately $400.1 million, or $7.25 per share of common stock. The Company incurred approximately $11.9 million in expenses associated with this offering, including placement agent fees. On March 16, 2017, the Company mailed a definitive information statement to its common stockholders notifying them that a majority of its stockholders had consented to the issuance of common stock, par value $0.0001 per share, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 55.2 million shares of common stock on April 6, 2017 in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since, pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to June 1, 2017.

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

In accordance with ASC Topic 470, Debt (ASC 470), the Company determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature. The fair value of the Company's common stock of $8.12 per share on the Commitment Date was greater than the conversion price of $7.25 per share of common stock, representing a beneficial conversion feature of $0.87 per share of common stock, or approximately $48.0 million in aggregate. Under ASC 470, $48.0 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to "Additional paid-in capital," creating a discount on the Preferred Stock (the Discount). The Discount is required to be amortized on a non-cash basis over the approximate 65-month period between the issuance date and the required redemption date of July 28, 2022, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. As a result, approximately $0.8 million of the Discount was amortized and a non-cash preferred dividend was recorded in the three months ended March 31, 2017 (Successor) and due to the conversion date occurring on April 6, 2017, the remaining $47.2 million of the amortization of the Discount was accelerated to the conversion date and fully amortized in the three months ended June 30, 2017 (Successor). The Discount amortization is reflected in "Non-cash preferred dividend" in

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

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

Common Stock

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

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

Warrants

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

Incentive Plans

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

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

The Company accounts for share-based payment accruals under authoritative guidance on stock compensation. The guidance requires all share-based payments to employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values. For awards granted under the 2016 Incentive Plan subsequent to emerging from chapter 11 bankruptcy and in conjunction with the early adoption of ASU 2016-09, the Company has elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited.

For the three and nine months ended September 30, 2017 (Successor) the Company recognized $12.3 million and $33.5 million, respectively, of share-based compensation expense. For the period from September 10, 2016 through September 30, 2016 (Successor), the period from July 1, 2016 through September 9, 2016 (Predecessor) and the period from January 1, 2016 through September 9, 2016 (Predecessor) the Company recognized $13.2 million, $1.2 million, and $4.9 million, respectively, of share-based compensation expense. These were recorded as a component of " General and administrative " on the unaudited condensed consolidated statements of operations.

Stock Options

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

During the nine months ended September 30, 2017 (Successor), the Company granted stock options under the 2016 Incentive Plan covering 1.8 million shares of common stock to employees of the Company. These stock options have exercise prices ranging from $6.55 to $7.75 per share with a weighted average exercise price of $7.72 per share. At September 30, 2017 (Successor), the Company had $17.3 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.5 years.

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

Restricted Stock

From time to time, the Company grants shares of restricted stock to employees and non-employee directors of the Company. Employee shares typically vest over a three year period at a rate of one-third

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. STOCKHOLDERS' EQUITY (Continued)

on the annual anniversary date of the grant, and the non-employee directors' shares vest six months from the date of grant. Certain shares granted under the 2016 Incentive Plan specifically related to the Company's emergence from chapter 11 bankruptcy vested on or before September 30, 2017.

During the nine months ended September 30, 2017 (Successor), the Company granted 2.0 million shares of restricted stock under the 2016 Incentive Plan to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $6.08 to $7.75 per share with a weighted average price of $7.07 per share. At September 30, 2017 (Successor), the Company had $5.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years.

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. EARNINGS PER COMMON SHARE

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

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

	Successor					Predecessor

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


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



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

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



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



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

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



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

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

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. EARNINGS PER COMMON SHARE (Continued)

	Successor					Predecessor

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


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



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

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



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



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

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

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

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

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

	Successor

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

	$	108,753	$	147,762



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

	$	12,171	$	6,940



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

	$	2,408	$	1,887



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

	$	172,012	$	186,184

14. SUBSEQUENT EVENTS

Divestiture of Williston Basin Non-Operated Assets

On September 19, 2017 (Successor), certain wholly owned subsidiaries of the Company entered into an Agreement of Sale and Purchase with a privately-owned company pursuant to which the Company agreed to sell its non-operated properties and related assets located in the Williston Basin in North Dakota and Montana (the Non-Operated Williston Assets) for a total adjusted purchase price of approximately $105.2 million, subject to post-closing adjustments. The effective date of the transaction

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. SUBSEQUENT EVENTS (Continued)

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

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

The following discussion is intended to assist in understanding our results of operations for the three and nine months ended September 30, 2017 (Successor) and the period of September 10, 2016 through September 30, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor) and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, though as described below, our financial statements for prior periods may not be comparable due to our adoption of fresh-start accounting on September 9, 2016. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

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

Overview

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. As discussed below in more detail under "Recent Developments," we have recently acquired certain properties in the Delaware Basin, divested our operated assets located in the Williston Basin and assets located in the El Halcón area of East Texas. As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers more attractive economics. The Williston Divestiture discussed under "Recent Developments, " improved our liquidity and significantly reduced our debt, better enabling us to accelerate development of our Delaware Basin properties and execute our growth plans in the basin.

Our average daily oil and natural gas production decreased slightly in the first nine months of 2017 (Successor) when compared to the same period in the prior year due to the El Halcón Divestiture, discussed under "Recent Developments," on March 9, 2017 and the Williston Divestiture on September 7, 2017. This decrease was partially mitigated by the production associated with the acquisition of the Pecos County Assets on February 28, 2017. During the first nine months of 2017 (Successor), production averaged 34,513 Boe/d compared to average daily production of 33,333 Boe/d and 36,787 Boe/d during the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. During the first nine months of 2017 (Successor), we participated in the drilling of 75 gross (12.6 net) wells, all of which were completed and capable of production.

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

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

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

The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for October 1, 2017 of $51.67 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices, that is more reflective of recent price trends, our ceiling test limitation would not have generated an impairment. Sustained lower commodity prices would have a material impact upon our full cost ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

Divestiture of Williston Basin Non-Operated Assets

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

Divestiture of Williston Basin Operated Assets

On July 10, 2017 (Successor), we and certain of our subsidiaries (the Sellers) entered into an Agreement of Sale and Purchase (the Purchase Agreement) with Bruin Williston Holdings, LLC (the Purchaser) for the sale of all of our operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of our subsidiaries (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion, subject to post-closing adjustments (the Williston Divestiture). The effective date of the sale was June 1, 2017, and we closed the transaction on September 7, 2017. Estimated proved reserves associated with these properties accounted for approximately 104.9 MMBoe, or approximately 71% of our year-end 2016 proved reserves. The Williston Assets generated net production of approximately 26,180 Boe/d, or approximately 76% of our average daily production during the nine months ended September 30, 2017. We are using the proceeds from the sale to repay borrowings outstanding under our Senior Credit Agreement, repurchase $425.0 million principal amount of the outstanding $850.0 million principal amount of our 6.75% senior unsecured notes due 2025 (the 2025 Notes), and redeem all of our outstanding 12% second lien notes, along with general corporate purposes.

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

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accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, we recognized a gain on the sale of $491.8 million during the three months ended September 30, 2017 (Successor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in "Gain (loss) on the sale of oil and natural gas properties," on the Company's unaudited condensed consolidated statements of operations.

Amended and Restated Senior Secured Revolving Credit Agreement

On September 7, 2017 (Successor), the Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Senior Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. The Senior Credit Agreement amends and restates in its entirety the original Senior Secured Revolving Credit Agreement entered into on September 9, 2016. Pursuant to the Senior Credit Agreement, the lenders party thereto have agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a current borrowing base of $100.0 million. The maturity date of the Senior Credit Agreement is September 7, 2022. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The next scheduled redetermination date is May 2018. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.25% to 2.25% for ABR-based loans or at specified margins over LIBOR of 2.25% to 3.25% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00.

Repurchase of 2025 Notes

On September 7, 2017 (Successor), we commenced an offer to purchase for cash up to $425.0 million of the $850.0 million outstanding aggregate principal amount of our 2025 Notes at 103.0% of principal plus accrued and unpaid interest. The consummation of the Williston Divestiture constituted a "Williston Sale" under the indenture governing the 2025 Notes dated as of February 16, 2017 (as supplemented, the February 2017 Indenture). Pursuant to the February 2017 Indenture, we were required to make an offer to all holders of the 2025 Notes to purchase for cash an aggregate principal amount up to $425.0 million of the notes. The offer to purchase expired on October 6, 2017, with notes representing in excess of $425.0 million of principal amount validly tendered. As a result, on October 10, 2017, we repurchased in cash $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest.

Redemption of 2022 Second Lien Notes

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

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redemption price equal to the principal amount of $112.8 million plus a make whole premium of approximately $23.0 million and accrued and unpaid interest of approximately $2.0 million. On September 7, 2017, utilizing $137.8 million of the proceeds from the Williston Divestiture, we deposited with U.S. Bank National Association an amount of funds sufficient to fund the redemption, delivered instructions to apply the deposited funds toward the redemption, and received a written acknowledgment from U.S. Bank National Association of the satisfaction and discharge of the indenture governing the 2022 Second Lien Notes and the obligations of us and our subsidiary guarantors under the 2022 Second Lien Notes and related guarantees. The payment of the redemption price and accrued interest to a holder of 2022 Second Lien Notes became due and payable on the Redemption Date upon presentation and surrender by the holder of such notes.

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

On February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of the 2025 Notes in a private placement exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (Securities Act), Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2017. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers' discounts and commissions and offering expenses. We utilized a portion of the net proceeds from the private placement to fund the repurchase and redemption of the outstanding 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes), discussed further below, and for general corporate purposes.

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

We recognized a loss on the extinguishment of debt, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes.

Divestiture of East Texas Eagle Ford Assets

On January 24, 2017 (Successor), certain of our subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of our oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total adjusted sales price of $491.1 million (the El Halcón Divestiture). The effective date of the sale was January 1, 2017, and the transaction closed on March 9, 2017. We used the net proceeds from the sale to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes. The sale properties included approximately 80,500 net acres prospective

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

We use the full cost method of accounting for our investment in oil and natural gas properties. Under this method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the El Halcón Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, we recognized a gain on the sale of $235.7 million during the nine months ended September 30, 2017 (Successor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in "Gain (loss) on sale of oil and natural gas properties," on the unaudited condensed consolidated statements of operations.

Private Placement of Automatically Convertible Preferred Stock

On January 24, 2017 (Successor), we entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which is convertible into 10,000 shares of common stock. Also on January 24, 2017 (Successor), we received an executed written consent in lieu of a stockholders' meeting authorizing and approving the conversion of the Preferred Stock into common stock. On February 27, 2017 (Successor), we filed with the Delaware Secretary of State a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation), which created the series of preferred stock issued by us on that same date. We issued the Preferred Stock at $72,500 per share. Gross proceeds were approximately $400.1 million, or $7.25 per share of common stock. We incurred approximately $11.9 million in expenses associated with this offering, including placement agent fees. We used the net proceeds from the sale of the Preferred Stock to partially fund the Pecos County Acquisition, which is discussed further below.

On March 16, 2017 (Successor), we mailed a definitive information statement to our common stockholders notifying them that a majority of our stockholders had consented to the issuance of common stock, par value $0.0001 per share, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 55.2 million shares of common stock on April 6, 2017 (Successor) in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since, pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to June 1, 2017.

We determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature of $48.0 million. This portion of the proceeds received from the issuance of the Preferred Stock was allocated to "Additional paid-in capital," creating a discount on the Preferred Stock. The $48.0 million discount was fully amortized during the six months ended June 30, 2017 (Successor) and is reflected in "Non-cash preferred dividend" in the unaudited condensed consolidated statements of operations. The preferred dividend was charged against additional paid-in capital since no retained earnings were available.

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

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

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

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

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

On December 9, 2016 (Successor), we entered into an agreement with a private company for the right to purchase up to 15,040 net acres in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations for an initial purchase price of $11,000 per acre. The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. The agreement was subsequently amended on June 14, 2017 (Successor) to increase the purchase price of the Southern and Northern Tract acreage, from $11,000 per acre to $13,000 per acre, for rights to additional depths in the acreage under option. Pursuant to the terms of the agreement, we initially paid $5.0 million and drilled a commitment well on the Southern Tract and on June 15, 2017 (Successor) purchased the Southern Tract acreage for approximately $13,000 per acre. On June 15, 2017 (Successor), we also paid $5.0 million and recently drilled a commitment well on the Northern Tract, to earn the option to acquire the Northern Tract acreage for $13,000 per acre by December 31, 2017.

Reorganization

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

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

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

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

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

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

Fresh-start Accounting

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

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

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

HK TMS Divestiture

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

Capital Resources and Liquidity

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

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

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

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

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

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

Cash Flow

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

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

	Successor					Predecessor

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


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

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

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

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

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

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

During the first nine months of 2017 (Successor), we incurred cash expenditures of $700.1 million to acquire the Pecos County Assets of which $674.6 million related to the oil and natural gas properties and $25.5 million related to the other operating property and equipment. In addition to the acquisition of the Pecos County Assets, we spent $242.1 million on other acquisitions, primarily in the Delaware Basin to increase our position in the area. We spent $218.9 million on oil and natural gas capital expenditures, of which $206.1 million related to drilling and completion costs. These cash outflows for acquisitions and our drilling and completion activities were more than offset by cash inflows from our non-core sales. Approximately $1.39 billion of the proceeds from the Williston Divestiture were allocated to the oil and natural gas properties divested and $10.9 million of the proceeds were allocated to the other operating property and equipment divested. Proceeds from the sale of the El Halcón Assets were $494.3 million of which $484.1 million related to the oil and natural gas properties divested and $10.2 million related to the other operating property and equipment divested.

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

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

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

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

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

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Contractual Obligations

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

	Payments Due by Period

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

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

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

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

We have entered into various long-term gathering, transportation and sales contracts with respect to production from the Delaware Basin in West Texas. As of September 30, 2017 (Successor), we had in place two long-term crude oil contracts and four long-term natural gas contracts in this area. Under

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

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

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Results of Operations

Three Months Ended September 30, 2017 and 2016

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

	Successor						Predecessor

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

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

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

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

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

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

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

Taxes other than income were $6.8 million, $2.2 million and $7.4 million for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.58 per Boe, $3.10 per Boe and $3.04 per Boe for the three months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of July 1, 2016 through September 9, 2016 (Predecessor), respectively.

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

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

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

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

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

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

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Accordingly, we recognized a gain on the sale of $491.8 million during the three months ended September 30, 2017 (Successor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

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

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

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

We recorded an income tax benefit of $17.0 million for the three months ended September 30, 2017 (Successor) resulting from the reversal of the $12.0 million alternative minimum tax generated primarily by the sale of the El Halcón Assets combined with the reversal of the $5.0 million alternative minimum tax liability recorded in 2016. We recorded an income tax provision of $3.4 million for the period of September 10, 2016 through September 30, 2016 (Successor) and an income tax benefit of $8.7 million for the period of July 1, 2016 through September 9, 2016 (Predecessor) related to our estimated 2016 alternative minimum tax liability and the reversal of the Predecessor 2015 alternative minimum tax liability, respectively.

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Nine Months Ended September 30, 2017 and 2016

	Successor						Predecessor

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

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

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

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

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

Taxes other than income were $29.1 million, $2.2 million and $24.5 million for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $3.09 per Boe, $3.10 per Boe and $2.63 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively.

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

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

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

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

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

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. On a per unit basis, depletion expense was $10.20 per Boe, $12.45 per Boe and $12.33 per Boe for the nine months ended September 30, 2017 (Successor), the period of September 10, 2016 through September 30, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively. The decrease in depletion expense and the depletion rate per Boe from 2016 levels is attributable to decreases in the amortizable base due to our full cost ceiling test impairments recorded in 2016.

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

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston and El Halcón Divestitures were accounted for as adjustments of capitalized costs with no gain or loss recognized, the adjustments would have significantly altered the relationship between capitalized costs and proved reserves at the time of each of the transactions. Accordingly, we recognized a gain on the sale of the Williston Assets of $491.8 million during the three months ended September 30, 2017 (Successor). We recognized a gain on the sale of the El Halcón Assets of $235.7 million during the nine months ended September 30, 2017 (Successor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

We review our other operating property and equipment for impairment in accordance with ASC 360. For the period of January 1, 2016 through September 9, 2016 (Predecessor), we recorded a non-cash impairment charge of $28.1 million. The impairment related to our gross investments of $32.8 million in gas gathering infrastructure that were not likely to be economically recoverable at that point in time due to our shift in exploration, drilling and developmental plans for 2016 to our most economic areas as a result of the low commodity price environment.

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

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

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

On September 7, 2017 (Successor), we issued an irrevocable notice to redeem the outstanding aggregate principal amount of our 2022 Second Lien Notes on October 7, 2017. On September 7, 2017, utilizing $137.8 million of the proceeds from the Williston Divestiture, we deposited with U.S. Bank National Association an amount of funds sufficient to fund the redemption, delivered instructions to apply the deposited funds toward the redemption, and received a written acknowledgment from U.S. Bank National Association of the satisfaction and discharge of the indenture governing the 2022 Second Lien Notes and the obligations of us and our subsidiary guarantors under the 2022 Second Lien Notes and related guarantees. We recognized a loss on the extinguishment of debt, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the notes. During the nine months ended September 30, 2017 (Successor), we repurchased and redeemed approximately $700.0 million principal amount of our 2020 Second Lien Notes. Upon settlement of the repurchases and redemptions, we recorded a net loss on extinguishment of debt of approximately $56.9 million, which included a write-off of $26.0 million associated with the discount for the notes. During the first three months of 2016 (Predecessor), we repurchased approximately $91.8 million principal amount of our then outstanding senior unsecured notes, consisting of $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022 for cash at prevailing market prices at the time of the transactions. The net cash used to make these repurchases was approximately $9.7 million. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased and we recorded a net gain on the extinguishment of debt of approximately $81.4 million, which included the write-down of $0.7 million associated with related issuance costs and discounts and premiums for the respective notes.

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

Recently Issued Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments and Hedging Activity

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

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and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and deferred put options. The total volumes that we hedge through the use of derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our anticipated production for the next 18 to 24 months, when derivative contracts are available at terms (or prices) acceptable to us. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change.

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

Fair Market Value of Financial Instruments

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

Interest Rate Sensitivity

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

Item 4. Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of September 30, 2017. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.

We did not have any change in our internal controls over financial reporting during the three months ended September 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

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

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

		Average Price Paid Per Share

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

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

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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


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

3.1		Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated September 9, 2016 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed September 9, 2016).

3.2		Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed May 7, 2015).

3.2.1		Amendment No. 1 to the Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed September 9, 2016).

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

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

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

10.1		Amended and Restated Senior Secured Revolving Credit Agreement, dated as of September 7, 2017, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 11, 2017).

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

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

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

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

101.INS	*	XBRL Instance Document

101.SCH	*	XBRL Taxonomy Extension Schema Document

101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	*	XBRL Taxonomy Extension Definition Document

101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document

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

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SIGNATURES

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


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

Exhibit 2.1

Execution Version

AGREEMENT OF SALE AND PURCHASE

BY AND AMONG

HALCÓN ENERGY PROPERTIES, INC.,

HRC ENERGY, LLC,

HALCÓN HOLDINGS, INC.,

AND

HALCÓN OPERATING CO., INC.

COLLECTIVELY AS SELLER

AND

RIVERBEND OIL AND GAS VI, LLC

AS PURCHASER

September 19, 2017

TABLE OF CONTENTS

ARTICLE 1 PURCHASE AND SALE		1
Section 1.1	Purchase and Sale	1
Section 1.2	Assets	1
Section 1.3	Excluded Assets	3
Section 1.4	Effective Time; Proration of Costs and Revenues	5
Section 1.5	Delivery and Maintenance of Records	6

ARTICLE 2 PURCHASE PRICE		7
Section 2.1	Purchase Price	7
Section 2.2	Adjustments to Purchase Price	7
Section 2.3	Allocation of Purchase Price	8
Section 2.4	Deposit	8

ARTICLE 3 TITLE MATTERS		9
Section 3.1	Seller’s Title	9
Section 3.2	Definitions of Title Matters	9
Section 3.3	Definition of Permitted Encumbrances	11
Section 3.4	Notice of Title Defect Adjustments	13
Section 3.5	Casualty or Condemnation Loss	18
Section 3.6	Limitations on Applicability	18
Section 3.7	Government Approvals Respecting Assets	18

ARTICLE 4 ENVIRONMENTAL MATTERS		19
Section 4.1	Assessment	19
Section 4.2	NORM, Wastes and Other Substances	21
Section 4.3	Environmental Defects	21
Section 4.4	Inspection Indemnity	23

ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF EACH SELLER		23
Section 5.1	Generally	23
Section 5.2	Existence and Qualification	24
Section 5.3	Power	24
Section 5.4	Authorization and Enforceability	24
Section 5.5	No Conflicts	24
Section 5.6	Liability for Brokers’ Fees	25
Section 5.7	Litigation	25
Section 5.8	Taxes and Assessments	25
Section 5.9	Compliance with Laws	26
Section 5.10	Contracts	26
Section 5.11	Payments for Hydrocarbon Production	26
Section 5.12	Non-Consent Operations	26
Section 5.13	Preference Rights	26
Section 5.14	Payout Balances	27
Section 5.15	Outstanding Capital Commitments	27
Section 5.16	Imbalances	27
Section 5.17	Bankruptcy	27
Section 5.18	Environmental Laws	27

Section 5.19	Foreign Person	28

ARTICLE 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER		28
Section 6.1	Existence and Qualification	28
Section 6.2	Power	28
Section 6.3	Authorization and Enforceability	28
Section 6.4	No Conflicts	28
Section 6.5	Liability for Brokers’ Fees	28
Section 6.6	Litigation	29
Section 6.7	Limitation and Independent Evaluation	29
Section 6.8	SEC Disclosure	29
Section 6.9	Bankruptcy	29
Section 6.10	Qualification	30
Section 6.11	Financing	30

ARTICLE 7 COVENANTS OF THE PARTIES		30
Section 7.1	Access	30
Section 7.2	Government Reviews	31
Section 7.3	Notification of Breaches	31
Section 7.4	Letters-in-Lieu; Assignments	31
Section 7.5	Public Announcements	32
Section 7.6	Operation of Business	32
Section 7.7	Preference Rights and Transfer Requirements	33
Section 7.8	Tax Matters	35
Section 7.9	Further Assurances	36

ARTICLE 8 CONDITIONS TO CLOSING		36
Section 8.1	Conditions of Seller to Closing	36
Section 8.2	Conditions of Purchaser to Closing	37

ARTICLE 9 CLOSING		38
Section 9.1	Time and Place of Closing	38
Section 9.2	Obligations of Seller at Closing	38
Section 9.3	Obligations of Purchaser at Closing	39
Section 9.4	Closing Adjustments	39

ARTICLE 10 TERMINATION		41
Section 10.1	Termination	41
Section 10.2	Effect of Termination	42

ARTICLE 11 POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS; DISCLAIMERS AND WAIVERS		42
Section 11.1	Assumed Seller Obligations	42
Section 11.2	Survival and Limitations; Exclusive Remedy	43
Section 11.3	Indemnification by Seller	44
Section 11.4	Indemnification by Purchaser	45
Section 11.5	Indemnification Proceedings	45
Section 11.6	Release	47
Section 11.7	Disclaimers	47
Section 11.8	Waiver of Trade Practices Acts	48

iii

Section 11.9	Recording	49
Section 11.10	Slawson Holdback; Consent Defect Properties	50

ARTICLE 12 MISCELLANEOUS		51
Section 12.1	Counterparts	51
Section 12.2	Notice	52
Section 12.3	Sales or Use Tax Recording Fees and Similar Taxes and Fees	52
Section 12.4	Expenses	53
Section 12.5	Replacement of Bonds, Letters of Credit and Guarantees	53
Section 12.6	Governing Law and Venue	53
Section 12.7	Captions	53
Section 12.8	Waivers	53
Section 12.9	Assignment	53
Section 12.10	Entire Agreement	54
Section 12.11	Amendment	54
Section 12.12	No Third-Party Beneficiaries	54
Section 12.13	References	54
Section 12.14	Construction	55
Section 12.15	Conspicuousness	55
Section 12.16	Severability	55
Section 12.17	Time of Essence	55
Section 12.18	Limitation on Damages	55

	EXHIBITS

Exhibit A	Leases
Exhibit A-1	Wells
Exhibit A-2	Units and Allocated Values
Exhibit B	Conveyance
Exhibit C	Form of Escrow Agreement

	SCHEDULES

Schedule A	Slawson Wells
Schedule B	Consent Defect Properties
Schedule 1.2(d)	Contracts
Schedule 1.3(d)	Excluded Items
Schedule 1.4	Overhead Costs
Schedule 1.4(b)	Certain Pre-Effective Time Property Costs
Schedule 3.3(f)	Contested Liens
Schedule 5.1	Identification of Certain Officers and Employees of Seller and Identification of Certain Officers and Employees of Purchaser
Schedule 5.7(a)	Party Proceedings
Schedule 5.7(b)	Non-Party Proceedings
Schedule 5.8	Taxes and Assessments

Schedule 5.9	Compliance with Laws
Schedule 5.10	Contract Matters
Schedule 5.11	Hydrocarbon Production Payments
Schedule 5.12	Non-Consent Operations
Schedule 5.13	Preference Rights
Schedule 5.14	Payout Balances
Schedule 5.15	Outstanding Capital Commitments
Schedule 5.16	Imbalances
Schedule 7.6	Operation of Business
Schedule 9.4(c)	Account Information

DEFINITIONS

“1031 Assets” has the meaning set forth in Section 7.8(c) .

“Actual Knowledge” has the meaning set forth in Section 5.1(a) .

“Adjusted Purchase Price” shall mean the Purchase Price after calculating and applying the adjustments set forth in Section 2.2 .

“Adjustment Period” has the meaning set forth in Section 2.2(a) .

“AEA” has the meaning set forth in the definition of Environmental Laws.

“AFE” means authority for expenditure.

“Affiliates” with respect to any Person, means any Person that directly or indirectly controls, is controlled by or is under common control with such Person. The concept of control, controlling or controlled as used in the aforesaid context means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise. No Person shall be deemed an Affiliate of any Person by reason of the exercise or existence of rights, interests or remedies under this Agreement.

“Aggregate Indemnity Deductible” has the meaning set forth in Section 11.2(c) .

“Agreed Accounting Firm” has the meaning set forth in Section 9.4(b) .

“Agreement” means this Agreement of Sale and Purchase.

“Allocated Value” has the meaning set forth in Section 3.4(a) .

“APO” has the meaning set forth in Section 11.10(a) .

“Asset Taxes” has the meaning set forth in Section 7.8(a) .

“Assets” has the meaning set forth in Section 1.2 .

“Assumed Seller Obligations” has the meaning set forth in Section 11.1 .

“BIA Lease Approvals” means the consents, filings, permits and approvals sufficient to validate and give full effect to the assignment to Purchaser, and vest record title in Purchaser, of all Leases from the Bureau of Indian Affairs or other tribal bodies or tribal authorities.

“BLM” means the Bureau of Land Management, U.S. Department of the Interior.

“Business Day” means each calendar day except Saturdays, Sundays, and United States federal holidays.

“CERCLA” has the meaning set forth in the definition of Environmental Laws.

“Claim Notice” has the meaning set forth in Section 11.2(b) .

“Closing” has the meaning set forth in Section 9.1(a) .

“Closing Date” has the meaning set forth in Section 9.1(b) .

“Closing Payment” has the meaning set forth in Section 9.4(a) .

“Code” means the United States Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” has the meaning set forth in Section 7.1(a) .

“Consent Defect Approvals” has the meaning set forth in Section 11.10(d) .

“Consent Defect Properties” has the meaning set forth in Section 11.10(d) .

“Consent Transfer Documents” has the meaning set forth in Section 11.10(d) .

“Contracts” has the meaning set forth in Section 1.2(d) .

“Conveyance” has the meaning set forth in Section 3.1(b) .

“COPAS” has the meaning set forth in Section 1.4(b)(i) .

“Cure Period” has the meaning set forth in Section 3.4(c) .

“Cured Slawson Amount” has the meaning set forth in Section 11.10(b) .

“Customary Post-Closing Filings” has the meaning set forth in Section 3.7 .

“Defensible Title” has the meaning set forth in Section 3.2 .

“Deposit” has the meaning set forth in Section 2.4 .

“DTPA” has the meaning set forth in Section 11.8(a) .

“earned” has the meaning set forth in Section 1.4(b)(i) .

“Effective Time” has the meaning set forth in Section 1.4(a) .

“Environmental Claim Date” has the meaning set forth in Section 4.3(a) .

“Environmental Defect” has the meaning set forth in Section 4.3(a) .

“Environmental Defect Amount” has the meaning set forth in Section 4.3(a) .

“Environmental Defect Deductible” has the meaning set forth in Section 4.3(c) .

“Environmental Defect Notice” has the meaning set forth in Section 4.3(a) .

vii

“Environmental Laws” means, as the same may have been amended, any federal, state or local Law relating to (i) the control of any potential pollutant or protection of the environment, including air, water or land, and human health and safety (ii) the generation, handling, treatment, storage, disposal or transportation Hazardous Materials or waste materials, (iii) the regulation of or exposure to Hazardous Materials, (iv) the cleanup, restoration, or remediation of, or other response to Hazardous Materials on, at, or migrating from, any property, or (v) responsibility for, response to, or restoration of damages (including natural resource damages) caused by Hazardous Materials, including the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq . (“CERCLA”); the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq . (“RCRA”); the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq .; the Clean Air Act, 42 U.S.C. § 7401 et seq . the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq .; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq .; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq .; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Federal Insecticide, Fungicide and Rodenticide Act, 7 U.S.C. § 136 et seq.; the Atomic Energy Act, 42 U.S.C. § 2011 et seq. (“AEA”); and all applicable related Law, whether local, state, territorial, or national, of any Governmental Body having jurisdiction over the property in question addressing pollution or the environment and all regulations implementing the foregoing. The term “Environmental Laws” includes all judicial and administrative decisions, orders, directives, and decrees issued by a Governmental Body pursuant to the foregoing.

“Environmental Liabilities” shall mean any and all environmental response costs (including costs of remediation), damages, natural resource damages, settlements, consulting fees, expenses, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, attorneys’ fees, and other liabilities incurred or imposed (i) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar act (including settlements) by any Governmental Body to the extent arising out of any violation of, or remedial obligation under, any Environmental Laws which are attributable to the ownership or operation of the Assets prior to the Closing or (ii) pursuant to any claim or cause of action by a Governmental Body or other Person for personal injury, property damage, damage to natural resources, remediation or response costs to the extent arising out of any violation of, or any remediation obligation under, any Environmental Laws which is attributable to the ownership or operation of the Assets prior to the Closing.

“Equipment and Facilities” has the meaning set forth in Section 1.2(f) .

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“Escrow Account” has the meaning set forth in Section 2.4.

“Escrow Agent” has the meaning set forth in Section 2.4.

“Escrow Agreement” has the meaning set forth in Section 2.4.

“Event” has the meaning set forth in definition of Material Adverse Effect.

“Excluded Assets” has the meaning set forth in Section 1.3 .

viii

“Execution Date” has the meaning set forth in the preamble hereto.

“Exploration Agreement” has the meaning set forth in Section 11.10(a) .

“Final Purchase Price” has the meaning set forth in Section 9.4(b) .

“Final Settlement Date” has the meaning set forth in Section 9.4(b) .

“Fundamental Representations” has the meaning set forth in Section 11.2(a) .

“Future Well” means a well that may be drilled in the future on a Future Well Location and having the lateral length and being drilled within the specified geographic area and in the formations described on Exhibit A-1 and which, solely for the purposes of determining Defensible Title thereto and any Title Defects associated therewith pursuant to this Agreement, shall be treated as if such well had been drilled and completed and was in existence at or prior to the Execution Date.

“Future Well Location” means a well drilling location described on Exhibit A-1 with a reserve category of “4PUD” or “5PRB”, including the location of the future well path, together with the Leases and/or Units insofar as included in such location.

“GAAP” means generally accepted accounting principles in effect in the United States as amended from time to time.

“Governmental Body” or “Governmental Bodies” means any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body, arbitrator or arbitration panel or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal.

“Hazardous Material” means (i) any “hazardous substance,” as defined by CERCLA, (ii) any “hazardous waste” or “solid waste,” in either case as defined by RCRA, and any analogous state statutes, and any regulations promulgated thereunder, (iii) any solid, hazardous, dangerous or toxic chemical, material, waste or substance, within the meaning of and regulated by any applicable Environmental Laws, (iv) any radioactive material, including any naturally occurring radioactive material, and any source, special or byproduct material as defined in AEA and any amendments or authorizations thereof, (v) any regulated asbestos-containing materials in any form or condition, (vi) any regulated polychlorinated biphenyls in any form or condition, and (vii) petroleum, petroleum hydrocarbons or any fraction or byproducts thereof.

“Hedge Contract” means any contract to which Seller is a party with respect to any swap, forward, future, put, call, floor, cap, collar option or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving or settled by reference to one or more rates, currencies, commodities (including Hydrocarbons), equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions or any derivative instrument as defined in Accounting Standards Codification Section 815.

“Hydrocarbons” means oil, gas, casinghead gas, condensate, natural gas liquids, and other gaseous and liquid hydrocarbons or any combination thereof and sulphur and other minerals extracted from or produced with the foregoing.

“Imbalance” or “Imbalances” means any over-production, under-production, over-delivery, under-delivery or similar imbalance of Hydrocarbons produced from or allocated to the Assets, regardless of whether such over-production, under-production, over-delivery, under-delivery or similar imbalance arises at the wellhead, pipeline, gathering system, transportation system, processing plant or other location.

“incurred” has the meaning set forth in Section 1.4(b)(i) .

“Indemnified Party” has the meaning set forth in Section 11.5(a) .

“Indemnifying Party” has the meaning set forth in Section 11.5(a) .

“Independent Expert” has the meaning set forth in Section 4.3(b) .

“Individual Environmental Threshold” has the meaning set forth in Section 4.3(c) .

“Individual Indemnity Threshold” has the meaning set forth in Section 11.2(c) .

“Individual Title Threshold” has the meaning set forth in Section 3.4(l) .

“Initial Slawson Cure Date” has the meaning set forth in Section 11.10(b) .

“Lands” has the meaning set forth in Section 1.2(a) .

“Law” or “Laws” means all statutes, laws, rules, regulations, ordinances, orders, decrees and codes of Governmental Bodies.

“Leases” has the meaning set forth in Section 1.2(a) .

“Like-Kind Exchange” has the meaning set forth in Section 7.8(c) .

“Loss” or “Losses” means any and all debts, obligations and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), diminution in value, monetary damages, fines, fees, Taxes, penalties, interest obligations, deficiencies, losses and expenses (including amounts paid in settlement, interest, court costs, costs of investigators, reasonable fees and expenses of attorneys, accountants, financial advisors and other experts, and other actual out of pocket expenses incurred in investigating and preparing for or in connection with any Proceeding); however, excluding special, punitive, exemplary, consequential or indirect damages, except to the extent a Party is required to pay such damages to a third party in connection with a matter for which such Party is entitled to indemnification under Article 11 .

“Lowest Cost Response” means the response required or allowed under Environmental Laws that resolves the condition present at the lowest cost (considered as a whole taking into

consideration any material negative impact such response may have on the operations of the relevant assets and any potential material additional costs or liabilities that may likely arise as a result of such response) as compared to any other response that is required or allowed under Environmental Laws that resolves the condition consistent with Environmental Laws.

“Material Adverse Effect” means any change, inaccuracy, circumstance, effect, event, result, occurrence, condition or fact (each an “Event”) (whether or not (i) foreseeable or known as of the date of this Agreement or (ii) covered by insurance) that has had, or could reasonably be expected to have, a material adverse effect on (i) the ownership, operation or value of the Assets, taken as a whole, or (ii) the ability of Seller to consummate the transactions contemplated hereby. Excluded from such Events for the purposes of determining whether a “Material Adverse Effect” has occurred or could reasonably be expected to occur are (A) Events resulting from changes in general market, economic, financial or political conditions or any outbreak of hostilities or war or terrorist events, (B) Events that affect the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally (including changes in commodity prices or general market prices in the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally), (C) any effect resulting from a change in Laws or regulatory policies, (D) matters that are cured by the Closing at no cost to Purchaser, and (E) the consequences of drilling and production operations (including but not limited to depletion, the watering out of any Well(s), collapsed casing or sand infiltration of any Well(s), sidetrack drilling operations on any Well(s), drilling results of any Well(s), and the depreciation of personal property due to ordinary wear and tear with respect to the Assets).

“Material Contracts” means the following types of Contracts: (i) all of the Contracts to which Seller is a party, obligating, or reasonably likely to obligate, the owner of the Assets to sell, lease, farmout, exchange, or otherwise dispose of all or any part of the Assets after the Effective Time (excluding conventional rights of reassignment upon intent to abandon or release a Well, Unit or Lease, and excluding rights and obligations under joint operating agreements), (ii) Contracts containing unperformed commitments to drill additional wells or participate in the conduct of other material field or development operations (other than ordinary lease or term assignment maintenance provisions requiring optional drilling to extend a primary term), (iii) unit agreements (excluding designations of pooled units), unit operating agreements, operating agreements, farmout or farmin agreements, joint venture agreements, limited or general partnership agreements, dry hole agreements, bottom hole agreements, (iv) participation agreements, joint exploration or development agreements or non-competition agreements, in each case to the extent such agreements contain unperformed material obligations or material surviving covenants, insofar as they are attributable to outstanding rights of Seller or any third party to earn additional acreage with regard to the Assets, (v) Contracts with drilling carry or other carry obligations with respect to costs normally chargeable to other lease or mineral owners (and excluding rights and obligations under joint operating agreements) (vi) Contracts that purport to restrict, limit, or prohibit Seller from engaging in any line of business, (vii) Contracts that include any area of mutual interest agreements to which Seller is bound and Purchaser would be bound by upon Closing, (viii) salt water disposal and sales agreements, in each case, which are not terminable without penalty upon sixty (60) days’ notice or less, (ix) Contracts under which any party thereto is presently entitled to receive assignments or conveyances of any Asset not yet made, or could earn additional assignments or conveyances of any Asset after the

Effective Time (excluding rights and obligations under joint operating agreements), (x) all of the Hydrocarbon sales, storage, marketing, balancing, processing, gathering, treatment, separation and compression and transportation agreements, in each case, which are not terminable without penalty upon sixty (60) days’ notice or less, (xi) any Contracts between a Seller and any Affiliate of such Seller, and (xii) any Contracts (other than contracts for utility services) relating to the Assets which could reasonably be expected to obligate Seller to expend in excess of $75,000 (net to its interest) in any calendar year.

“Net Revenue Interest” has the meaning set forth in Section 3.2(a) .

“NORM” means naturally occurring radioactive material.

“Notice Period” has the meaning set forth in Section 11.5(a) .

“Parties” and “Party” has the meaning set forth in the preamble hereto.

“Permit” has the meaning set forth in Section 1.2(i) .

“Permitted Encumbrances” has the meaning set forth in Section 3.3 .

“Person” means any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Body or any other entity.

“Personal Property” has the meaning set forth in Section 1.2(f) .

“Phase I” or “Phase I Assessment” has the meaning set forth in Section 4.1.

“Phase II” or “Phase II Assessment” has the meaning set forth in Section 4.1.

“Plugging and Abandonment Obligations” means any and all responsibility and liability for the following, arising out of or relating to the Assets, whether before, on or after the Effective Time: (a) the necessary and proper plugging, replugging, and abandonment of the Wells; (b) the necessary and proper removal, abandonment, and disposal of all structures, pipelines, equipment, operating inventory, abandoned property, trash, refuse, and junk located on or comprising part of the Assets; (c) the necessary and proper capping and burying of all associated flow lines located on or comprising part of the Assets in connection with any plugging, replugging or abandonment of the Wells; (d) to the extent not covered by clause (b) above, the necessary and proper removal, abandonment, and decommissioning of any facilities comprising part of the Assets; and (e) the necessary and proper restoration of the surface and subsurface (including any required reclamation) to the condition required by the Laws of any Governmental Body and contracts.

“Preference Property” has the meaning set forth in Section 7.7(b) .

“Preference Right” means any right or agreement that enables any Person to purchase or acquire any Asset or any interest therein or portion thereof as a result of or in connection with (i) the sale, assignment or other transfer of any Asset or any interest therein or portion thereof or

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(ii) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Proceeding” or “Proceedings” has the meaning set forth in Section 5.7 .

“Properties” has the meaning set forth in Section 1.2(c) .

“Property Costs” has the meaning set forth in Section 1.4(b)(ii) .

“Purchase Price” has the meaning set forth in Section 2.1 .

“Purchaser” has the meaning set forth in the preamble hereto.

“Purchaser Indemnified Persons” has the meaning set forth in Section 11.3 .

“Qualified Intermediary” has the meaning set forth in Section 7.8(c) .

“RCRA” has the meaning set forth in the definition of Environmental Laws.

“Recognized Environmental Conditions” has the meaning set forth in Section 4.1(b) .

“Records” has the meaning set forth in Section 1.2(h) .

“ REGARDLESS OF FAULT ” means WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY CLAIM, EVEN THOUGH A CLAIM IS CAUSED IN WHOLE OR IN PART BY:

THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), STRICT LIABILITY, OR OTHER FAULT OF THE SELLER INDEMNIFIED PERSONS OR PURCHASER INDEMNIFIED PERSONS, BUT EXCLUDING GROSS NEGLIGENCE AND WILLFUL MISCONDUCT OF ANY SUCH PERSON TO BE INDEMNIFIED; AND/OR

THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), GROSS NEGLIGENCE, STRICT LIABILITY, OR OTHER FAULT OF THIRD PARTIES OR INVITEES, INCLUDING WILLFUL MISCONDUCT; OR

A PRE-EXISTING DEFECT, WHETHER PATENT OR LATENT, IN, ON, UNDER OR WITH RESPECT TO PURCHASER’S PROPERTY OR SELLER’S PROPERTY (INCLUDING WITHOUT LIMITATION THE ASSETS) OR THE PREMISES THERETO OR THE UNSEAWORTHINESS OF ANY VESSEL OR UNAIRWORTHINESS OF ANY AIRCRAFT OR MECHANICAL FAILURE OF ANY VEHICLE OF A PARTY WHETHER CHARTERED, LEASED, OWNED, FURNISHED OR PROVIDED BY ANY OF THE PURCHASER INDEMNIFIED PERSONS, SELLER INDEMNIFIED PERSONS, INVITEES AND/OR THIRD PARTIES .

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“Release Date” has the meaning set forth in Section 11.10(b) .

“Retained Asset” has the meaning set forth in Section 7.7(c) .

“Retained Employee Liabilities” shall mean any liabilities of a Seller (i) to employees of a Seller arising under the Worker Adjustment Retraining Notification Act of 1988 as a result of actions taken by Seller prior to the Closing, (ii) arising out of claims by Seller’s employees with respect to events that occur prior to the Closing and that relate to their employment with, or the terminations of their employment from, the applicable Seller, (iii) with respect to employees of a Seller arising under any “employee benefit plan” (as defined in Section 3(3) of ERISA) that is sponsored by, contributed to, or maintained by, such Seller, or (iv) arising under ERISA for which Purchaser may have any liability under ERISA solely as a result of the consummation of the transactions contemplated by this Agreement.

“Retained Liabilities” means Losses, liabilities and obligations insofar as arising from (a) the Excluded Assets, (b) any proceeding, arbitration, action, suit, pending settlement, or other legal proceeding on Schedules 5.7 (a) or 5.7(b) (insofar as the Losses, liabilities and obligations assessed as a result of the actions or proceedings described thereon are solely attributable to Hydrocarbons produced prior to the Effective Time, and not to Hydrocarbons produced on or after the Effective Time), or that should be disclosed on Schedules 5.7(a) or 5.7(b) for the representation and warranty in Schedules 5.7(a) or 5.7(b) to be true and correct in all respects, (c) any transportation, storage, treatment or disposal of Hazardous Materials off-site of the Assets prior to Closing, (d) subject to Section 9.4(d) , Property Costs for which Seller is responsible pursuant to Section 1.4(b) , (e) the failure to properly pay or have paid, in accordance with the terms of or rights under any Lease, Unit, Contract or applicable Law, all working interest amounts and royalties, overriding royalties and similar burdens upon, measured by or payable out of production from or attributable to the Assets prior to the Effective Time (other than amounts in suspense or otherwise being contested in good faith), but only insofar as Seller or any of its Affiliates received or were otherwise credited with the revenues or proceeds from which such amounts were required to be paid and (f) Retained Employee Liabilities.

“SEC” means the U.S. Securities and Exchange Commission.

“Securities Act” means the Securities Act of 1933, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“Seller” has the meaning set forth in the preamble hereto.

“Seller I” has the meaning set forth in the preamble hereto.

“Seller II” has the meaning set forth in the preamble hereto.

“Seller III” has the meaning set forth in the preamble hereto.

“Seller IV” has the meaning set forth in the preamble hereto.

“Seller Indemnified Persons” has the meaning set forth in Section 11.4 .

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“Slawson Defect Value” has the meaning set forth in Section 11.10(a) .

“Slawson Holdback” shall mean the amount of Four Million, Seven Hundred Fifty Thousand Dollars ($4,750,000) (or such other reduced amount as determined in accordance with Section 11.10(b) ) which shall be retained in the Escrow Account at Closing and handled in accordance with Section 11.10 .

“Slawson Wells” shall mean the Wells described on Schedule A .

“Soft Consent” means any consent or approval required in connection with the transfer of any Assets which do not, by their express terms, render the assignment or the underlying interest void or voidable if the consent is not obtained, or would result in liquidated damages, the termination of any Asset (other than any consent of, notice to, filing with, or other action by any Governmental Body), in each case in connection with the sale or conveyance of oil and/or gas leases or interests therein or Surface Contracts or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Surface Contracts or interests and they are customarily and lawfully obtained subsequent to the sale or conveyance (including consents from state agencies).

“Surface Contracts” has the meaning set forth in Section 1.2(e) .

“Tax” or “Taxes” means (a) all federal, state, local, and foreign income, profits, franchise, sales, use, ad valorem, property, severance, production, excise, stamp, documentary, real property transfer or gain, gross receipts, goods and services, registration, capital, transfer, or withholding taxes or other governmental fees or charges imposed by any Governmental Body, including any interest, penalties or additional amounts which may be imposed with respect thereto, whether disputed or not; (b) any liability to pay amounts described in (a) on behalf of another Person under any contract, arrangement or agreement (whether written or oral), reimbursement or indemnity agreement, as transferee or otherwise; and (c) any liability to pay amount described in (a) by reason of liability imposed under Section 1.1502-6 of the Treasury Regulations or similar provisions imposing liability by reason of participation in a consolidated, combined, unitary or similar Tax Return or similar filing.

“Tax Returns” has the meaning set forth in Section 5.8(a) .

“Termination Date” has the meaning set forth in Section 10.1(b) .

“Third Party Claim” has the meaning set forth in Section 11.5(a) .

“Title Benefit” has the meaning set forth in Section 3.2 .

“Title Benefit Amount” has the meaning set forth in Section 3.4(e) .

“Title Benefit Notice” has the meaning set forth in Section 3.4(b) .

“Title Claim Date” has the meaning set forth in Section 3.4(a) .

“Title Defect” has the meaning set forth in Section 3.2 .

“Title Defect Amount” has the meaning set forth in Section 3.4(d) .

“Title Defect Deductible” has the meaning set forth in Section 3.4(l) .

“Title Defect Notice” has the meaning set forth in Section 3.4(a) .

“Title Defect Property” has the meaning set forth in Section 3.4(a) .

“Title Expert” has the meaning set forth in Section 3.4(k) .

“Transfer Requirement” means any consent, approval, authorization or permit of, or filing with or notification to, any Person which is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Asset or any interest therein; provided, however , that “Transfer Requirement” shall not include (i) any Soft Consent, (ii) and BIA Lease Approvals, or (iii) any consent of, notice to, filing with, or other action by any Governmental Body in connection with the sale or conveyance of oil and/or gas leases or interests therein or Surface Contracts or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Surface Contracts or interests and they are customarily and lawfully obtained subsequent to the sale or conveyance (including consents from state agencies).

“Transfer Taxes” has the meaning set forth in Section 12.3 .

“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed, or final Treasury Regulations.

“Units” has the meaning set forth in Section 1.2(c) .

“Unscheduled (Negative) Imbalance” shall mean, respectively as to each Property and without duplication, the sum (expressed in mcf) of (i) the aggregate make-up, prepaid or other volumes of natural gas, not described on Schedule 5.16 , that a Seller was obligated as of the Effective Time, on account of prepayment, advance payment, take-or-pay, gas balancing or similar obligations, to deliver from such Property after the Effective Time without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent Seller will be entitled to receive partial payment therefor) and (ii) the aggregate pipeline or processing plant Imbalances or overdeliveries, not described in Schedule 5.16 , for which Seller is obligated to pay or deliver natural gas or cash to any pipeline, gatherer, transporter, processor, co-owner or purchaser in connection with any other natural gas attributable to each Property.

“Unscheduled (Positive) Imbalance” shall mean, respectively as to each Property and without duplication, the sum (expressed in mcf) of (i) the aggregate make-up, prepaid or other volumes of natural gas, not described on Schedule 5.16 , that a Seller was entitled as of the Effective Time, on account of prepayment, advance payment, take-or-pay, gas balancing or similar obligations, to receive from such Property after the Effective Time and (ii) the aggregate pipeline or processing plant Imbalances or underdeliveries, not described in Schedule 5.16 , for which Seller is entitled to receive natural gas or cash from any pipeline, gatherer, transporter,

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processor, co-owner or purchaser in connection with any other natural gas attributable to each Property.

“Wells” has the meaning set forth in Section 1.2(b) .

“Working Interest” has the meaning set forth in Section 3.2(b).

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AGREEMENT OF SALE AND PURCHASE

This Agreement of Sale and Purchase is executed on September 19, 2017 (“Execution Date”), by and among Halcón Energy Properties, Inc. , a Delaware corporation (“ Seller I ”), Halcón Operating Co., Inc. , a Texas corporation (“ Seller II ”), Halcón Holdings, Inc. , a Delaware corporation (“ Seller III ”), and HRC Energy, LLC , a Colorado limited liability company (“ Seller IV ”, and together with Seller I, Seller II, Seller III, the “ Seller ”, and each individually, a “ Seller ”) and Riverbend Oil and Gas VI, LLC , a Delaware limited liability company (“ Purchaser ”). Seller and Purchaser may be referred to individually as a “Party” or collectively as the “Parties.”

RECITALS

A. Seller owns certain interests in the Assets as more fully described in Section 1.2 and the exhibits hereto.

B. Seller desires to sell to Purchaser and Purchaser desires to purchase from Seller the properties and rights of Seller hereafter described, in the manner and upon the terms and conditions hereafter set forth.

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties intending to be legally bound by the terms hereof, agree as follows:

ARTICLE 1
PURCHASE AND SALE

Section 1.1 Purchase and Sale . At the Closing, and upon the terms and subject to the conditions of this Agreement, Seller agrees to sell, transfer and convey its interests in the Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the interest of Seller in the Assets and to assume the Assumed Seller Obligations.

Section 1.2 Assets . As used herein, the term “Assets” means, subject to the terms and conditions of this Agreement, all of the Seller’s right, title, interest and estate, in and to the following (but excluding the Excluded Assets):

(a) All of the oil and gas leases; subleases and other leaseholds; interests in fee; carried interests; reversionary interests; net profits interests; royalty interests; overriding royalty interests; forced pooled interests; farmout rights; options; mineral interests and other properties and interests described on Exhibit A , subject to such depth limitations described therein, together with each and every kind and character of right, title, claim, interest and estate that Seller has in and to the lands covered by the Leases and the interests currently pooled, unitized, communitized or consolidated therewith (the “Lands”), and all of the leasehold, royalty and mineral estates covered thereby, including fee mineral interests, mineral leases, leasehold estates, all mineral, royalty, overriding royalty, production payment, reversionary, net profit, contractual leasehold and other similar rights, estates and interests in the Leases, Lands, together with all rights, privileges, benefits and powers conferred upon the holder of said interests with respect to

the use and occupation of the lands (surface and subsurface) covered thereby, in each case subject to the Leases, Contracts, Surface Contracts and applicable Law (collectively, the “Leases”);

(b) All oil, gas, water, disposal, monitoring or injection wells located on the Lands, whether producing, shut-in, or abandoned (whether temporarily or permanently), including the interests in the wells shown on Exhibit A-1 attached hereto (collectively, the “Wells”);

(c) All leasehold interests of Seller in or to any currently existing pools or units which include any Lands or all or a part of any Leases or include any Wells, including those pools or units related to the Properties and associated with the Wells shown on Exhibit A-1 or A-2 (the “Units”; the Units, together with the Leases, Lands, and Wells, being hereinafter referred to as the “Properties”), and including all leasehold interests of Seller in production of Hydrocarbons from any such Units, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease, and all tenements, hereditaments and appurtenances belonging to the Leases and Units;

(d) All contracts, agreements and instruments by which the Properties are bound or subject, or, used or held for use for, or that relate to or are otherwise applicable to the Properties, including to the extent applicable to the Properties or the production of Hydrocarbons produced in association therewith from the Properties, only to the extent applicable to the Properties rather than Seller’s or any of its Affiliates’ other properties, including operating agreements, unitization, pooling and communitization agreements, declarations and orders, joint venture agreements, farmin and farmout agreements, exploration agreements, participation agreements, area of mutual interest agreements, exchange agreements, transportation or gathering agreements, agreements for the sale and purchase of oil, gas or casinghead gas and processing agreements to the extent applicable to the Properties or the production of Hydrocarbons produced in association therewith from the Properties, including those identified on Schedule 1.2(d) (collectively “Contracts”), but excluding any contracts, agreements and instruments to the extent transfer would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived or satisfied pursuant to Section 7.7 and provided that “Contracts” shall not include the instruments constituting the Leases for any purpose under this Agreement and shall not include the Surface Contracts, as such term is defined below;

(e) All easements (including subsurface easements), permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (collectively “Surface Contracts”) appurtenant to, used or held for use in connection with the ownership or operation of Properties, whether part of the premises covered by the Leases, Lands or Units or otherwise, but excluding any permits and other rights to the extent transfer would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived or satisfied pursuant to Section 7.7 ;

(f) All the facilities, equipment and infrastructure that are owned by Seller (insofar as they are owned by Seller as part of the joint account under the applicable joint operating agreement or owned by Seller as one of the co-interest owners of a Unit) which are associated or used in connection with the Wells, including all pipelines, flow lines, gathering lines of systems, compression facilities, equipment, buildings, real property, personal property, mixed property,

machinery, injection facilities, salt water disposal facilities, gas and oil treating facilities fixtures, including any well equipment, casing, tubing, pumps, engines, motors, machinery, rods, tanks, boilers, communication lines, materials and improvements located on the Properties or elsewhere insofar as they are owned by Seller (insofar as they are owned by Seller as part of the joint account under the applicable joint operating agreement or owned by Seller as one of the co-interest owners of a Unit) for the operation of the Properties or the production, treatment, storage, sale, transportation, gathering, separation, injection or disposal of Hydrocarbons or water or other fluids produced from or generated by the Properties or attributable or allocable thereto (the “Equipment and Facilities” and, together with the Wells, the “Personal Property”);

(g) All Hydrocarbons produced from or attributable to the Leases, Lands, and Wells from and after the Effective Time, including all Hydrocarbons stored in tanks and pipelines attributable to the ownership and operation of the Assets as of the Effective Time, together with and subject to Imbalances associated with the Properties;

(h) All lease files, land files, well files, gas and oil sales contract files, gas processing and transportation and storage files, marketing files, gathering files, surface rights and easement files division order files, abstracts, title opinions, land surveys, logs, maps, engineering data and reports, interpretive data, technical evaluations and technical outputs, and other books, records, data, files, financial data and records, and accounting records, including lease operating statements (in accessible digital and physical formats), records showing all funds payable to owners of working interests, royalties and overriding royalties and other interests in the Properties held in suspense by Seller as of the Closing Date, in each case to the extent related to the Properties, or used or held for use in connection with the maintenance or operation thereof and in Seller’s possession (the “Records”); provided, however , that Seller may retain the originals of such Records as Seller has reasonably determined may be required for existing litigation, tax, accounting, auditing purposes or such other record keeping purpose required by Law;

(i) To the extent transferrable, all environmental, governmental (whether federal, state or local) and non-governmental permits, licenses, orders, authorizations, privileges, waivers, consents, emissions or similar credits, franchises and related instruments or rights, in each case relating to the ownership, operation or use of the Properties, including the exploration, drilling for, production, separation, processing, treatment, transporting, gathering, storing, sale or disposal of Hydrocarbons produced from or attributable to the Properties (“Permits”); and

(j) All rights, claims, and causes of action, to the extent such rights, claims, and causes of action relate both to (A) any of the properties described in Sections 1.2(a) through (i) , and (B) to the Assumed Seller Obligations, and other than and excluding (x) rights, claims, and causes of action that Seller may have in, under or relating to this Agreement and (y) rights, claims, and causes of action set forth in Section 1.3 below.

Section 1.3 Excluded Assets . Notwithstanding the foregoing, the Assets shall not include, and there is excepted, reserved and excluded from the transaction contemplated hereby (collectively, the “Excluded Assets”):

(a) except to the extent necessary to satisfy Seller’s obligations under Section 7.1 , (i) all corporate, corporate-level financial, income and franchise tax and legal (other than title, regulatory, Contract, Surface Contract, Permit and similar Asset) records of Seller that relate to Seller’s business generally (whether or not relating to the Assets), (ii) all books, records and files that relate to Excluded Assets, (iii) any records retained by Seller pursuant to Section 1.2(h) , (iv) any books, records, data, files, logs, maps, evaluations, outputs, and accounting records to the extent disclosure or transfer would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived or satisfied pursuant to Section 7.7 , (v) computer or communications software or intellectual property (including tapes, codes, data and program documentation and all tangible manifestations and technical information relating thereto), (vi) attorney-client privileged communications of Seller’s or any of Seller’s Affiliates’ legal counsel (other than title opinions), (vii) reserve studies and similar evaluations, (viii) records relating to the marketing, negotiation, and consummation of the sale of the Assets and (ix) copies of any other Records retained by Seller pursuant to Section 1.5 ;

(b) all rights to any refund and any other rights, titles, claims and interests related to the Retained Liabilities or Taxes or other costs or expenses borne by Seller or Seller’s predecessors in interest and title attributable to periods prior to the Effective Time;

(c) Seller’s area-wide bonds, permits and licenses or other permits, licenses or authorizations used in the conduct of Seller’s business generally;

(d) those items listed in Schedule 1.3(d) ;

(e) all trade credits, accounts receivable, notes receivable, take-or-pay amounts receivable, pre-paid expenses and deposits, and other receivables attributable to the Assets with respect to any period of time prior to the Effective Time, except insofar as such credits, receivables and amounts arise from claims or rights that by their terms offset or cover, or otherwise arise from, liabilities or obligations assumed by Purchaser hereunder;

(f) all Hedge Contracts;

(g) all right, title and interest of Seller in and to vehicles used in connection with the Assets;

(h) all rights, titles, claims and interests of Seller or any Affiliate of Seller (i) to or under any policy or agreement of insurance or any insurance proceeds, except to the extent provided in Section 3.5 , and (ii) to or under any bond or bond proceeds;

(i) any patent, patent application, logo, service mark, copyright, trade name or trademark of or associated with Seller or any Affiliate of Seller or any business of Seller or of any Affiliate of Seller;

(j) a nonexclusive right to freely use any copies of any logs, interpretive data, technical outputs, technical evaluations, maps, engineering data and reports, and other data and information being transferred as a part of the Assets that Seller is entitled to retain pursuant to Section 1.5 ; and

(k) all Retained Assets not conveyed to Purchaser pursuant to Section 7.7 and any Property excluded pursuant to Section 3.4(d)(ii) .

Section 1.4 Effective Time; Proration of Costs and Revenues .

(a) Subject to Section 1.5 , possession of the Assets shall be transferred from Seller to Purchaser at the Closing, but certain financial benefits and burdens of the Assets shall be transferred and assumed effective as of 7:00 A.M., local time, where the respective Assets are located, on April 1, 2017 (the “Effective Time”), as described below.

(b) Purchaser shall be entitled to all Hydrocarbon production from or attributable to the Properties at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets at or after the Effective Time, and Purchaser shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred (i) at and after the Effective Time and (ii) with respect to the properties and items set forth on Schedule 1.4(b) regardless of whether such Property Costs were incurred prior to, on or after the Effective Time Seller shall be entitled to its proportionate share of all Hydrocarbon production from or attributable to the Properties prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets prior to the Effective Time, and Seller shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred by Seller prior to the Effective Time, subject to the provisions of Section 9.4 .

(i) As used in this Agreement, the terms “earned” and “incurred” shall be interpreted in accordance with GAAP and the Council of Petroleum Accountants Society (“COPAS”) standards, as applicable.

(ii) As used in this Agreement, the term “Property Costs” means all costs attributable to the development, exploration or operation of the Assets (including without limitation costs of insurance relating specifically to the Assets and capital expenditures incurred in the development, exploration or operation of the Assets and, where applicable, in accordance with the relevant operating or unit agreement, if any, overhead costs charged to the Assets under the relevant operating or unit agreement, if any, and regardless of whether charged by an Affiliate of a Seller or by a third party, or, if none, the amounts shown under Schedule 1.4 shall be the overhead amounts deemed charged to the Assets); provided, however , the term “Property Costs” does not include any costs, expenses or liabilities attributable to, or arising out of or constituting:

(A) personal injury, illness or death, property damage, torts, breach of contract or non-compliance or violation of any Law;

(B) Remediation obligations or any other obligations relating to the Plugging and Abandonment Obligations or decommissioning of any of the Assets;

(D) obligations with respect to Hedge Contracts;

(E) any income Taxes or Asset Taxes;

(F) any costs or expenses incurred in connection with the cure (or attempted cure) of any Title Defect, Environmental Defect, environmental conditions or matters or other title claims (including claims that Leases have terminated);

(G) costs and expenses incurred in connection with any casualty loss described in Section 3.5 between the Effective Time and the Closing (including any repair or restoration costs related thereto); or

(H) any expenses and payments for which any Party is entitled to indemnity under Article 11 (other than the indemnity in Section 11.3(iii)) for the Retained Liability listed as item (f) and adjustment to the Purchase Price under Section 2.2 (other than Section 2.2(d) or Section 2.2(j) ).

(iii) For purposes of this Section 1.4 , determination of whether Property Costs are attributable to the period before or after the Effective Time shall be based on when services are rendered, when the goods are delivered, or when the work is performed. For clarification, the date an item or work is ordered is not the date of a pre-Effective Time transaction for settlement purposes, but rather the date on which the item ordered is delivered to the job site, or the date on which the work ordered is performed, shall be the relevant date. For purposes of allocating Hydrocarbon production (and accounts receivable with respect thereto), under this Section 1.4 , (x) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Properties when such Hydrocarbons are placed into the storage facilities and (y) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Properties when such Hydrocarbons pass into the delivery point sales or custody transfer meters on the pipelines through which they are transported.

(iv) For purposes of applying other provisions of this Agreement, Property Costs and Asset Taxes that are paid periodically shall be prorated based on the number of days in the applicable period falling before and the number of days in the applicable period falling at or after the Effective Time, except that Hydrocarbon production, severance and similar Taxes shall be prorated based on the number of units actually produced, purchased or sold or proceeds of sale, as applicable, before, and at or after, the Effective Time. In each case, Purchaser shall be responsible for the portion allocated to the period at and after the Effective Time and Seller shall be responsible for the portion allocated to the period before the Effective Time.

Section 1.5 Delivery and Maintenance of Records . Seller shall deliver the Records to Purchaser within thirty (30) days following Closing. Other than any original Records retained by Seller pursuant to Section 1.2(h) , Purchaser shall be entitled to all original Records maintained by Seller. Seller shall be entitled to keep copies of all Records. Purchaser shall preserve the Records for a period of ten (10) years following the Closing and will allow Seller and their respective representatives, consultants and advisors reasonable access, during normal business hours and upon reasonable notice, to the Records for any legitimate business reason of

such Seller, including in order for a Seller to comply with a Tax or other legally required reporting obligation or Tax or legal dispute. Any such access shall be at the sole cost and expense of such Seller. Unless otherwise consented to in writing by Seller for a period of ten (10) years following the Closing Date, Purchaser shall not and shall cause its Affiliates, its permitted transferees, designees and assigns hereunder not to destroy, alter or otherwise dispose of the Records, or any portions thereof, without first giving at least thirty (30) days prior written notice to Seller and offering to surrender to Seller the Records or such portions thereof.

ARTICLE 2
PURCHASE PRICE

Section 2.1 Purchase Price . The purchase price for the Assets (the “Purchase Price”) shall be One Hundred Three Million, Five Hundred Thousand Dollars ($103,500,000), adjusted as provided in Section 2.2 .

Section 2.2 Adjustments to Purchase Price . The Purchase Price for the Assets shall be adjusted in the manner specified below (without duplication), with all such amounts being determined in accordance with GAAP and COPAS standards, as applicable, in order to reach the “Adjusted Purchase Price”:

(a) Reduced by the aggregate amount of the following proceeds received by Seller between (and including) the Effective Time and the Closing Date (with the period between the Effective Time and the Closing Date referred to as the “Adjustment Period”): (i) proceeds from the sale of Hydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out of production, gathering, processing and transportation costs and any production, severance, sales, excise or similar Taxes not reimbursed to Seller by the purchaser of production and paid or borne by Seller) produced from or attributable to the Properties during the Adjustment Period, and (ii) other proceeds earned with respect to the Assets during the Adjustment Period;

(b) Reduced to the extent provided in Section 7.7 with respect to Preference Rights and Retained Assets;

(c) (i) If the Parties make the election under Section 3.4(d)(i) with respect to a Title Defect, subject to the Individual Title Threshold and the Title Defect Deductible, reduced by the Title Defect Amount with respect to such Title Defect if the Title Defect Amount has been determined prior to Closing and (ii) increased by the Title Benefit Amount with respect to each Title Benefit for which the Title Benefit Amount has been determined prior to Closing;

(d) Increased by the amount of all Property Costs attributable to the ownership and operation of the Assets which are paid by Seller and incurred during the Adjustment Period (including any overhead costs under Schedule 1.4 deemed charged to the Assets with respect to the Adjustment Period even though not actually paid), except any Property Costs already deducted in the determination of proceeds in Section 2.2(a) ;

(e) Reduced to the extent provided in Section 3.4(d)(ii) for any Properties excluded from the Assets pursuant to Section 3.4(d)(ii) and reduced to the extent provided in Section 4.3 for Environmental Defects;

(f) Reduced to the extent provided in Section 3.5 in connection with a casualty loss;

(g) Increased or reduced as mutually agreed upon in writing prior to Closing by Seller and Purchaser;

(h) Increased by the value of the amount of any and all Hydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out of production, gathering, processing and transportation costs and any production, severance, sales, excise or similar Taxes not reimbursed to Purchaser by the purchaser of production and paid or borne by Purchaser) stored in tanks above the exit valve or pipeline sale connection attributable to the ownership and operation of the Assets that belong to Seller as of the Effective Time (which value shall be computed by Seller at the applicable third-party contract prices for the month of May 2017 for such stored Hydrocarbons);

(i) (x) Reduced by the product obtained by multiplying the aggregate amount of Unscheduled (Negative) Imbalances by $2.50 per mcf; and (y) increased by the product obtained by multiplying the aggregate amount of Unscheduled (Positive) Imbalances by $2.50 per mcf; and

(j) Reduced by the amount of all Property Costs attributable to the ownership and operation of the Assets which are paid by Purchaser and incurred prior to the Effective Time, except any Property Costs already deducted in the determination of proceeds in Section 2.2(h).

Each adjustment made pursuant to Section 2.2(a) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s entitlement under Section 1.4 to Hydrocarbon production from or attributable to the Properties during the Adjustment Period, and to the value of other income, proceeds, receipts and credits earned with respect to the Assets during the Adjustment Period, and as such, Purchaser shall not have any separate rights to receive any Hydrocarbon production or income, proceeds, receipts and credits with respect to which an adjustment has been made. Similarly, the adjustment described in Section 2.2(d) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s obligation under Section 1.4 to pay Property Costs and other costs attributable to the ownership and operation of the Assets which are incurred during the Adjustment Period.

Section 2.3 Allocation of Purchase Price . The Allocated Values are contained in Exhibit A-2 . Purchaser shall be responsible for assigning the Allocated Values included on Exhibit A-2 , subject to Seller’s right to review the Allocated Values for reasonableness.

Section 2.4 Deposit . A deposit in the amount of Seven Million, Eight Hundred Seventy-Five Thousand Dollars ($7,875,000) (together with any earnings thereon, “Deposit”) shall be paid simultaneously with the execution of this Agreement by Purchaser to Wells Fargo Bank, National Association as escrow agent (“Escrow Agent”), by wire transfer to an interest bearing account (the “Escrow Account”), governed by an agreement in the form attached hereto as Exhibit C (the “Escrow Agreement”). A portion of the Deposit, in an amount equal to Four Million, Seven Hundred Fifty Thousand Dollars ($4,750,000) (or such other reduced amount as determined in accordance with Section 11.10(b) ) shall be converted into the Slawson Holdback at Closing, and the remainder shall be distributed to Seller at Closing as part of the Purchase

Price. Likewise, all interest and earnings on the Deposit shall be paid to Seller at Closing. The Deposit shall be non-refundable and, in the event the transaction contemplated hereby is not consummated in accordance with the terms hereof, the Deposit shall be distributed to Purchaser by the Escrow Agent; provided , however , if the transaction contemplated hereby is not consummated due to Seller’s termination of this Agreement in accordance Section 10.1(c) , the Escrow Agent shall distribute the Deposit to Seller.

ARTICLE 3
TITLE MATTERS

Section 3.1 Seller’s Title .

(a) Except as set forth in this Agreement and/or in the special warranty of title as set forth in Section 3.1(b) , SELLER MAKES NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, WITH RESPECT TO SELLER’S TITLE TO ANY OF THE ASSETS AND PURCHASER HEREBY ACKNOWLEDGES AND AGREES THAT PURCHASER’S SOLE REMEDY FOR ANY DEFECT OF TITLE, INCLUDING ANY TITLE DEFECT, WITH RESPECT TO ANY OF THE ASSETS SHALL BE PURSUANT TO THE PROCEDURES SET FORTH IN THIS ARTICLE 3 .

(b) If the Closing occurs, then effective as of the Closing Date, Seller warrants Defensible Title to the Properties unto Purchaser against every Person whomsoever lawfully claiming by, through and under Seller, but not otherwise, subject, however, to the Permitted Encumbrances, with full substitution and subrogation of Purchaser, and all Persons claiming by, through, and under Seller or its Affiliates (other than as against Seller or one of its Affiliates, with the liability remaining against Seller or its Affiliates being the special warranty of title from Seller described above), in and to all covenants and warranties of Seller’s (or such Affiliates’) predecessors in title and with full subrogation of all rights and all rights of action of warranty against all former owners of the Assets. Except for the limited warranty expressed in the preceding provisions of this Section 3.1(b) , no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets shall be contained in the assignment and conveyance documents substantially in the form attached hereto as Exhibit B to be delivered by Seller to Purchaser at Closing (the “Conveyance”).

(c) Notwithstanding anything stated in this Agreement to the contrary, except for a breach of the representation in Section 5.12 , if a Title Defect under this Article 3 results from any matter which could also result in the breach of any representation or warranty of Seller set forth in Article 5 , then Purchaser shall only be entitled to assert such matter as a Title Defect to the extent permitted by this Article 3 , and shall be precluded from also asserting such matter as the basis of the breach of any representation or warranty.

Section 3.2 Definitions of Title Matters . As used in this Agreement, the term “Defensible Title” means that title of Seller with respect to the Units, Wells, Future Wells or Leases shown in Exhibit A-1 or A-2 , except for and subject to Permitted Encumbrances, that:

(a) Entitles Seller to receive an interest (expressed as a percentage or decimal fraction) of the Hydrocarbons produced, saved and marketed from any Unit, Future Well or Well

shown in Exhibit A-1 or A-2 throughout the duration of the productive life of such Unit, Future Well or Well shown in Exhibit A-1 or A-2 (after satisfaction of all royalties, overriding royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons) (a “Net Revenue Interest”), of not less than the Net Revenue Interest shown in Exhibit A-1 or A-2 for such Unit, Future Well or Well, except (solely to the extent that such actions do not cause a breach of Seller’s covenants under Section 7.6 ) for decreases in connection with those operations in which Seller may from and after the Execution Date become a non-consenting co-owner, decreases resulting from the establishment or amendment from and after the Effective Time of pools or units, and decreases occurring after the Execution Date required to allow other working interest owners to make up past underproduction of Hydrocarbons or pipelines to make up past under deliveries of Hydrocarbons, and except as stated in such Exhibit A-1 or A-2 ;

(b) Obligates Seller to bear a percentage of the costs and expenses for the maintenance and development of, and operations relating to, (i) any Unit, Well, Future Well or Lease shown in Exhibit A-1 or A-2 throughout the productive life of such Unit, Well, Future Well or Lease shown in Exhibit A-1 or A-2 (“Working Interest”) not greater than the Working Interest shown in Exhibit A-1 or A-2 for such Unit, Well, Future Well or Lease, except as stated in Exhibit A-1 or A-2 and except for increases resulting from contribution requirements with respect to non-consenting or defaulting co-owners under applicable operating agreements and increases that are accompanied by at least a proportionate increase in Seller’s Net Revenue Interest; and

As used in this Agreement, the term “Title Defect” means the failure of Seller to have Defensible Title in and to the Units, Wells, Future Wells or Leases as of the Effective Time and the Title Claim Date. Notwithstanding the foregoing, the following shall not be considered Title Defects:

(i) defects based solely on (1) lack of information in Seller’s files, or (2) references to a document(s) if such document(s) is not in Seller’s files;

(ii) defects arising out of lack of corporate or similar entity authorization unless Purchaser provides affirmative written evidence that the action was not authorized and results in another Person’s superior claim of title;

(iii) defects based on failure to record Leases issued by any local, state or federal Governmental Body, or any assignments of such Leases, in the real property, conveyance or other records of the county in which such Property is located;

(iv) defects based on a gap in Seller’s chain of title in the county records as to fee Leases, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain which documents shall be included in a Title Defect Notice;

(v) defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

(vi) defects or irregularities in title in to the extent affecting any Well or Leases held thereby (which has been paying in producing quantities) which have not delayed or prevented Seller’s (and/or Seller’s predecessors) from receiving its Net Revenue Interest share of the proceeds of production from any such Well (which has been paying in producing quantities) and have not caused Seller to bear a share of expenses or costs greater than its Working Interest share from any such Well (which has been paying in producing quantities) for a period of at least ten (10) years prior to the date of this Agreement;

(vii) defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Purchaser provides affirmative evidence that such failure or omission has resulted in another Person’s superior claim of title; and

(viii) defects that have been cured by possession under applicable Laws for adverse possession or prescription.

As used in this Agreement, the term “Title Benefit” shall mean any right, circumstance or condition that operates to increase the Net Revenue Interest of Seller in any Unit, Well or Lease, without causing a greater than proportionate increase in Seller’s Working Interest above that shown in Exhibit A-1 or A-2 as of the Effective Time; provided, however that no Title Benefit can be claimed on a Slawson Well or its applicable drilling and spacing unit, subject to Section 11.10 .

Section 3.3 Definition of Permitted Encumbrances . As used herein, the term “Permitted Encumbrances” means any or all of the following:

(a) Royalties and any overriding royalties, reversionary interests, net profit interests, production payments, carried interests, and other burdens, to the extent that any such burden does not reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1 or A-2 or increase Seller’s Working Interest above that shown in Exhibit A-1 or A-2 without a proportionate increase in the Net Revenue Interest;

(b) The terms of all Leases, Contracts, and Surface Contracts, to the extent that they do not, individually or in the aggregate, reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1 or A-2 or increase Seller’s Working Interest above that shown in Exhibit A-1 or A-2 without a proportionate increase in the Net Revenue Interest;

(d) Transfer Requirements and other required consents, approvals and notices only insofar as required to transfer any of the Assets applicable to this or any future transaction;

(e) Liens for current Taxes or assessments not yet delinquent or, if delinquent, being contested in good faith by appropriate actions;

(f) Any (i) undetermined or inchoate liens or charges constituting or securing the payment of expenses which were incurred incidental to maintenance, development, production or operation of the Assets or for the purpose of developing, producing or processing oil, gas or

other hydrocarbons therefrom or therein and (ii) materialman’s, mechanics’, repairman’s, employees’, contractors’, operators’ or other similar liens, security interests or charges for liquidated amounts arising in the ordinary course of business to construction, maintenance, development, production or operation of the Assets or the production or processing of oil, gas or other hydrocarbons therefrom, that are not delinquent (including any amounts being withheld as provided by Law) and that will be paid in the ordinary course of business or, if delinquent, that are being contested in good faith and set forth on Schedule 3.3(f) ;

(g) All rights to consent by, required notices to, filings with, or other actions by Governmental Bodies in connection with the sale or conveyance of the Assets or interests therein pursuant to this or to any future transaction (if they are not required prior to the sale or conveyance) or are Customary Post-Closing Filings;

(h) Rights of notice or reassignment (or granting an opportunity to receive a reassignment) of a leasehold interest to the holders of such reassignment rights prior to surrendering or releasing such leasehold interest;

(i) Easements, rights-of-way, servitudes, Permits, surface leases and other rights in respect of surface operations, to the extent that they do not detract in any material respect from the value of, or interfere in any material respect with the use, ownership or operation of, the Assets subject thereto or affected thereby (as currently used, owned and operated or as may be reasonably developed);

(j) Calls on Hydrocarbon production under existing Contracts that are listed on Schedule 1.2(d) ;

(k) All rights reserved to or vested in any Governmental Body to control or regulate any of the Assets in any manner, and all obligations and duties under all applicable Laws or under any franchise, grant, license or permit issued by any such Governmental Body, excluding violation or non-compliance that may affect title or prevent reasonable operation or development of the Assets;

(l) Any matters shown on Exhibit A or A-1 ;

(m) Any other liens, charges, encumbrances, defects or irregularities which do not, individually or in the aggregate, detract in any material respect from the value of, or interfere in any material respect with the use or ownership of, the Assets subject thereto or affected thereby (as currently used, operated or owned or as may be reasonably developed), which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties and which do not (A) reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1 or A-2 , or increase Seller’s Working Interest above that shown in Exhibit A-1 or A-2 without a proportionate increase in Net Revenue Interest or (B) materially impair the use, ownership or operation of the Assets (as currently owned and operated by Seller);

(n) Imbalances associated with the Assets;

(o) Liens granted under applicable joint operating agreements and other similar agreements;

(p) The matters disclosed in Schedules 5.7(a) and 5.7(b) ;

(q) Any inchoate lien or trust arising in connection with workers’ compensation, unemployment insurance, pension, employment or child support Laws; and

(r) Any encumbrance, title defect or other matter (whether or not constituting a Title Defect) waived or deemed waived by Purchaser pursuant to this Agreement.

Section 3.4 Notice of Title Defect Adjustments .

(a) To assert a claim of a Title Defect, Purchaser must deliver written claim notices to Seller (each a “Title Defect Notice”) on or before the date that is five (5) days prior to Closing at 5:00 p.m. C.D.T. (the “Title Claim Date”); provided , however , that Purchaser agrees that it shall use reasonable efforts to furnish Seller once every two-weeks until the Title Claim Date a preliminary Title Defect Notice if any officer of Purchaser or any of its Affiliates discovers or learns of any Title Defect during such two (2) week period. To be effective, each Title Defect Notice shall be in writing and shall substantially include (i) a description of the alleged Title Defect(s), (ii) Units, Wells, Future Wells or Leases in Exhibit A-1 or A-2 affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents that sufficiently and reasonably evidence the existence of and extent of the alleged Title Defect(s) and the amount by which the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s), and (v) the amount by which Purchaser reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations and information upon which Purchaser’s belief is based. It is acknowledged that Purchaser must furnish such evidence in accordance with this Article 3 in order to properly assert a Title Defect and may not rely only upon the absence of available information in Seller’s records, and acknowledging that Seller’s title would be subject to Permitted Encumbrances and other limitations set forth in this Article 3 . NOTWITHSTANDING ANY OTHER PROVISION OF THIS AGREEMENT TO THE CONTRARY, PURCHASER SHALL BE DEEMED TO HAVE WAIVED ITS RIGHT TO ASSERT TITLE DEFECTS OF WHICH EACH SELLER HAS NOT BEEN GIVEN A TITLE DEFECT NOTICE ON OR BEFORE THE TITLE CLAIM DATE. For purposes hereof, the “Allocated Value” of an Asset shall mean the portion of the Purchase Price that has been allocated to a particular Lease, Unit, Future Well or Well in Section 2.3 and/or Exhibits A and A-1, or Exhibit A-2, as prepared by Purchaser and reviewed for reasonableness by Seller prior to the execution of this Agreement.

(b) Seller shall have the right, but not the obligation, to deliver to Purchaser on or before the Title Claim Date, with respect to each Title Benefit, a notice (a “Title Benefit Notice”) including (i) a description of the Title Benefit, (ii) the Units, Wells, or Leases in Exhibit A-1 or A-2 affected, (iii) the Allocated Values of the Units, Wells or Leases in Exhibit A-1 or A-2 subject to such Title Benefit, and (iv) the amount by which Seller reasonably believe the Allocated Value of those Units, Wells or Leases is increased by the Title Benefit (as further defined in Section 3.4(e) ), and the computations and information upon which Seller’s belief is based. Seller shall be deemed to have waived all Title Benefits of which it has not given notice on or before the Title Claim Date.

(c) Seller shall have the right, but not the obligation, to attempt, at their sole cost, to cure or remove Title Defects at any time prior to Closing (the “Cure Period”), unless the Parties otherwise agree, any Title Defects of which Seller have been advised in writing by Purchaser. Any asserted Title Defects which are cured within the Cure Period or waived or deemed waived by Purchaser shall be deemed Permitted Encumbrances hereunder.

(d) Remedies for Title Defects. In the event that any Title Defect is not waived by Purchaser or cured on or before Closing, Seller shall elect to have one of the following remedies apply:

(i) subject to the Individual Title Threshold and the Title Defect Deductible, have the Purchase Price reduced by an amount agreed upon (“Title Defect Amount”) pursuant to Section 3.4(g) by Purchaser and Seller as being the value of such Title Defect; provided , however , that the methodology, terms and conditions of Section 3.4(g) shall control any such determination; or

(ii) Seller retains only the quantum of interest in the Property that is subject to and burdened by such Title Defect, together with a proportionate quantum of interest in and to all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value (proportionately reduced to reflect the excluded quantum of interest) of such Property.

In each case of (i) and (ii) above, Seller shall have one hundred eighty (180) days after Closing in which to cure the Title Defect with respect to such Properties. Any Property held back from the initial Closing will be conveyed to Purchaser at a delayed Closing (which shall become the new Closing Date with respect to such Property). The delayed Closing for any portion of a retained Property subject to a cured Title Defect shall occur within ten (10) days following the date of the cure. On such date, Purchaser shall pay to Seller the cured Title Defect Amount of such Property (and subject to the adjustments contemplated herein) in accordance with their respective interests (provided that the aggregate amount paid by Purchaser to Seller on account of Seller’s curing of Title Defects after the Closing shall not exceed the Title Defect Amount), and provided further that if multiple delayed Closings are contemplated as a result of this provision and/or Section 7.7(c) , the delayed Closings may be consolidated on dates mutually agreeable to the Parties. An election to delay the Closing pursuant to Section 3.4(d)(ii) shall not waive Seller’s right to dispute the existence of a Title Defect or to contest the Title Defect Amount asserted with respect thereto. In the event that Seller are unable to cure the Title Defect within one hundred eighty (180) days of the initial Closing, then Seller shall, at its sole election, select one of the two remedies in subsection (i) or (ii) above. Should Seller’s choice ultimately lead to application of Section 3.4(k) , the Title Expert shall be selected within fifteen (15) Business Days of the end of this one hundred eighty (180) day cure period. All other provisions of Section 3.4(k) shall apply as written.

In the event Seller selects the remedy set forth in subsection (i) above, and Purchaser and Seller are unable to agree on the Title Defect Amount, the affected Assets will nevertheless be conveyed to Purchaser at Closing with a reduction by Purchaser’s good faith estimate to the Purchase Price for such Title Defect, subject to Purchaser’s and Seller’s right to a subsequent

adjustment in the Purchase Price for such Title Defect as may result under the provisions of Section 3.4(k) , or as may otherwise be agreed to by the Parties.

(e) With respect to each Unit, Well or Lease in Exhibit A-1 or A-2 affected by Title Benefits reported under Section 3.4(b) , the Purchase Price shall be increased by an amount (the “Title Benefit Amount”) equal to the increase in the Allocated Value for such Unit, Well or Lease in Exhibit A-1 or A-2 caused by such Title Benefits, as determined pursuant to Section 3.4(j) , provided, that the cumulative Title Benefit Amounts will not exceed the cumulative Title Defect Amounts.

(f) Section 3.4(d) shall be the exclusive right and remedy of Purchaser with respect to Title Defects asserted by Purchaser pursuant to Section 3.4(a) and Section 3.4(e) shall be the exclusive right and remedy of Seller with respect to Title Benefits asserted by Seller pursuant to Section 3.4(b) .

(g) The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(i) if Purchaser and Seller agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(ii) if the Title Defect is a lien, encumbrance or other charge which is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii) if the Title Defect results from Seller having a lesser Net Revenue Interest in such Title Defect Property than the Net Revenue Interest specified therefor in Exhibit A - 1 or A-2 , the Title Defect Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Title Defect Property on Exhibit A-1 or A-2 by a fraction, the numerator of which is the reduction in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Title Defect Property in Exhibit A - 1 or A-2 ;

(iv) if the Title Defect results from any matter not described in subsections (i) , (ii) or (iii) above, the Title Defect Amount shall be an amount equal to the difference between the value of the Title Defect Property affected by such Title Defect with such Title Defect and the value of such Title Defect Property without such Title Defect (taking into account the portion of the Purchase Price allocated in Section 2.3 and/or Exhibit A - 1 or A-2 to such Title Defect Property);

(v) if a Title Defect is not effective or does not affect a Title Defect Property throughout the entire remaining productive life of such Title Defect Property, such fact shall be taken into account in determining the Title Defect Amount;

(vi) notwithstanding anything to the contrary in this Article 3 , the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect

Property shall not exceed the Allocated Value of the Title Defect Property and to the extent Purchaser asserts that a Title Defect affects a Unit and reduces the Allocated Value of such Unit, Purchaser shall not be entitled to also assert such Title Defect affects an individual Well within such Unit; and

(vii) with respect to the application of the above methodology in this Section 3.4(g) to a Title Defect affecting a Unit, any discrepancy in Net Revenue Interest and/or Working Interest in the Unit shall be determined by reference to the Net Revenue Interest(s) and Working Interest(s) set forth on Exhibit A-1 for the Wells and/or Future Wells that are included in such Unit; similarly, to determine the amount by which the Allocated Value of the Unit is reduced in the aggregate as a result of the Title Defect, there shall be a separate calculation made for each such Well or Future Well included in the Unit that utilizes the proportion of the Unit’s Allocated Value that such Well or Future Well contributes to the Unit, which proportion is specified on Exhibit A-1 under the column entitled “Proportion of Unit Value”.

(h) The Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder. For example, if a lien affects more than one Title Defect Property or the curative work with respect to one Title Defect results (or is reasonably expected to result) in the curing of any other Title Defect affecting the same or another Title Defect Property, the amount necessary to discharge such lien or the cost and expense of such curative work shall be allocated among the Title Defect Properties so affected (in the ratios of the respective portions of the Purchase Price allocated to such Title Defect Properties) and the amount so allocated to a Title Defect Property shall be included only once in the Title Defect Amount.

(i) No Title Defect Amount shall be allowed on account of and to the extent that an increase in a Seller’s Working Interest in a Property has the effect of proportionately increasing such Seller’s Net Revenue Interest in such Property.

(j) The Title Benefit Amount for any Title Benefit shall mean, with respect to an affected Unit, Well or Lease, the amount by which the value of the affected Unit, Well or Lease is enhanced by virtue of (A) Seller having a greater Net Revenue Interest in such Unit, Well or Lease than the Net Revenue Interest specified therefor in Exhibit A-1 or A-2 or (B) a Seller having a lesser working interest in such Unit, Well or Lease than the working interest specified therefor in Exhibit A-1 or A-2 :

(i) If Purchaser and Seller agree on the Title Benefit Amount, that agreed amount shall be the Title Benefit Amount.

(ii) If the Title Benefit Amount results from a Seller having a greater Net Revenue Interest in such Unit, Well or Lease than the Net Revenue Interest specified therefor in Exhibit A - 1 or A-2 , the Title Benefit Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Unit, Well or Lease in Section 2.3 or Exhibit A -2 by a fraction, the numerator of which is the increase in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Unit, Well or Lease in Exhibit A - 1 or A-2 .

(iii) In determining the amount of Title Benefit Amounts, the principles and methodology set forth in Section 3.4(g) shall generally be applied, mutatis mutandis .

(k) Seller and Purchaser shall attempt in good faith to agree on all Title Defect Amounts and Title Benefit Amounts prior to Closing. If Seller and Purchaser are unable to agree by Closing, then (i) the affected Title Defect Property shall nevertheless be conveyed at Closing, (ii) the amount to be paid to Seller at Closing shall be reduced by Purchaser’s good faith estimate of the Title Defect Amount or Title Benefit Amount, as applicable, and (iii) the Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved pursuant to this Section 3.4(k) . There shall be a single arbitrator, who shall be a title attorney with at least ten (10) years experience in oil and gas titles involving properties in the regional area in which the Properties are located, as selected by mutual agreement of Purchaser and Seller within fifteen (15) Business Days after the end of the Cure Period (the “Title Expert”) (and if no Title Expert is selected by such date, then either Party shall have the right to apply to the Houston, Texas office of the American Arbitration Association to select an independent arbitrator meeting these requirements). The Title Expert’s determination shall be made within fifteen (15) Business Days after submission of the matters in dispute and shall be final and binding upon all Parties, without right of appeal. In making his determination, the Title Expert shall be bound by the rules set forth in Section 3.4(g) and Section 3.4(h) and may consider such other matters as in the opinion of the Title Expert are necessary or helpful to make a proper determination. The Title Expert may allow the Parties to make written submissions of their positions in the manner and to the extent the Title Expert deems appropriate, and the Title Expert may call on the Parties to submit such other materials as the Title Expert deems helpful and appropriate to resolution of the dispute. Additionally, the Title Expert may consult with and engage disinterested third parties to advise the arbitrator, including without limitation petroleum engineers. The Title Expert shall act as an expert for the limited purpose of determining the specific disputed Title Defect Amounts and Title Benefit Amounts submitted by either Party and may not award damages, interest or penalties to any Party with respect to any matter. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case. The costs and expenses of the Title Expert shall be borne and paid one-half by Seller and one-half by Purchaser, including any costs incurred by the Title Expert that are attributable to such third party consultation. Within ten (10) days after the Title Expert delivers written notice to Purchaser and Seller of his award with respect to a Title Defect Amount or a Title Benefit Amount, (i) Purchaser shall pay to Seller the amount, if any, so awarded by the Title Expert to Seller and (ii) Seller shall pay to Purchaser the amount, if any, so awarded by the Title Expert to Purchaser.

(l) Notwithstanding anything to the contrary, (i) in no event under Article 3 shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any individual uncured Title Defect for which the Title Defect Amount therefor does not exceed $50,000 (“Individual Title Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller under Article 3 for uncured Title Defects unless the aggregate Title Defect Amounts attributable to all uncured Title Defects, taken together with the aggregate Environmental Defect Amounts attributable to all uncured Environmental Defects, exceeds a deductible in an amount equal to 2% of the unadjusted Purchase Price (“Title Defect Deductible”), after which point adjustments to the Purchase Price or other remedies shall be made available to Purchaser only with respect to uncured Title Defects where the aggregate Title Defect Amounts are in excess of the Title Defect Deductible; for the

avoidance of doubt, Title Defect Amounts which do not meet the Individual Title Threshold shall not be included in reaching the Title Defect Deductible.

Section 3.5 Casualty or Condemnation Loss .

(a) From and after the Effective Time, but subject to the provisions of Section 3.5(b) below and all other applicable provisions of this Agreement, Purchaser shall assume all risk of loss with respect to any change in the condition of the Assets and for production of Hydrocarbons through normal depletion (including but not limited to the watering out of any Well, collapsed casing or sand infiltration of any Well) and the depreciation of personal property due to ordinary wear and tear with respect to the Assets.

(b) If, prior to the Closing Date, all or a material part of any of the Assets are damaged or destroyed by fire, flood, storm or other casualty or are taken in condemnation or under the right of eminent domain, or if proceedings for such purposes shall be pending or threatened, Seller shall promptly notify Purchaser in writing of the nature and extent of the casualty loss or government taking and Seller’s estimate of the cost required to repair or replace that portion of the Assets affected by the casualty loss or value of the Assets taken by the government. If all or any portion of the Assets are affected by a casualty loss or government taking, the Purchase Price will be adjusted downward by the agreed cost of the casualty loss or the agreed value of the Assets taken by the government, and the Parties will proceed with Closing, subject to the other terms and conditions of this Agreement. With Purchaser’s consent (which shall not be unreasonably withheld), in lieu of adjustments to the Purchase Price, Seller may elect to pay over to Purchaser: (i) all insurance proceeds payable to Seller with respect to any such casualty loss, (ii) all sums paid to Seller by third parties by reason of any such casualty loss, and (iii) all compensation paid to Seller with respect to any such government taking.

Section 3.6 Limitations on Applicability . Without releasing Purchaser’s rights with respect to Seller’s representations in Article 5 (it being understood the same do not directly pertain to title) and the special warranty of title as set forth in Section 3.1(b) , the right of Purchaser to assert a Title Defect under this Agreement and Seller’s rights to assert a Title Benefit under this Agreement shall terminate as of the Title Claim Date, provided there shall be no termination of Purchaser’s or Seller’s rights under Section 3.4 with respect to any bona fide Title Defect properly reported in a Title Defect Notice or bona fide Title Benefit Claim properly reported in a Title Benefit Notice on or before the Title Claim Date.

Section 3.7 Government Approvals Respecting Assets .

(a) Federal, State and BIA Lease Approvals . Solely with respect to customary approvals, transfer forms and documents of Governmental Bodies that are customarily and lawfully obtained and/or filed after the assignment of the Assets and required to effectuate the transfer of the Assets, including BIA Lease Approvals (“Customary Post-Closing Filings”), Purchaser shall, within thirty (30) days after Closing and at Purchaser’s own expense, file for approval with the applicable Governmental Bodies all Customary Post-Closing Filings; provided that all such Customary Post-Closing Filings shall be executed, acknowledged (if applicable) and delivered to Purchaser by Seller at Closing. The Parties further agree, promptly after Closing, to cooperate in taking all other actions reasonably required by federal or state agencies having

jurisdiction to receive approval for or give effect to all Customary Post-Closing Filings. Purchaser shall provide Seller with approved copies of the assignment documents and other state, tribal, and federal transfer documents, as soon as they are available.

(b) Title Pending Governmental Approvals . Until all of the BIA Lease Approvals have been obtained, the following shall occur with respect to the affected portion of the Assets:

(i) Seller shall continue to hold record title to the affected Leases and other affected portion of the Assets as nominee for Purchaser;

(ii) Purchaser shall be responsible for all Assumed Seller Obligations with respect to the affected Leases and other affected portion of the Assets as if Purchaser was the record owner of such Leases and other portion of the Assets as of the Effective Time;

(iii) Seller shall act as Purchaser’s nominee but shall be authorized to act only upon and in accordance with Purchaser’s instructions, and Seller shall have no authority, responsibility or discretion to perform any tasks or functions with respect to the affected Leases and other affected portion of the Assets other than those which are purely administrative or ministerial in nature (including (A) accounting for and remitting any revenues received by Seller to Purchaser with respect to any Asset affected by such unobtained BIA Lease Approvals and (B) submitting all AFE’s and other notices from applicable operators and third Persons delivered for the attention of the owner of any Assets to Purchaser), unless otherwise specifically requested and authorized by Purchaser in writing;

(iv) Seller shall not be obligated to incur any expenses in Seller’s capacity as nominee for the benefit of Purchaser under this Section 3.7(b) , and Purchaser agrees to pay or reimburse Seller for any such expenses promptly upon receiving notice thereof; and

(v) For purposes of Article 11 , Seller and Purchaser shall treat and deal with such affected Leases and other affected portions of the Assets as if full legal and equitable title to the same had passed from Seller to Purchaser at Closing.

ARTICLE 4
ENVIRONMENTAL MATTERS

Section 4.1 Assessment .

(a) Notwithstanding anything in this Agreement to the contrary, Purchaser acknowledges that the permission of the operator or another third Person may be required before Purchaser will be able to access the Assets and that such permission must be obtained prior to access. Seller shall use commercially reasonable efforts to obtain such permission for Purchaser upon Purchaser’s request (and shall keep Purchaser reasonably apprised of the status of all requests for access), provided that Seller shall not be obligated to expend any funds or undertake any material obligations to obtain such permission. Purchaser agrees to comply with (and to cause its officers, employees, agents and authorized representatives to comply with) the rules, regulations and instructions issued by Seller or any operator of the Properties regarding the actions of Purchaser (and its officers, employees, agents and authorized representatives) in conducting any inspection pursuant to this Section 4.1 .

(b) Upon at least two (2) Business Days’ notice to Seller, and subject to Section 4.1(a) above, Purchaser shall be entitled to conduct a Phase I environmental property assessment of the Assets that satisfies the basic assessment requirements set forth under the current American Society for Testing and Material Standard Practice for Phase I environmental property assessments (Designation E1527-13) but such Phase I environmental property assessment shall not include any environmental sampling or testing (the “Phase I Assessment” or “Phase I”, whether one or more). The Phase I Assessment and Purchaser’s other diligence activities shall be conducted at the sole cost, risk and expense of Purchaser, and shall be subject to the indemnity provisions of Section 4.4 . Seller or its respective designee shall have the right to accompany Purchaser and Purchaser’s representatives whenever they are onsite on Assets and also to collect split test samples if any are collected pursuant to a Phase II Assessment. Notwithstanding anything herein to the contrary, Purchaser shall not have access to, and shall not be permitted to conduct any environmental due diligence (including all or any part of the Phase I Assessments) with respect to any Assets where Seller or their Affiliates do not operate such Assets or do not have the authority to grant access for such due diligence; provided, however , Seller and their Affiliates shall use their commercially reasonable efforts to obtain permission from any other Person to allow Purchaser and Purchaser’ representatives such access (and shall keep Purchaser reasonably apprised of the status of all requests for access) and as long as Seller and their Affiliates have exercised such commercially reasonable efforts, Seller shall have no liability to Purchaser for failure to obtain any such other Person’s permission. In the event that Purchaser’s Phase I Assessment identifies actual or potential “Recognized Environmental Conditions,” as such conditions are defined or described under the current American Society for Testing and Material Standard Practice Designation E1527-13, then Purchaser may request Seller’s consent (which may be withheld in its sole discretion) to conduct additional Phase II environmental property assessments or such other activities intended to constitute the conduct of “all appropriate inquiries” under 30 CFR Part 312 (collectively, the “Phase II Assessment” or “Phase II,” whether one or more); and no Phase II Assessment may be conducted without Seller’s prior written consent. The Phase II Assessment procedures and plan concerning any additional investigation shall be submitted to Seller in a written environmental property assessment plan, and shall be reasonable based on the Recognized Environmental Conditions identified by the Phase I Assessment. Thereafter, Seller may, in their sole discretion, approve said environmental property assessment plan, in whole or in part, and Purchaser shall not have the right to conduct any activities set forth in such plan until such time that Seller have approved such plan in writing (which may be withheld in its sole discretion); provided that , notwithstanding the Seller’s rejection of said environmental property assessment plan, in whole or in part, Purchaser may still deliver an Environmental Defect Notice with respect to such Assets pursuant to Section 4.3 . Any such approved environmental property assessment plan shall be performed in accordance with this Article 4 and in compliance with all Laws. Purchaser and Seller shall maintain, and shall cause their respective officers, employees, representatives, consultants and advisors to maintain, all information obtained by Purchaser pursuant to any Phase I, Phase II or other due diligence activity as strictly confidential until the Closing occurs, or in the event that Closing does not occur, for a period of four (4) years from the date of this Agreement, unless disclosure of any facts discovered through such Phase I, Phase II or other due diligence activity is required under any Laws. Purchaser shall provide Seller with a copy of the final version of all environmental reports prepared by, or on behalf of, Purchaser with respect to any Phase I, Phase II or other due diligence activity conducted on the Properties. In the event that

any necessary disclosures under applicable Laws are required with respect to matters discovered by any Phase I, Phase II or other due diligence activity conducted by, for or on behalf of Purchaser, Purchaser agrees that Seller shall be the responsible party for disclosing such matters to the appropriate Governmental Bodies; provided that , if Seller fails to promptly make such disclosure and Purchaser or any of its Affiliates is legally obligated to make such disclosure, such Person shall have the right to fully comply with such legal obligation.

Section 4.2 NORM, Wastes and Other Substances . Purchaser acknowledges that the Assets have been used for the exploration, development, and production of Hydrocarbons and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under the Properties or associated with the Assets. Equipment and sites included in the Assets may contain Hazardous Materials, including NORM. NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms. The wells, materials, and equipment located on, in or under the Properties or included in the Assets may contain Hazardous Materials, including NORM. Hazardous Materials, including NORM, may have come in contact with various environmental media, including without limitation, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media and Hazardous Materials, including NORM, from the Assets.

Section 4.3 Environmental Defects .

(a) If, as a result of its investigation pursuant to Section 4.1 , Purchaser determines that with respect to the Assets, there exists a condition in, on or under an Asset (including air, land, soil, surface and subsurface strata, surface water, ground water, or sediments) that (y) is attributable to the period of time prior to the Environmental Claim Date, and (z) causes an Asset and/or Seller to be in violation of an Environmental Law or requires remediation, notice or corrective action under Environmental Law, or would so cause a violation or require such actions with notice (in each case, an “Environmental Defect”), then on or prior to the date that is five (5) days prior to Closing at 5:00 p.m. C.D.T. (the “Environmental Claim Date”), Purchaser may notify Seller in writing of such Environmental Defect (an “Environmental Defect Notice”). FOR ALL PURPOSES OF THIS AGREEMENT, PURCHASER SHALL BE DEEMED TO HAVE WAIVED ANY ENVIRONMENTAL DEFECT WHICH PURCHASER FAILS TO ASSERT AS AN ENVIRONMENTAL DEFECT BY AN ENVIRONMENTAL DEFECT NOTICE RECEIVED BY EACH SELLER ON OR BEFORE THE ENVIRONMENTAL CLAIM DATE, EXCEPT AS SET FORTH IN SECTION 5.18 . To be effective, each such notice must set forth (i) a description of the alleged Environmental Defect, (ii) the Units, Wells and associated Assets affected by the Environmental Defect, (iii) the Purchaser’s good faith estimate of the Lowest Cost Response to eliminate the Environmental Defect in question (the “Environmental Defect Amount”), and (iv) supporting documents that sufficiently and reasonably evidence the existence of the alleged Environmental Defect and the Environmental Defect Amount. Purchaser shall use reasonable effort to furnish to Seller once every two (2) weeks until the Environmental Claim Date, a written notice of any alleged Environmental Defect that Purchaser discovers or becomes aware of during such two (2) week period.

(b) Seller shall have the right, but not the obligation, to cure any Environmental Defect before Closing or, provided that the Parties shall have agreed to the general plan of remediation with respect to such Environmental Defect and the time period by which such remediation shall take place, after Closing. If Seller disagrees with any of Purchaser’s assertions with respect to the existence of an Environmental Defect or the Environmental Defect Amount, Purchaser and Seller will attempt to resolve the dispute prior to Closing. If the dispute cannot be resolved within ten (10) days of the first meeting of Purchaser and Seller, any Party may submit the dispute to an environmental consultant approved in writing by Seller and Purchaser that is experienced in environmental corrective action at oil and gas properties in the relevant jurisdiction and that shall not have performed professional services for either Party or any of their respective Affiliates during the previous three (3) years (the “Independent Expert”) (and if no Independent Expert has been selected by mutual agreement within fifteen (15) Business Days, then either Party shall have the right to apply to the Houston, Texas office of the American Arbitration Association to select an independent arbitrator meeting these requirements). The Independent Expert may elect to conduct the dispute resolution proceeding by written submissions from Purchaser and Seller with exhibits, including interrogatories, supplemented with appearances by Purchaser and Seller, if necessary, as the Independent Expert may deem necessary. After the Parties and Independent Expert have had the opportunity to review all such submissions, the Independent Expert shall call for a final, written offer of resolution from each Party. The Independent Expert shall render its decision within fifteen (15) Business Days of receiving such offers by selecting one or the other of the offers, or by crafting a decision that represents a compromise between the two offers. In the event the Parties have failed to resolve any dispute regarding an Environmental Defect at Closing, Seller shall retain the Asset affected by the Environmental Defect, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Asset. Thereafter, the Independent Expert shall render his decision regarding the Environmental Defect and the Purchase Price for such retained Asset subject to such Environmental Defect shall be reduced as determined by the Independent Expert or as otherwise agreed to by the Parties. Any Asset so held back from the initial Closing will be conveyed to Purchaser at a delayed Closing (which shall become the new Closing Date with respect to such Asset) within ten (10) days following the date that the Independent Expert delivers written notice to Purchaser and Seller of his award with respect to the Environmental Defect Amount, at which time Purchaser shall pay to Seller the full Allocated Value of the Asset less such Environmental Defect Amount and accounting for other applicable adjustments under Section 2.2 , in accordance with their respective interests.

(c) The Independent Expert may not award damages, interest or penalties to either Party with respect to any matter. The decision of the Independent Expert shall be final and binding upon all Parties, without right of appeal. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case to the Independent Expert. The costs and expenses of the Independent Expert shall be borne and paid one-half by Seller and one-half by Purchaser. The Parties shall adjust the Purchase Price to reflect the Environmental Defect Amounts, as agreed by the Parties or as determined by the Independent Expert, for all uncured Environmental Defects; provided that , notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual uncured Environmental Defect for which the Environmental Defect Amount therefor does not exceed $75,000 (“Individual Environmental Threshold”); (ii) in no event shall there be any adjustments to the Purchase Price for any uncured Environmental Defect unless the aggregate Environmental

Defect Amount attributable to all such Environmental Defects, exceeds a deductible in an amount equal to two percent (2%) of the unadjusted Purchase Price (“Environmental Defect Deductible”), after which point Purchaser shall be entitled to adjustments to the Purchase Price or other remedies only with respect to uncured Environmental Defects where the aggregate Environmental Defect Amounts attributable thereto are in excess of the Environmental Defect Deductible; and (iii) in the event that any Environmental Defect Amount, when combined with any Title Defect Amount for the affected Property, exceeds the Allocated Value of the affected Property, Seller shall have the right to exclude such Property from Closing and reduce the Purchase Price by the Allocated Value of such Property. For the avoidance of doubt, Environmental Defect Amounts which do not meet the Individual Environmental Threshold shall not be included in reaching the Environmental Defect Deductible. To the extent the Independent Expert fails to determine any disputed Environmental Defect Amounts prior to Closing, then, within ten (10) days after the Independent Expert delivers written notice to Purchaser and Seller of his award with respect to an Environmental Defect Amount, Purchaser shall pay to Seller the Purchase Price less the amount, if any, so awarded by the Independent Expert at the delayed Closing described above, and the Parties shall account to one another under Section 2.2 .

Section 4.4 Inspection Indemnity . PURCHASER HEREBY AGREES TO DEFEND, INDEMNIFY, RELEASE, PROTECT, SAVE AND HOLD HARMLESS THE SELLER INDEMNIFIED PERSONS FROM AND AGAINST ANY AND ALL LOSSES ARISING OUT OF THE PHYSICAL ACCESS TO THE WELLS AND LEASES AFFORDED TO PURCHASER OR ITS AGENTS OR REPRESENTATIVES UNDER THIS AGREEMENT, WHETHER BEFORE OR AFTER THE EXECUTION OF THIS AGREEMENT, REGARDLESS OF FAULT; PROVIDED THAT THE FOREGOING SHALL NOT BE CONSTRUED TO REQUIRE PURCHASER TO INDEMNIFY SELLER FOR THE MERE DISCOVERY OF ANY PRE-EXISTING CONDITION. The indemnity obligation set forth in this Section 4.4 shall survive the Closing or termination of this Agreement.

ARTICLE 5
REPRESENTATIONS AND WARRANTIES OF EACH SELLER

Section 5.1 Generally .

(a) Any representation or warranty qualified “to the knowledge of Seller” or “to Seller’s knowledge” or with any similar knowledge qualification is limited to matters within the Actual Knowledge of the officers and management-level employees of Seller who have direct responsibility for the Assets and who have the titles specified on Schedule 5.1 . “Actual Knowledge” for purposes of this Agreement means information actually and personally known by the individuals who have the titles specified on Schedule 5.1 as of the date of this Agreement, without further investigation or inquiry.

(b) Inclusion of a matter on a Schedule to a representation or warranty which addresses matters possibly having a Material Adverse Effect shall not be deemed an indication that such matter does, or may, have a Material Adverse Effect. Likewise, the inclusion of a matter on a Schedule in relation to a representation or warranty shall not be deemed an indication that such matter necessarily would, or may, breach such representation or warranty absent its inclusion on such Schedule. Matters may be disclosed on a Schedule or Exhibit to this

Agreement for purposes of information only. Nothing in the Schedules of Seller is intended to broaden the scope or effect of any representation or warranty contained in this Agreement. Nothing in the Schedules constitutes an admission of any liability or obligation to any third Person, or an admission to any third Person against the interests of Seller. Descriptions of or references to particular contracts, agreements, notices and other documents herein are qualified in their entirety by reference to such documents. In disclosing information pursuant to the Schedules, no Seller waives any attorney-client privilege associated with such information.

(c) Subject to the foregoing provisions of this Section 5.1 , the disclaimers and waivers contained in Section 11.7 and Section 11.8 and the other terms and conditions of this Agreement, Seller represents and warrants to Purchaser the matters set out in the remainder of this Article 5 .

Section 5.2 Existence and Qualification . (i) Seller I is a corporation, duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as a domestic corporation where the Assets it owns are located, (ii) Seller II is a corporation, duly organized, validly existing and in good standing under the laws of the State of Texas and is duly qualified to do business as a domestic corporation where the Assets it owns are located, (iii) Seller III is a corporation, duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as a domestic corporation where the Assets it owns are located, and (iv) Seller IV is a limited liability company, duly organized, validly existing and in good standing under the laws of the State of Colorado and is duly qualified to do business as a domestic limited liability company where the Assets it owns are located.

Section 5.3 Power . Seller has the power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 5.4 Authorization and Enforceability . The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary action on the part of Seller. This Agreement has been duly executed and delivered by Seller (and all documents required hereunder to be executed and delivered by Seller at Closing will be duly executed and delivered by Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Seller, enforceable against Seller in accordance with their terms subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium, and other similar Laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based upon public policy.

Section 5.5 No Conflicts . Subject to compliance with or waiver of the Preference Rights and Transfer Requirements set forth in Schedule 5.13 , and any other required consent, approval, or notice that may be required to transfer any of the Assets, the execution, delivery and performance of this Agreement by such Seller, and the transactions contemplated by this Agreement will not (i) violate any provision of the certificate of formation or incorporation, as applicable, bylaws or limited liability company agreement or any similar governing document of Seller, (ii) result in default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of

the terms, conditions or provisions of any note, bond, mortgage, or indenture to which Seller is a party or which affect the Assets, (iii) violate any judgment, order, ruling, or decree applicable to Seller as a party in interest, (iv) violate any Laws applicable to Seller or any of the Assets, except for (a) rights to consent by, required notices to, filings with, approval or authorizations of, or other actions by any Governmental Body where the same are not required prior to the assignment of the related Asset or they are customarily obtained subsequent to the sale or conveyance thereof and (b) any matters described in clauses (ii) , (iii) or (iv) above which would not be, individually or in the aggregate material to the Assets.

Section 5.6 Liability for Brokers’ Fees . Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Seller or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 5.7 Litigation . With respect to the Assets and Seller’s or any of its Affiliates’ ownership, development, maintenance, or use of any of the Assets, except as set forth in: (i) Schedule 5.7(a) , no proceeding, claim, cause of action, filing, arbitration, action, lawsuit, pending settlement, or other legal proceeding of any kind or nature before or by any Governmental Body (each, a “Proceeding,” and collectively “Proceedings”) (including any take-or-pay claims) to which Seller or any of its Affiliates is a party and which relates to or affects the Assets is pending or, to such Seller’s knowledge, threatened in writing with respect to Seller or any of the Assets, including those where a Seller is a party, or that affect Seller’s ability to consummate the transaction contemplated under this Agreement; and (ii) except as set forth in Schedule 5.7(b) , to Seller’s knowledge, no Proceeding or investigation to which Seller is not a party which relates to the Assets is pending or threatened.

Section 5.8 Taxes and Assessments .

(a) With respect to all Taxes related to the Assets, and except for Taxes being contested in good faith, (i) all reports, returns, statements (including estimated reports, returns or statements), and other similar filings relating to the Assets (the “Tax Returns”) required to be filed by Seller, if any, with respect to such Taxes have been timely filed with the appropriate Governmental Body in all jurisdictions in which such Tax Returns are required to be filed, (ii) such Tax Returns are true and correct in all material respects and (iii) Seller is not delinquent in the payment of such Taxes.

(b) To Seller’s knowledge, with respect to all Taxes related to the Assets, except as set forth on Schedule 5.8 , (i) there are not currently in effect any extensions or waivers of any statute of limitations of any jurisdiction regarding the assessment or collection of any such Tax; (ii) there are no Proceedings against the Assets or Seller by any Governmental Body; and (iii) there are no Tax liens on any of the Assets except for liens for Taxes not yet due or are being contested in good faith.

(c) None of the Assets is an interest in a partnership for U.S. federal income tax purposes. Seller is not a “foreign person” within the meaning of Section 1445 of the Code.

(d) Notwithstanding anything to the contrary contained herein, none of the representations or warranties contained elsewhere in this Article 5 shall relate to Tax matters, which are instead the subject of this Section 5.8 exclusively.

Section 5.9 Compliance with Laws . Except as disclosed on Schedule 5.9 , (a) to Seller’s knowledge, the Assets are, and the ownership, operation, development, maintenance, and use of any of the Assets are, in material compliance with the provisions and requirements of all Laws, licenses and Permits; and (b) to Seller’s knowledge, (i) the applicable operator has and maintains, all necessary governmental permits, licenses, and filings, with regard to the ownership or operation of the Leases, Wells, Units and Lands, as the same are currently owned and operated and (ii) there has not been any violation, cancellation or material modification of any of the foregoing by any other party. Notwithstanding the foregoing, Seller makes no representation or warranty, express or implied, under this Section 5.9 relating to any Environmental Liabilities or Environmental Laws.

Section 5.10 Contracts . Schedule 5.10 sets forth all Material Contracts. Seller has made available to Purchaser true and correct copies of the Material Contracts. Seller is in material compliance and, to Seller’s knowledge, all counterparties are in material compliance with all Material Contracts, except as disclosed on Schedule 5.10 . To Seller’s knowledge, the Material Contracts are in full force and effect and are legal, valid and binding obligations of the parties thereto, their respective successors and assigns.

Section 5.11 Payments for Hydrocarbon Production . Except as set forth on Schedule 5.11 ,

(a) to Seller’s knowledge, all rentals, royalties, excess royalty, overriding royalty interests, Hydrocarbon production payments, and other payments due and payable by Seller to overriding royalty interest holders and other interest owners under or with respect to the Assets and the Hydrocarbons produced therefrom or attributable thereto, have been paid, or if not paid, (i) are being contested in good faith and set forth on Schedule 5.11 ; or (ii) Seller or the operator of the Assets is otherwise entitled to withhold payment while resolving questions of title, obtaining division orders, or resolving other matters in the ordinary course of business; and

(b) Seller is not obligated under any contract or agreement for the sale of gas from the Assets containing a take-or-pay, advance payment, prepayment, or similar provision, or under any gathering, transmission, or any other contract or agreement with respect to any of the Assets to gather, deliver, process, or transport any gas without then or thereafter receiving full payment therefor.

Section 5.12 Non-Consent Operations . Except as set forth on Schedule 5.12 , as of the Execution Date, Seller has not elected not to participate in any operation or activity proposed with respect to the Assets which could result in any of Seller’s interest in such Assets becoming subject to a penalty or forfeiture as a result of such election not to participate in such operation or activity.

Section 5.13 Preference Rights . To such Seller’s knowledge, Schedule 5.13 sets forth all Preference Rights applicable to the Assets, including Preference Rights contained in

easements, rights-of-way or equipment leases included in the Assets. None of the other Assets, or any portion thereof, is subject to any Preference Right which may be applicable to the transactions contemplated by this Agreement, except for Preference Rights as are set forth on Schedule 5.13 .

Section 5.14 Payout Balances . To Seller’s knowledge, Schedule 5.14 contains a complete and accurate list of the status as of March 31, 2017, of any “payout” status for the Wells and Units listed on Exhibit A-1 that are subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

Section 5.15 Outstanding Capital Commitments . As of the Execution Date, there are no outstanding AFEs or other commitments to make capital expenditures which are binding on the Assets and which Seller reasonably anticipates will individually require expenditures by the owner of the Assets, net to its proportionate interest, after the Effective Time in excess of $50,000 other than those shown on Schedule 5.15 .

Section 5.16 Imbalances . To Seller’s knowledge, Schedule 5.16 accurately sets forth in all respects all of such Seller’s Imbalances arising with respect to the Assets and, except as disclosed in Schedule 5.16 , to Seller’s knowledge (i) no Person is entitled to receive any portion of such Seller’s Hydrocarbons produced from the Assets or to receive cash or other payments to “balance” any disproportionate allocation of Hydrocarbons produced from the Assets under any operating agreement, gas balancing or storage agreement, gas processing or dehydration agreement, gas transportation agreement, gas purchase agreement, or other agreements, whether similar or dissimilar, (ii) Seller is not obligated to deliver any quantities of gas or to pay any penalties or other amounts, in connection with the violation of any of the terms of any gas contract or other agreement with shippers with respect to the Assets, and (iii) Seller is not obligated to pay any penalties or other payments under any gas transportation or other agreement as a result of the delivery of quantities of gas from the Wells in excess of the contract requirements. Except as set forth on Schedule 5.16 , Seller has not received, or is not obligated to receive, prepayments (including payments for gas not taken pursuant to “take-or-pay” arrangements) for any of such Seller’s share of the Hydrocarbons produced from the Properties, as a result of which the obligation exists to deliver Hydrocarbons produced from the Properties after the Effective Time without then or thereafter receiving payment therefor.

Section 5.17 Bankruptcy . There are no bankruptcy, reorganization, or receivership proceedings pending against, or, to Seller’s knowledge, being contemplated by or threatened against Seller.

Section 5.18 Environmental Laws . Seller has not received any written notice from any Governmental Body or any other Person of any actual, potential or alleged condition that may result in Environmental Liabilities, which notice or condition has not been fully resolved prior to the Execution Date. Seller has not received any written notice that the Assets are not in material compliance with any Environmental Laws, except for such non-compliance which has been remediated or otherwise resolved. Copies of all environmental reports related to the Assets that are in the possession of the Seller will be made available to Purchaser promptly after execution of this Agreement by the Parties.

Section 5.19 Foreign Person . Seller is not a “foreign person” within the meaning of Section 1445 of the Code.

ARTICLE 6
REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to Seller the following:

Section 6.1 Existence and Qualification . Purchaser is a limited liability company duly formed, validly existing and in good standing under the laws of the State of Delaware; and Purchaser is duly qualified to do business as a foreign limited liability company in every jurisdiction in which it is required to qualify in order to conduct its business, except where the failure to so qualify would not have a material adverse effect on Purchaser; and Purchaser is or will be as of Closing duly qualified to do business as a foreign limited liability company in the respective jurisdictions where the Assets are located.

Section 6.2 Power . Purchaser has the power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 6.3 Authorization and Enforceability . The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary limited liability company action on the part of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and all documents required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable against Purchaser in accordance with their terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other similar Laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based upon public policy.

Section 6.4 No Conflicts . The execution, delivery and performance of this Agreement by Purchaser, and the transactions contemplated by this Agreement will not (i) violate any provision of the organizational documents of Purchaser, (ii) result in a default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or agreement to which Purchaser is a party, (iii) violate any judgment, order, ruling, or regulation applicable to Purchaser as a party in interest, or (iv) violate any Law applicable to Purchaser or any of its assets, or (v) require any filing with, notification of or consent, approval or authorization of any Governmental Body or authority, except any matters described in clauses (ii) , (iii) , (iv) or (v) above which would not have a Material Adverse Effect on Purchaser or the transactions contemplated hereby.

Section 6.5 Liability for Brokers’ Fees . Seller shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Purchaser or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of

compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 6.6 Litigation . There are no Proceedings pending, or to the knowledge of Purchaser, threatened in writing before any Governmental Body against Purchaser or any Affiliate of Purchaser which are reasonably likely to impair materially Purchaser’s ability to perform its obligations under this Agreement.

Section 6.7 Limitation and Independent Evaluation . Except for the representations and warranties expressly made by Seller in Article 5 of this Agreement, or in the Conveyance or in any certificate furnished or to be furnished to Purchaser pursuant to this Agreement, Purchaser represents and acknowledges that (i) there are no representations or warranties, express, statutory or implied, as to the Assets or prospects thereof, and (ii) Purchaser has not relied upon any oral or written information provided by Seller. Without limiting the generality of the foregoing, subject to Section 5.7 and Section 5.18 , Purchaser represents and acknowledges that Seller has not made nor will it make any representation or warranty regarding any matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment or any other environmental condition of the Assets. Purchaser further represents and acknowledges that it is knowledgeable of the oil and gas business and of the usual and customary practices of producers such as Seller, and that it has retained and taken advice concerning the Assets and transactions herein from advisors and consultants which are knowledgeable about the oil and gas business, and that is aware of the risks inherent in the oil and gas business. Purchaser represents that it has or will have access to the Assets, the officers and employees of Seller, and the books, records and files made available by Seller relating to the Assets, and in making the decision to enter into this Agreement and consummate the transactions contemplated hereby, except for the representations and warranties made by Seller in Article 5 , any other agreement between the Parties relating to the transaction contemplated under this Agreement and the special warranty in the Conveyance to be delivered by Seller at Closing, Purchaser has relied solely on the basis of its own independent evaluation and due diligence investigation of the Assets, and its own independent evaluation of the business, economic, legal, tax, or other consequences of this transaction including its own estimate and appraisal of the extent and value of the oil, natural gas, and other reserves attributable to the Properties.

Section 6.8 SEC Disclosure . Purchaser is acquiring the Assets for its own account for use in its trade or business, and not with a view toward or for sale associated with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act and applicable state securities Laws. Purchaser understands and acknowledges that: (i) an investment in the Properties involves certain risks; and (ii) neither the SEC nor any federal, state or foreign agency has passed upon the Properties or made any finding or determination as to the fairness of an investment in the Properties or the accuracy or adequacy of the disclosures made to Purchaser.

Section 6.9 Bankruptcy . There are no bankruptcy, reorganization or receivership proceedings pending against, or, to the knowledge of Purchaser, being contemplated by, or threatened against Purchaser. Purchaser is, and will be immediately after giving effect to the transactions contemplated by this Agreement, solvent.

Section 6.10 Qualification . As of Closing, Purchaser will be qualified to own and assume operatorship of the Leases in the jurisdictions where the Assets to be transferred to Purchaser are located, and the consummation of the transactions contemplated in this Agreement will not cause Purchaser to be disqualified as such an owner or operator. To the extent required by applicable Law, as of the Closing, Purchaser will have lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, such Law (or other requirements) governing the ownership and operation of the Assets.

Section 6.11 Financing . Purchaser has, or will have at Closing, sufficient cash, available lines of credit or other sources of immediately available funds to enable it to pay the Purchase Price to Seller at Closing.

ARTICLE 7
COVENANTS OF THE PARTIES

Section 7.1 Access .

(a) From the date of this Agreement until the Closing, (i) Seller shall use commercially reasonable efforts to assist Purchaser and its representatives, consultants and advisors, in obtaining reasonable access to the Assets, and shall provide full access to the Records, but only to the extent that Seller may do so without waiving any attorney-client privilege or violating any obligations to any third party or any Laws and to the extent that Seller has authority, in its capacity as a non-operator, to assist in obtaining such access without breaching any restriction legally or contractually binding on Seller; provided that Seller shall not be obligated to expend any funds or undertake any material obligations to obtain such permission. Purchaser shall conduct all such inspections and other information gathering described above only (i) during regular business hours and (ii) in a manner which will not materially interfere with the operation of the Assets. All information obtained by Purchaser and its representatives pursuant to this Section 7.1 shall be subject to the terms of that certain confidentiality agreement dated April 19, 2017 (the “Confidentiality Agreement”), by and between Seller and Purchaser and any applicable Contracts or Surface Contracts, in accordance with their terms.

ALL MATERIALS, DOCUMENTS, AND OTHER INFORMATION, MADE AVAILABLE TO PURCHASER AT ANY TIME IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY, WHETHER MADE AVAILABLE PURSUANT TO THIS SECTION OR OTHERWISE, ARE MADE WITHOUT REPRESENTATION OR WARRANTY, AND, EXCEPT FOR SELLER’S REPRESENTATIONS, WARRANTIES AND COVENANTS IN THIS AGREEMENT, WITHOUT REPRESENTATION OR WARRANTY OF ANY KIND, WHETHER EXPRESS, IMPLIED OR STATUTORY, AS TO THE ACCURACY AND COMPLETENESS OF SUCH MATERIALS, DOCUMENTS, AND OTHER INFORMATION OR AS TO WHETHER SUCH MATERIALS, DOCUMENTS AND OTHER INFORMATION CONTAINS A MISREPRESENTATION FOR THE PURPOSES OF APPLICABLE SECURITIES LAWS (WHETHER NOW OR HEREAFTER IN EFFECT). TO THE MAXIMUM EXTENT PERMITTED BY LAW, EXCEPT FOR SELLER’S REPRESENTATIONS, WARRANTIES AND COVENANTS IN THIS AGREEMENT, ANY RELIANCE UPON OR CONCLUSIONS

DRAWN THEREFROM BY PURCHASER SHALL BE AT PURCHASER’S RISK AND SHALL NOT GIVE RISE TO ANY LIABILITY OF OR AGAINST SELLER, AND PURCHASER HEREBY ACKNOWLEDGES THAT IT IS NOT RELYING ON ANY REPRESENTATIONS OTHER THAN SELLER’S WARRANTIES. EXCEPT FOR SELLER’S REPRESENTATIONS, WARRANTIES, COVENANTS, OBLIGATIONS AND INDEMNITY OBLIGATIONS SET FORTH IN THIS AGREEMENT, PURCHASER HEREBY WAIVES AND RELEASES ANY CLAIMS ARISING UNDER THIS AGREEMENT, COMMON LAW OR ANY STATUTE (WHETHER NOW OR HEREAFTER IN EFFECT) ARISING OUT OF OR RELATED TO ANY MATERIALS, DOCUMENTS OR INFORMATION PROVIDED TO PURCHASER OR SELLER’S PROVISION OF SALE TO PURCHASER.

Section 7.2 Government Reviews . Seller and Purchaser shall in a timely manner (i) make all required filings, if any, with and prepare applications to and conduct negotiations with, each Governmental Body as to which such filings, applications or negotiations are necessary or appropriate in the consummation of the transactions contemplated hereby and (ii) provide such information as each may reasonably request to make such filings, prepare such applications and conduct such negotiations. Each Party shall cooperate with and use all commercially reasonable efforts to assist the other with respect to such filings, applications and negotiations.

Section 7.3 Notification of Breaches . Until the Closing,

(a) Purchaser shall notify Seller promptly after Purchaser obtains Actual Knowledge that any representation or warranty of a Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by a Seller prior to or on the Closing Date has not been so performed or observed in any material respect.

(b) Seller shall notify Purchaser promptly after Seller obtains Actual Knowledge that any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by Purchaser prior to or on the Closing Date has not been so performed or observed in any material respect.

(c) If any of Purchaser’s or Seller’s representations or warranties is untrue or shall become untrue in any material respect between the date of execution of this Agreement and the Closing Date, or if any of Purchaser’s or Seller’s covenants or agreements to be performed or observed prior to or on the Closing Date shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing, then such breach shall be considered not to have occurred for all purposes of this Agreement. No such notification shall affect the representations or warranties of the Parties or the conditions to their respective obligations hereunder.

Section 7.4 Letters-in-Lieu; Assignments .

(a) Seller will execute on the Closing Date letters in lieu of division and transfer orders relating to the Assets, on forms prepared by Seller and reasonably satisfactory to Purchaser, to reflect the transactions contemplated hereby.

(b) Seller will prepare and execute, and Purchaser will execute, on the Closing Date, all assignments necessary to convey to Purchaser all federal and state Leases in the form as prescribed by the applicable Governmental Body and otherwise acceptable to Purchaser and Seller.

Section 7.5 Public Announcements . Until the Closing, neither Seller nor Purchaser shall make any press release or other public announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of the others; provided, however , the foregoing shall not restrict disclosures by Purchaser or Seller which are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates. At or after Closing, the content of any press release or public announcement first announcing the consummation of this transaction shall be subject to the prior review and reasonable approval of Seller and Purchaser; provided, however , the foregoing shall not restrict disclosures by Purchaser or Seller which are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates.

Section 7.6 Operation of Business . Except as set forth on Schedule 7.6 , until the Closing, with respect to Assets that are operated by Seller, Seller (i) will not, without the prior written consent of Purchaser, which consent shall not be unreasonably withheld, commit to any operation, or series of related operations thereon, reasonably anticipated to require future capital expenditures by Purchaser as owner of the Assets in excess of $100,000, or make any capital expenditures in respect of the Assets in excess of $100,000, or terminate, amend, execute or extend any material contracts affecting the Assets (including the Leases, Permits Contracts or Material Contracts), (ii) will maintain insurance coverage on the Assets presently furnished by nonaffiliated third parties in the amounts and of the types presently in force, (iii) will not transfer, farmout, sell, hypothecate, encumber or otherwise dispose of any Assets, except for (A) sales and dispositions of Hydrocarbon production in the ordinary course of business consistent with past practices and/or (B) transfers, farmouts, hypothecations, encumbrances or other dispositions of Assets, in one or more transactions, not exceeding $100,000 of consideration (in any form), in the aggregate, and/or (C) except with regard to the pre-Closing assignment of any of the Assets held by Halcón Williston I, LLC, and Halcón Williston II, LLC to another Affiliate of Seller (and which Assets or, with the written consent of Seller, the equity interests of the Seller Affiliate transferee which received such Assets will still be conveyed to Purchaser at Closing), (iv) will not make or change any election with respect to Taxes that would have a Material Adverse Effect on Purchaser or the Assets, (v) elect to participate in any operation or activity proposed with respect to the Assets involving any capital expenditures in respect of the Assets (net to Seller’s interest) in excess of $100,000, (vi) enter, or agree to enter, into any agreement that, if in existence as of the Execution Date, would be a Material Contract, or (vii) will not commit to do any of the foregoing. Purchaser’s approval of any action restricted by this Section 7.6 shall be considered granted within ten (10) days of (unless a shorter time is reasonably required by the circumstances and such shorter time is specified in a Seller’s written notice) Purchaser’s receipt of such Seller’s written notice to Purchaser requesting such consent

unless Purchaser notifies Seller to the contrary in writing during that period. In the event of an emergency, Seller may take such action as a prudent operator would take and shall notify Purchaser of such action promptly thereafter.

Purchaser acknowledges that Seller may own an undivided interest in certain of the Assets, and Purchaser agrees that the acts or omissions of the other working interest owners shall not constitute a violation of the provisions of this Section 7.6 nor shall any action required by a vote of working interest owners constitute such a violation so long as Seller has voted its interest in a manner consistent with the provisions of this Section 7.6 .

Section 7.7 Preference Rights and Transfer Requirements .

(a) The transactions contemplated by this Agreement are expressly subject to all validly existing and applicable Preference Rights and Transfer Requirements, Soft Consents and other required consents and approvals to transfer the Assets. Prior to the Closing Date, Seller shall promptly initiate all procedures which are required to comply with or obtain the waiver of all Preference Rights and Transfer Requirements set forth in Schedule 5.13 and all Soft Consents with respect to the transactions contemplated by this Agreement. Seller shall use commercially reasonable efforts to obtain all such consents and to obtain waivers of applicable Preference Rights; provided , however , Seller shall not be obligated to pay any consideration to (or incur any cost or expense for the benefit of) the holder of any Preference Right, Transfer Requirement or Soft Consent in order to obtain the waiver thereof or compliance therewith; provided , further, that to the extent any Soft Consent are not obtained or waived prior to Closing, Purchaser agrees to assume and close over such unobtained Soft Consents or BIA Lease Approvals without adjustment to the Purchase Price, and Purchaser shall assume all risk and liability relating thereto. Notwithstanding anything to the contrary herein, if any Soft Consent, Transfer Requirement, approval or authorization necessary to preserve any right or benefit under any Contract is not obtained prior to the Closing, Seller shall, subsequent to the Closing, use commercially reasonable efforts to cooperate with Purchaser in attempting to obtain such consent, approval or authorization as promptly thereafter as practicable.

(b) If (i) the holder of a Preference Right elects prior to Closing to purchase the Asset subject to a Preference Right (a “Preference Property”) in accordance with the terms of such Preference Right, and Seller receives written notice of such election prior to the Closing (ii) the time frame for the exercise of a Preference Right has not expired and Seller has not received notice of an intent not to exercise or waiver of the Preference Right, or (iii) a third party exercises its preferential right to purchase, but fails to consummate the transaction prior to the Closing, the Preference Property will be eliminated from the Assets and the Purchase Price shall be reduced by the Allocated Value of the Preference Property.

(i) a third party brings any suit, action or other proceeding prior to the Closing seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby in connection with a claim to enforce a Preference Right;

(ii) an Asset is subject to a Transfer Requirement that is not a Soft Consent, and such Transfer Requirement is not waived, complied with or otherwise satisfied prior to the Closing Date; or

(iii) the holder of a Preference Right does not elect to purchase such Preference Property or waive such Preference Right with respect to the transactions contemplated by this Agreement prior to the Closing Date and the time in which the Preference Right may be exercised has not expired;

then, unless otherwise agreed by Seller and Purchaser, the Asset or portion thereof affected by such Preference Right or Transfer Requirement (a “Retained Asset”) shall be held back from the Assets to be transferred and conveyed to Purchaser at Closing and the Purchase Price to be paid at Closing shall be reduced by the Allocated Value of such Retained Asset pursuant to Section 7.7(b) . Any Retained Asset so held back at the initial Closing will be conveyed to Purchaser at a delayed Closing (which shall become the new Closing Date with respect to such Retained Asset), within ten (10) days following the date on which the suit, action or other proceeding, if any, referenced in clause (i) above is settled or a judgment is rendered (and no longer subject to appeal) or the time for exercise in clause (ii) expires without exercise permitting transfer of the Retained Asset to Purchaser pursuant to this Agreement and Seller complies with or obtains a written waiver of or written notice of election not to exercise, or otherwise satisfies (with respect to Transfer Requirements), all remaining Preference Rights and Transfer Requirements with respect to such Retained Asset as contemplated by this Section 7.7(c) (or if multiple Assets are Retained Assets, on a date mutually agreed to by the Parties in order to consolidate, to the extent reasonably possible, the number of Closings). At the delayed Closing, Purchaser shall pay Seller a purchase price equal to the amount by which the Purchase Price was reduced on account of the holding back of such Retained Asset (as adjusted pursuant to Section 2.2 through the new Closing Date therefor); provided , however , that if all other such Preference Rights and Transfer Requirements with respect to any Retained Asset so held back at the initial Closing are not obtained, complied with, waived or otherwise satisfied as contemplated by this Section within one hundred eighty (180) days after the initial Closing has occurred with respect to any Asset, then such Retained Asset shall be eliminated from the Assets and shall become an Excluded Asset, unless Seller and Purchaser agree to proceed with a closing on such Retained Asset, in which case Purchaser shall be deemed to have waived any objection (and shall be obligated to indemnify the Seller Indemnified Persons for all Losses) with respect to non-compliance with such other Preference Rights and Transfer Requirements with respect to such Retained Asset(s).

(d) Purchaser acknowledges that Seller desires to sell all of the Assets to Purchaser and would not have entered into this Agreement but for Purchaser’s agreement to purchase all of the Assets as herein provided. Accordingly, it is expressly understood and agreed that Seller does not desire to sell any Property affected by a Preference Right to Purchaser unless the sale of all of the Assets is consummated by the Closing Date in accordance with the terms of this Agreement. In furtherance of the foregoing, Seller’s obligation hereunder to sell the Preference Properties to Purchaser is expressly conditioned upon the consummation by the Closing Date of the sale of all of the Assets (other than Retained Assets or other Assets excluded pursuant to the express provisions of this Agreement) in accordance with the terms of this Agreement, either by conveyance to Purchaser or conveyance pursuant to an applicable Preference Right; provided that , nothing herein is intended or shall operate to extend or apply any Preference Right to any

portion of the Assets which is not otherwise burdened thereby. Time is of the essence with respect to the Parties’ agreement to consummate the sale of the Assets by the Closing Date (or by the delayed Closing Date pursuant to Section 7.7(c) ).

Section 7.8 Tax Matters .

(a) Subject to the provisions of Section 12.3 and without duplication hereunder, Seller shall be responsible for all ad valorem, real property, personal property, severance, production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons from or attributable thereto (“Asset Taxes”) attributable to any period of time prior to the Effective Time, and Purchaser shall be responsible for all such Asset Taxes related to the Assets attributable to any period of time on and after the Effective Time. Notwithstanding the foregoing, Seller shall pay or cause to be paid, as applicable, to the appropriate Governmental Body, all Asset Taxes which are required to be paid prior to Closing (and shall file or cause to be filed all Tax Returns with respect to such Taxes); provided, that (i) in the case of ad valorem, real property, personal property, or similar Asset Taxes paid by Seller prior to Closing, Purchaser shall reimburse Seller for the portion of such Taxes pro rated for the period beginning at the Effective Time, and (ii) in the case of severance, production and similar Taxes paid by Seller prior to Closing, Purchaser shall reimburse Seller to the extent such Taxes are attributable to production of Hydrocarbons on or after the Effective Time. Notwithstanding the foregoing, this Section 7.8 shall not apply to income, franchise, corporate, business and occupation, business license and similar Taxes, and Tax Returns therefor, which shall be borne, paid and filed by the Party responsible for such Taxes under applicable Law.

(b) Purchaser and Seller shall cooperate fully, as and to the extent able and as reasonably requested by the other Party, in connection with the filing of any Tax Returns and any audit, litigation or other Proceeding with respect to Asset Taxes. Such cooperation shall include the retention and (upon the other Party’s request) the provision of records and information which are reasonably relevant to any such audit, litigation or other Proceeding and making employees reasonably available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. To the extent applicable, Purchaser and Seller agree (i) to retain all books and records with respect to Asset Tax matters pertinent to the Assets relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations (and, to the extent notified by Purchaser or Seller, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any Governmental Body, and (ii) to give the other Party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other Party so requests, each Party shall allow the other Party the option of taking possession of such books and records prior to their disposal. Purchaser and Seller further agree, upon request, to use their commercially reasonable efforts to obtain any certificate or other document from any Governmental Body or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed with respect to the transactions contemplated hereby.

(c) Purchaser and Seller shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection of accommodating a 1031 exchange (as provided for under Section 1031 of the Code). Each of Purchaser and Seller reserves the right, at or prior to

Closing, to assign its rights under this Agreement with respect to all or a portion of the Purchase Price, and that portion of the Assets associated therewith (“1031 Assets”), to a “Qualified Intermediary” (as that term is defined in Section 1.1031(k)-1(g)(4)(v) of the Treasury Regulations) to accomplish this transaction, in whole or in part, in a manner that will comply with the requirements of a like-kind exchange (“Like-Kind Exchange”) pursuant to Section 1031 of the Code. In order to effect a Like-Kind Exchange, the non-electing Party shall cooperate and do all acts as may be reasonably required or requested by the Party electing for a Like-Kind Exchange with regard to effecting such Like-Kind Exchange, including, but not limited to, executing additional escrow instructions, documents, agreements or instruments to effect an exchange; provided, however , that neither Purchaser nor Seller shall be required to take title to any property other than the Assets in connection with the Like-Kind Exchange, and Closing will not be delayed by reason of any such Like-Kind Exchange. Purchaser and Seller acknowledge and agree that a whole or partial assignment of this Agreement to a Qualified Intermediary shall not release the other Party from any of its respective promises, liabilities and obligations to the other Party or expand any promises, liabilities or obligations of such Party under this Agreement. Neither Party represents to the other that any particular tax treatment will be given to either Party as a result of the Like-Kind Exchange. Neither Party shall be obligated to pay any additional costs or incur any additional obligations in its sale of the Assets if such costs are the result of the other Party’s Like-Kind Exchange, and each Party shall hold harmless and indemnify the other Party from and against all claims, losses and liabilities (including reasonable attorneys’ fees, court costs and related expenses), if any, resulting from such a Like-Kind Exchange.

Section 7.9 Further Assurances . After the Closing, Seller and Purchaser shall, and shall cause their Affiliates, as applicable to, execute, acknowledge and deliver all such further conveyances, transfer orders, division orders, notices assumptions, releases and acquittances, and such other instruments, and shall take such further actions as may be necessary or appropriate to assure fully to Purchaser or Seller (including their successors and assigns) as the case may be, that the transactions described in this Agreement shall be completed and that all of the Assets intended to be conveyed under the terms of this Agreement are so conveyed, including such Assets that are improperly described herein or inadvertently omitted from this Agreement and/or the Conveyance (including the Exhibits attached to each) and to assure fully that Purchaser has assumed the liabilities and obligations intended to be assumed by Purchaser pursuant to this Agreement.

ARTICLE 8
CONDITIONS TO CLOSING

Section 8.1 Conditions of Seller to Closing . The obligations of Seller to consummate the transactions contemplated by this Agreement are subject to the fulfillment on or prior to Closing of each of the following conditions, each of which may be waived by Seller:

(a) Representations . Each of the representations and warranties of Purchaser contained in this Agreement shall be true and correct in all material respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material

respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of such specified date;

(b) Performance . Purchaser shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by Purchaser under this Agreement prior to or on the Closing Date;

(c) Proceedings . No Proceeding by a third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement shall be pending or filed before any Governmental Body and no order, writ, injunction or decree shall have been pending, filed or entered and be in effect by any court or any Governmental Body of competent jurisdiction, and no statute, rule, regulation or other requirement shall have been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby; provided, however , the Closing shall proceed notwithstanding any Proceedings seeking to restrain, enjoin or otherwise prohibit consummation of the transactions contemplated hereby brought by holders of Preference Rights seeking to enforce such rights with respect to the Assets, and the Assets subject to such Proceedings shall be treated as a Preference Property in accordance with Section 7.7 ;

(d) Deliveries . Purchaser shall have delivered (or be ready, willing and able to immediately deliver) to Seller duly executed counterparts of the Conveyance and all other documents and certificates to be delivered by Purchaser under Section 9.3 and shall have performed (or be ready, willing and able to immediately perform) the other obligations required to be performed by it under Section 9.3 ; and

(e) Price Adjustment Limitations . The aggregate downward adjustment (if any) of the Purchase Price which results from the procedures set forth in this Agreement, together with the value of any Title Defects or Environmental Defects (or Title Defect Amounts or Environmental Defect Amounts) in dispute, does not exceed fifteen percent (15%) of the Purchase Price.

Section 8.2 Conditions of Purchaser to Closing . The obligations of Purchaser to consummate the transactions contemplated by this Agreement are subject to the satisfaction or waiver by Purchaser on or prior to Closing of each of the following conditions, each of which may be waived by Purchaser:

(a) Representations . Each of the representations and warranties of the applicable Seller contained in this Agreement shall be true and correct in all respects as of the Execution Date and as of the Closing Date as though made on and as of the Closing Date, except: (i) to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all respects as of such specified date; and (ii) to the extent the failure of such representations or warranties to be true and correct would not, individually or in the aggregate, result in a Material Adverse Effect;

(b) Performance . Seller shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by Seller under this Agreement prior to or on the Closing Date;

(d) Deliveries . Seller shall have delivered (or be ready, willing and able to immediately deliver) to Purchaser duly executed counterparts of the Conveyance and all other documents and certificates to be delivered by Seller under Section 9.2 ; and

(e) Price Adjustment Limitations . The aggregate downward adjustment (if any) of the Purchase Price which results from the procedures set forth in this Agreement does not exceed fifteen percent (15%) of the Purchase Price.

ARTICLE 9
CLOSING

Section 9.1 Time and Place of Closing .

(a) Unless this Agreement shall have been terminated and the transactions herein contemplated shall have been abandoned pursuant to Article 10 , and subject to the satisfaction or waiver of the conditions set forth in Article 8 (other than conditions the fulfillment of which by their nature is to occur at the completion of the transactions contemplated by this Agreement (the “Closing”)), and subject to the provisions of Section 3.4 and Section 7.7 relating to delayed Closings, the Closing shall take place at 10:00 a.m., local time, on November 9, 2017, at the offices of Seller, 1000 Louisiana St., Suite 6700, Houston, Texas 77002, unless another date, time or place is mutually agreed to in writing by Purchaser and Seller. If any of the conditions (other than conditions the fulfillment of which by their nature is to occur at the Closing) set forth in Article 8 are not satisfied or waived at the time the Closing is to occur pursuant to this Section 9.1(a) , then the Closing shall occur on a date that is the third Business Day after the satisfaction or waiver of all such conditions.

(b) The date on which the Closing occurs is herein referred to as the “Closing Date.”

Section 9.2 Obligations of Seller at Closing . At the Closing, upon the terms and subject to the conditions of this Agreement, Seller shall deliver or cause to be delivered to Purchaser, or perform or cause to be performed, the following:

(a) the Conveyance, in sufficient number of counterpart originals to allow recording in all appropriate jurisdictions and offices, duly executed by Seller ;

(b) all applicable assignment, transfer and other forms of any Governmental Bodies, including assignments, on appropriate forms, of state, tribal and of federal leases (or leases of other Governmental Bodies) comprising portions of the Assets, necessary to convey and vest title to Seller as of the Effective Time, duly executed by Seller;

(d) a certificate duly executed by an authorized corporate officer of such Seller, dated as of Closing, certifying on behalf of Seller that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

(e) evidence that all lien releases from such Seller’s lenders have been obtained relating to all mortgages and filings in accordance with the Uniform Commercial Code regarding the Assets;

(f) joint written instructions to the Escrow Agent, directing the release of release of the Deposit to Seller (less and except the Slawson Holdback); and

(g) a certificate that Seller is not a foreign person within the meaning of the Code, as described in Treasury Regulation 1.1445-2(b)(2).

Section 9.3 Obligations of Purchaser at Closing . At the Closing, upon the terms and subject to the conditions of this Agreement, Purchaser shall deliver or cause to be delivered to Seller, or perform or caused to be performed, the following:

(a) a wire transfer to Seller in an amount equal to such Seller’s Closing Payment, in immediately available funds;

(b) the Conveyance, duly executed by Purchaser;

(c) all applicable assignment, transfer and other forms of any Governmental Bodies, including assignments, on appropriate forms, of state, tribal and of federal leases (or leases of other Governmental Bodies) comprising portions of the Assets, necessary to convey and vest title to Seller as of the Effective Time, duly executed by Purchaser;

(d) letters-in-lieu of transfer orders covering the Assets, duly executed by Purchaser;

(e) a certificate by an authorized corporate officer of Purchaser, dated as of Closing, certifying on behalf of Purchaser that the conditions set forth in Section 8.1(a) and Section 8.1(b) have been fulfilled; and

(f) joint written instructions to the Escrow Agent, directing the release of release of the Deposit to Seller (less and except the Slawson Holdback).

Section 9.4 Closing Adjustments .

(a) Not later than five (5) Business Days prior to the Closing Date, Seller shall prepare and deliver to Purchaser, based upon the best information available to Seller, a preliminary settlement statement estimating Seller’s share of the Adjusted Purchase Price after giving effect to all adjustments listed in Section 2.2 , less the Deposit. The estimate delivered in accordance with this Section 9.4(a) shall constitute the dollar amounts to be paid by Purchaser to Seller at the Closing (the “Closing Payment”). Until one (1) Business Day before the Closing Date, Purchaser shall have the opportunity to review and discuss the preliminary settlement statement with Seller; provided, however , Seller shall not be required to make any change thereto to which Seller does not agree, acting reasonably.

(b) As soon as reasonably practicable after the Closing but not later than ninety (90) days following the Closing Date, Seller shall prepare and deliver to Purchaser a statement setting forth the final calculation of the Adjusted Purchase Price, and Seller’s share thereof, and showing the calculation of each adjustment, based, to the extent possible, on actual credits, charges, receipts and other items before and after the Effective Time and taking into account all adjustments provided for in this Agreement (the “Final Purchase Price”). Seller shall, at Purchaser’s request, supply reasonable documentation available to support any credit, charge, receipt or other item. Seller shall afford Purchaser and its representatives the opportunity to review such statement and the supporting schedules, analyses, workpapers, and other underlying records or documentation as are reasonably necessary and appropriate in Purchaser’s review of such statement. Each Party shall cooperate fully and promptly with the other and their respective representatives in such examination with respect to all reasonable requests related thereto. As soon as reasonably practicable but not later than the 30th day following receipt of Seller’s statement hereunder, Purchaser shall deliver to Seller a written report containing any changes that Purchaser proposes be made to such statement. Seller and Purchaser shall undertake to agree on the final statement of the Final Purchase Price, and Seller’s share thereof, no later than one hundred twenty (120) days after the Closing Date (the “Final Settlement Date”). In the event that Seller and Purchaser cannot reach agreement by the Final Settlement Date, either Party may refer the remaining matters in dispute to a nationally-recognized independent accounting firm as may be mutually accepted by Purchaser and Seller, for review and final determination (the “Agreed Accounting Firm”), provided that any dispute with respect to (i) Title Defect Amounts and Title Benefit Amounts shall be exclusively resolved under Section 3.2(k) and (ii) the existence of Environmental Defects or the Environmental Defect Amount shall be exclusively resolved under Section 4.3(b) . Each Party shall summarize its position with regard to the remaining matters in dispute in a written document of twenty-five (25) pages or less and submit such summaries to the Agreed Accounting Firm, together with any other documentation such Party may desire to submit. Within fifteen (15) Business Days after receiving the Parties’ respective submissions, the Agreed Accounting Firm shall render in writing a decision choosing a Seller’s position or Purchaser’s position or a position in between those (but in no event higher or lower than the amounts proposed in the post-Closing statements exchanged between the Parties, as described earlier in this subsection) based on the materials described above. The Agreed Accounting Firm may not award damages or penalties to either Party. Any decision rendered by the Agreed Accounting Firm pursuant hereto shall be final, conclusive and binding on Seller and Purchaser and will be enforceable against any of the Parties in any court of competent jurisdiction. The fees of the Agreed Accounting Firm shall be borne and paid one-half by Seller and one-half by Purchaser. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case. Within ten (10) Business Days after the date on which the Parties or the Agreed

Accounting Firm, as applicable, finally determines the disputed matters, (x) Purchaser shall pay to Seller Seller’s share of the amount by which the Final Purchase Price exceeds the Closing Payment or (y) Seller shall pay to Purchaser the amount by which such Seller’s share of the Closing Payment exceeds Seller’s share of the Final Purchase Price, as applicable.

(c) All payments made or to be made hereunder to Seller shall be by electronic transfer of immediately available funds to the account of Seller as set forth on Schedule 9.4(c) , for the credit of Seller or to such other bank and account as may be specified by Seller in writing. All payments made or to be made hereunder to Purchaser shall be by electronic transfer of immediately available funds to a bank and account specified by Purchaser in writing to Seller.

(d) Upon the agreement of the Parties on the Final Purchase Price as described in Section 9.4(b) above, the Final Closing Statement shall be deemed final, and no more adjustments shall be made in accordance with this Section 9.4 and any and all liabilities relating to the Assets shall be addressed exclusively under Article 11 below.

ARTICLE 10
TERMINATION

Section 10.1 Termination . This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Closing, it being agreed that the following rights shall represent the sole and exclusive remedies of the Parties in the event Closing fails to occur:

(a) by mutual written consent of Seller and Purchaser;

(b) by Seller or by Purchaser, if:

(i) the Closing shall not have occurred on or before November 30, 2017 (the “Termination Date”); or

(ii) there shall be any Law that makes consummation of the transactions contemplated hereby illegal or otherwise prohibited or a Governmental Body shall have issued an order, decree, or ruling or taken any other action permanently restraining, enjoining, or otherwise prohibiting the consummation of the transactions contemplated hereby, and such order, decree, ruling, or other action shall have become final and non-appealable;

(c) by Seller, if Purchaser shall have failed to fulfill in any material respect any of its obligations under this Agreement or breach any of its representations and warranties under this Agreement in any material respect, and such failure has not been cured within ten (10) days after written notice thereof from Seller to Purchaser; provided that , any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date; or

(d) by Purchaser, if a Seller shall have failed to fulfill in any material respect any of its obligations under this Agreement or breach any of its representations and warranties under this Agreement, and, such failure has not been cured within ten (10) days after written notice thereof from Purchaser to such Seller; provided that (i) any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date, and (ii) the breach by Seller any

of its representations and warranties shall not give rise to a right of termination hereunder unless such failures, individually or in the aggregate, result in a Material Adverse Effect.

A Party may not terminate this Agreement under Section 10.1(c) or (d) if such Party purporting to terminate is then in breach in any material respect of any of its representations, warranties, covenants or obligations hereunder.

Section 10.2 Effect of Termination . If this Agreement is terminated pursuant to Section 10.1 , this Agreement shall become void and of no further force or effect and the Parties shall have no liability or obligation hereunder (except for the provisions of Section 4.1 , Section 4.4, Section 5.6 , Section 6.5 , Section 7.5 , Section 11.7 and Section 11.8 of this Agreement and this Article 10 , the Section entitled “Definitions,” and Article 12 (other than Section 12.5 ), all of which shall continue in full force and effect). Notwithstanding the foregoing, nothing contained in this Section 10.2 shall relieve any Party from liability for Losses resulting from its breach of this Agreement. If Seller terminates this Agreement because Purchaser has failed to comply with any provision of Section 8.1(a) , Section 8.1(b) or Section 8.1(d) , then Seller shall be entitled to the Deposit, as its sole and exclusive remedy for Purchaser’s breach and failure to tender performance at Closing, distributed to the Seller by the Escrow Agent as liquidated damages and not a penalty, and Seller hereby waives any other remedies otherwise available at law or in equity. The Parties agree that the distribution of the Deposit as set forth in this Section 10.2 to Seller will be deemed liquidated damages and that the amount of liquidated damages is reasonable considering all of the circumstances existing as of the Execution Date and constitute the Parties’ good faith estimate of the actual damages reasonably expected to result from Seller’s termination of this Agreement. If Purchaser terminates this Agreement with respect to a Seller because Seller has failed to comply with any provision of Section 8.2(a) , Section 8.2(b) or Section 8.2(d) , then Purchaser shall be entitled to, , as Purchaser’s sole and exclusive remedy , either: (A) (1) return of the Deposit, in which event the Parties shall cause the Escrow Agent to distribute the Deposit to Purchaser immediately following termination of this Agreement, and (2) seek to recover its actual, out-of-pocket, damages from Seller available at Law, up to an amount equal to Five Million Dollars ($5,000,000) or (B) not terminate this Agreement and, instead, seek and obtain specific performance to pursue the Closing, without any obligation to post bond or other security, it being understood that liquidated or monetary damages may not be sufficient to compensate Purchaser if Purchaser so determines, as Purchaser’s sole and exclusive remedy.

ARTICLE 11
POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS; DISCLAIMERS AND WAIVERS

Section 11.1 Assumed Seller Obligations . Subject to the indemnification by Seller under Section 11.3 , on the Closing Date, Purchaser shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of Seller, known or unknown, with respect to the Assets, regardless of whether such obligations or liabilities arose prior to, on or after the Effective Time, including obligations to (a) furnish makeup gas according to the terms of applicable gas sales, gathering or transportation contracts, and to satisfy all other gas balancing obligations, if any, (b) pay working interests, royalties, overriding royalties and other interests held in suspense, (c) properly plug and abandon any and all wells, including inactive wells or temporarily abandoned wells, drilled on

the Properties, as required by Law, including all Plugging and Abandonment Obligations, (d) replug any well, wellbore, or previously plugged well on the Properties to the extent required by Governmental Body, (e) dismantle, salvage and remove any equipment, structures, materials, flowlines, and property of whatever kind related to or associated with operations and activities conducted on the Properties, (f) clean up, restore, remediate or otherwise respond to Hazardous Materials on, at or migrating from the premises covered by or related to the Assets in accordance with applicable agreements and Laws, to comply with Laws concerning Hazardous Materials and Environmental Liabilities related to the Assets, and to discharge all other Environmental Liabilities, and (g) perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and related contracts, or as required by applicable Laws, (all of said obligations and liabilities, subject to the exclusions below, herein being referred to as the “Assumed Seller Obligations”); provided, however , that the Assumed Seller Obligations shall not include, and Purchaser shall have no obligation to assume, any obligations or liabilities of Seller to the extent that they are Retained Liabilities.

Section 11.2 Survival and Limitations; Exclusive Remedy .

(a) The representations and warranties contained in Article V of Seller and Article VI of Purchaser (except for the Fundamental Representations) shall terminate one (1) year after the Closing Date. The representations and warranties contained in Section 5.2 , Section 5.3 , Section 5.4 , Section 5.6 , Section 5.8 , Section 6.1 , Section 6.2 , Section 6.3 , and Section 6.5 (collectively, the “Fundamental Representations”) shall survive until the expiration of the applicable statute of limitations period. Upon the termination of a representation or warranty in accordance with the foregoing, such representation or warranty shall have no further force or effect for any purpose under this Agreement. The covenants and other agreements of Seller and Purchaser set forth in this Agreement, to the extent that, by their terms, they are to be performed prior to or on the Closing Date, shall terminate at Closing. The covenants and agreements of Seller and Purchaser set forth in this Agreement, to the extent that, by their terms, they are to be performed in whole or in part after the Closing, shall survive until such covenants and agreements have been fully performed; provided that the Retained Liability described under subsection (e) of the definition thereof (and the indemnity of Seller with respect to such subsection) shall expire on the date that is the eighteen (18) month anniversary of the Closing Date. Upon the termination of a covenant or agreement in accordance with the foregoing, such covenant or agreement shall have no further force or effect for any purpose under this Agreement.

(b) No Party shall have any indemnification obligation pursuant to this Article 11 or otherwise in respect of any representation, warranty, covenant or agreement unless it shall have received from the Party seeking indemnification a written notice (a “Claim Notice”) of the existence of the claim for or in respect of which indemnification in respect of such representation, warranty, covenant or agreement is being sought on or before the expiration of the applicable survival period set forth in Section 11.2(a) . If an Indemnified Party delivers a Claim Notice to an Indemnifying Party before the expiration of the applicable survival period set forth in Section 11.2(a) , then the applicable representation, warranty, covenant or agreement shall survive until, but only for purposes of, the resolution of the matter covered by such Claim Notice.

(c) Seller shall not have any liability for any indemnification under Section 11.3(i) of this Agreement, until and unless (i) the amount of the liability for any individual claim or series of claims arising out of the same or similar set of facts, for which a Claim Notice is delivered by Purchaser exceeds $75,000, and then only to the extent such damage exceeds $75,000 (“Individual Indemnity Threshold”), and (ii) the aggregate amount of the liabilities for all claims for which Claim Notices are delivered by Purchaser exceeds two percent (2%) of the Purchase Price, and then only to the extent such damages exceed two percent (2%) of the Purchase Price (the “Aggregate Indemnity Deductible”); for the avoidance of doubt, claims for which Claim Notices are delivered by Purchaser which do not meet the Individual Indemnity Threshold shall not be included in reaching the Aggregate Indemnity Deductible.

(d) Seller shall never be required to indemnify Purchaser ( AND PURCHASER, FOR ITSELF AND THE OTHER PURCHASER INDEMNIFIED PERSONS, HEREBY WAIVES, RELEASES AND FULLY DISCHARGES SELLER ) for aggregate damages in excess of (A) with respect to the Fundamental Representations and indemnification by Seller pursuant to Section 11.3(i) (solely as it pertains to Fundamental Representations), Section 11.3(ii) and Section 11.3(iii) , one hundred percent (100%) of the Purchase Price, and (B) with respect to all other matters not included within subsection (A), fifteen percent (15%) of the Purchase Price, in each case, REGARDLESS OF FAULT .

(e) The sole and exclusive remedy of Purchaser with respect to the Assets shall be pursuant to the express provisions of this Agreement and any agreement delivered between the Parties at Closing. If the Closing occurs, the sole and exclusive remedy of Purchaser for any and all (a) claims relating to any representations, warranties, covenants and agreements that are contained in this Agreement or in any certificate delivered at Closing, (b) other claims pursuant to or in connection with this Agreement and (c) other claims relating to the Assets and the purchase and sale thereof, shall be any right to indemnification from such claims that is expressly provided in this Article 11, the special warranty contained in the Conveyance and any other right or remedy under an agreement delivered between the Parties at Closing.

Section 11.3 Indemnification by Seller . Subject to the terms, conditions, and limitations of this Article 11 , from and after the Closing, Seller shall indemnify, defend and hold harmless Purchaser and its directors, officers, employees, stockholders, members, agents, consultants, advisors and other representatives (including legal counsel, accountants and financial advisors) and Affiliates and the successors and permitted assigns of this Agreement of Purchaser (collectively, the “Purchaser Indemnified Persons”) from and against any and all Losses asserted against, resulting from, imposed upon, or incurred or suffered by any Purchaser Indemnified Person to the extent resulting from, arising out of or relating to:

(i) any breach of any representation or warranty of Seller contained in this Agreement or in any certificate furnished by or on behalf of Seller in connection with this Agreement REGARDLESS OF FAULT ;

(ii) any breach or nonfulfillment of or failure to perform any covenant or agreement of Seller contained in this Agreement REGARDLESS OF FAULT or in any certificate furnished by or on behalf of Seller in connection with this Agreement; and

(iii) any Retained Liabilities REGARDLESS OF FAULT .

Section 11.4 Indemnification by Purchaser . From and after the Closing, subject to the terms and conditions of this Article 11 , Purchaser shall indemnify, defend and hold harmless Seller and its directors, officers, employees, agents, consultants, stockholders, advisors and other representatives (including legal counsel, accountants and financial advisors), and Seller’s successors, permitted assigns of this Agreement and Affiliates (collectively, the “Seller Indemnified Persons”) from and against any and all Losses, asserted against, resulting from, imposed upon, or incurred or suffered by any Seller Indemnified Person, directly or indirectly, to the extent resulting from, arising out of, or relating to:

(a) any breach of any representation or warranty of Purchaser contained in this Agreement or in any certificate furnished by or on behalf of Purchaser to a Seller in connection with this Agreement REGARDLESS OF FAULT ;

(b) any breach or nonfulfillment of or failure to perform any covenant or agreement of Purchaser contained in this Agreement REGARDLESS OF FAULT or any certificate furnished by or on behalf of Purchaser to a Seller in connection with this Agreement;

(d) the Assumed Seller Obligations REGARDLESS OF FAULT ;

(e) the indemnity obligation set forth in Section 4.4 ;

(f) Environmental Laws, Environmental Defects, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment, or any other environmental condition of the Assets, REGARDLESS OF THE TIME OF OCCURRENCE AND REGARDLESS OF FAULT ; and

Section 11.5 Indemnification Proceedings .

(a) In the event that any claim or demand for which Seller or Purchaser (such Person, an “Indemnifying Party”) may be liable to a Purchaser Indemnified Person under Section 11.3 or to a Seller Indemnified Person under Section 11.4 (an “Indemnified Party”) is asserted against or sought to be collected from an Indemnified Party by a third party (a “Third Party Claim”), the Indemnified Party shall with reasonable promptness notify the Indemnifying Party of such Third Party Claim by delivery of a Claim Notice, provided that the failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11 , except (and solely) to the extent that the Indemnifying Party demonstrates that its defense of such Third Party Claim is actually and materially prejudiced thereby. The Indemnifying Party shall have thirty (30) days from receipt of the Claim Notice from the Indemnified Party (in this Section 11.5 , the “Notice Period”) to notify the Indemnified Party whether or not the Indemnifying Party desires, at the Indemnifying Party’s sole cost and expense, to defend the Indemnified Party against such claim or demand; provided, that the Indemnified Party is hereby authorized prior to and during the Notice Period, and at the cost and expense of the Indemnifying

Party, to file any motion, answer or other pleading that it shall reasonably deem necessary to protect its interests or those of the Indemnifying Party.

(b) The Indemnifying Party shall have the right to assume the defense of such Third Party Claim only if and for so long as the Indemnifying Party (i) notifies the Indemnified Party during the Notice Period that the Indemnifying Party is assuming the defense of such Third Party Claim, (ii) uses counsel of its own choosing that is reasonably satisfactory to the Indemnified Party, and (iii) conducts the defense of such Third Party Claim in an active and diligent manner. If the Indemnifying Party is entitled to, and does, assume the defense of any such Third Party Claim, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof; provided, however , that notwithstanding the foregoing, the Indemnifying Party shall pay the reasonable attorneys’ fees of the Indemnified Party if the Indemnified Party’s counsel shall have advised the Indemnified Party that there is a conflict of interest that could make it inappropriate under applicable standards of professional conduct to have common counsel for the Indemnifying Party and the Indemnified Party it being understood and agreed, however, that the Indemnifying Party shall not be responsible for paying for more than one separate firm of attorneys and one local counsel to represent all of the Indemnified Parties subject to such Third Party Claim.

(c) If the Indemnifying Party elects (and is entitled) to assume the defense of such Third Party Claim, (i) no compromise or settlement thereof or consent to any admission or the entry of any judgment with respect to such Third Party Claim may be effected by the Indemnifying Party without the Indemnified Party’s written consent (which shall not be unreasonably withheld, conditioned or delayed) unless the sole relief provided is monetary damages that are paid in full by the Indemnifying Party (and no injunctive or other equitable relief is imposed upon the Indemnified Party) and there is an unconditional provision whereby each plaintiff or claimant in such Third Party Claim releases the Indemnified Party from all liability with respect thereto and (ii) the Indemnified Party shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which shall not be unreasonably withheld). If the Indemnifying Party elects not to assume the defense of such Third Party Claim (or fails to give notice to the Indemnified Party during the Notice Period or otherwise is not entitled to assume such defense), the Indemnified Party shall be entitled to assume the defense of such Third Party Claim with counsel of its own choice, at the expense and for the account of the Indemnifying Party; provided, however , that the Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of any Indemnifying Party without the prior written consent of such Indemnifying Party, which consent shall not be unreasonably withheld, conditioned or delayed.

(d) Notwithstanding the foregoing, the Indemnifying Party shall not be entitled to control (but shall be entitled to participate at its own expense in the defense of), and the Indemnified Party, shall be entitled to have sole control over, the defense or settlement, compromise, admission, or acknowledgment of any Third Party Claim (i) at the reasonable expense of the Indemnifying Party, as to which the Indemnifying Party fails to assume the defense during the Notice Period after the Indemnified Party gives notice thereof to the Indemnifying Party or (ii) at the reasonable expense of the Indemnifying Party, to the extent the Third Party Claim seeks an order, injunction, or other equitable relief against the Indemnified Party which, if successful, could adversely affect the business, condition (financial or other),

capitalization, assets, liabilities, results of operations or prospects of the Indemnified Party. The Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of the Indemnifying Party without the prior written consent of the Indemnifying Party (which consent shall not be unreasonably withheld, conditioned or delayed).

(e) In any case in which an Indemnified Party seeks indemnification hereunder and no Third Party Claim is involved, the Indemnified Party shall deliver a Claim Notice to the Indemnifying Party within a reasonably prompt period of time after an officer of such Indemnified Party or its Affiliates has obtained knowledge of the Loss giving rise to indemnification hereunder. The failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11 except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively mitigate the resulting Losses and thereby materially prejudices the Indemnifying Party.

Section 11.6 Release . EXCEPT WITH RESPECT TO POST-CLOSING REMEDIATION AGREED TO BY SELLER PURSUANT TO SECTION 4.3 AND PURCHASER’S EXPRESS RIGHTS UNDER THIS AGREEMENT AND ANY DOCUMENT DELIVERED PURSUANT TO HERETO, PURCHASER HEREBY RELEASES, REMISES AND FOREVER DISCHARGES THE SELLER INDEMNIFIED PERSONS FROM ANY AND ALL CLAIMS, KNOWN OR UNKNOWN, WHETHER NOW EXISTING OR ARISING IN THE FUTURE, CONTINGENT OR OTHERWISE, WHICH PURCHASER MIGHT NOW OR SUBSEQUENTLY MAY HAVE AGAINST THE SELLER INDEMNIFIED PERSONS, RELATING DIRECTLY OR INDIRECTLY TO OR ARISING OUT OF OR INCIDENT TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, ENVIRONMENTAL DEFECTS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, INCLUDING, WITHOUT LIMITATION, RIGHTS TO CONTRIBUTION UNDER CERCLA, REGARDLESS OF FAULT .

Section 11.7 Disclaimers .

(a) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, OR IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCE, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO PURCHASER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY OF ITS AFFILIATES) .

(b) EXCEPT AS EXPRESSLY PROVIDED IN THIS AGREEMENT, OR IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCE, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLER OR ANY THIRD PARTIES, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO PURCHASER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, (IX) REDHIBITORY, PATENT OR LATENT DEFECTS, AND FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT PURCHASER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS AND THAT PURCHASER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE, OR (X) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT .

(c) OTHER THAN AS SET FORTH IN SECTION 5.18, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND PURCHASER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION, SUBJECT TO ARTICLE 4 .

Section 11.8 Waiver of Trade Practices Acts .

(a) It is the intention of the Parties that Purchaser’s rights and remedies with respect to this transaction and with respect to all acts or practices of Seller, past, present or future, in connection with this transaction shall be governed by legal principles other than the Texas Deceptive Trade Practices—Consumer Protection Act, Tex. Bus. & Com. Code Ann. § 17.41 et seq . (the “DTPA”). As such, Purchaser hereby waives the applicability of the DTPA to this transaction and any and all duties, rights or remedies that might be imposed by the DTPA, whether such duties, rights and remedies are applied directly by the DTPA itself or indirectly in connection with other statutes. Purchaser acknowledges, represents and warrants that it is purchasing the goods and/or services covered by this Agreement for commercial or business use; that it has assets of $25,000,000 or more according to its most recent financial statement prepared in accordance with GAAP; that it has knowledge and experience in financial and business matters that enable it to evaluate the merits and risks of a transaction such as this; and that it is not in a significantly disparate bargaining position with Seller.

(b) Purchaser expressly recognizes that the price for which Seller has agreed to perform their obligations under this Agreement has been predicated upon the inapplicability of the DTPA and this waiver of the DTPA. Purchaser further recognizes that Seller, in determining to proceed with the entering into this Agreement, have expressly relied on this waiver and the inapplicability of the DTPA.

(c) In addition to the foregoing, and in order to ensure compliance with Texas’ DTPA Section 17.42(c), Purchaser waives all rights it may possess, if any, under the DTPA with the following certification:

WAIVER OF RIGHTS

PURCHASER WAIVES ITS RIGHTS UNDER THE DECEPTIVE TRADE PRACTICES-CONSUMER PROTECTION ACT, SECTION 17.41 ET SEQ., BUSINESS & COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS AND PROTECTIONS. AFTER CONSULTATION WITH AN ATTORNEY OF ITS OWN SELECTION, PURCHASER VOLUNTARILY CONSENTS TO THIS WAIVER .

Section 11.9 Recording . As soon as practicable after Closing, Purchaser shall record the Conveyance in the appropriate counties where the Properties are located and provide Seller with copies of all recorded or approved instruments. The Conveyance in the form attached as Exhibit B is intended to convey all of the Properties being conveyed pursuant to this Agreement. Certain Properties or specific portions of the Properties that are leased from, or require the approval to transfer by, a Governmental Body are conveyed under the Conveyance and also are described and covered under separate assignments made by Seller to Purchaser on officially approved forms, or forms acceptable to such entity, in sufficient multiple originals to satisfy applicable statutory and regulatory requirements. The interests conveyed by such separate assignments are the same, and not in addition to, the interests conveyed in the Conveyance attached as Exhibit B . Further, such assignments shall be deemed to contain all of the exceptions, reservations, rights, titles, power and privileges set forth herein and in the Conveyance as fully and only to the extent as though they were set forth in each such separate assignment.

Section 11.10 Slawson Holdback; Consent Defect Properties .

(a) Schedule A will list (i) each Slawson Well, and (ii) the defect value for such Slawson Well (the “Slawson Defect Value”, which represents a ten percent (10%) loss of interest in such Slawson Well) not being in after payout (“APO”) status pursuant to that that certain Exploration and Development Agreement dated effective as of January 1, 2007, by and between Slawson Exploration Company and Chandler Energy, LLC (predecessor in interest of Seller) (the “Exploration Agreement”).

(b) If on or after the Execution Date and prior to the first anniversary of the Closing Date, as may be extended in accordance with the terms below (“Release Date”), Seller provides documented evidence to Purchaser that reasonably establishes that a Slawson Well is in APO status under the terms of the Exploration Agreement (which evidence shall be to the reasonable satisfaction of Purchaser), then Seller shall be entitled to the Slawson Defect Value set forth on Schedule A for such cured Slawson Well (“Cured Slawson Amount”) and such Slawson Defect Value shall be accounted for in accordance with the procedures set forth in this Section 11.10(b) . If prior to the Release Date, Seller provides documented evidence to Purchaser that reasonably establishes that a Slawson Well, taking into consideration the expected economic life remaining with regard to such Slawson Well and the other wells considered therewith under the Exploration Agreement in determining APO status, then Seller and Purchaser shall negotiate in good faith and attempt to agree upon an amount, which amount may be all or a portion of the Slawson Defect Value, and such agreed upon amount shall be accounted for in accordance with the procedures set forth in this Section 11.10(b) . To the extent that the Parties have disputes relating to the procedures or matters set forth in this Section 11.10(b) , then such dispute shall be resolved in accordance with an arbitration proceeding, comparable to those for title disputes under Section 3.4(k) , but instead of a Title Expert, (i) with respect to any dispute related to the sufficiency of evidence of whether a Slawson Well is in APO status, the arbitrator shall be a title attorney and (ii) with respect to all other disputes relating to this Section 11.10(b), the arbitrator shall be a nationally recognized reservoir engineering firm, each with at least ten (10) years’ experience in oil and gas matters involving properties in the regional area in which the Properties are located, selected by mutual agreement of Purchaser and Seller within fifteen (15) Business Days after written notice is provided from one Party to the other of the desire to initiate such arbitration (and if no arbitrator is selected by such date, then either Party shall have the right to apply to the Houston, Texas office of the American Arbitration Association to select an independent arbitrator meeting these requirements). If upon the first anniversary of the Closing there is any disputed matter then being arbitrated, or a disputed matter for which one Party has provided written notice to the other that it desires to arbitrate the dispute, then the Release Date shall be extended until such dispute is fully resolved, and any remaining Slawson Holdback distributed or paid out in accordance with the terms hereof. Three (3) days prior to Closing (“Initial Slawson Cure Date”), the Slawson Holdback (and therefore the Deposit) shall be reduced by an amount equal to the sum of Cured Slawson Amounts that were established prior to the Initial Slawson Cure Date. On the first of each month during the period after the Closing Date until the Release Date, the Parties shall cause the Escrow Agent to release all Cured Slawson Amounts (excluding those previously released) for any Slawson Well that was established to be APO during the immediately preceding month.

(c) Upon the Release Date, if there remains any Slawson Holdback that is not subject to a Cured Slawson Amount due to be released to Seller, then the remaining Slawson Holdback is released to Purchaser. No later than three (3) Business Days after the Release Date, the Parties shall jointly instruct the Escrow Agent to deliver any such amounts then due and owing to Purchaser pursuant to this Section 11.10(c) .

(d) The Parties acknowledge that, with respect to certain Slawson Wells and/or associated Leases identified on Schedule B (the “Consent Defect Properties”), the assignment or conveyance to Seller (or its Affiliate) of such Consent Defect Properties from the applicable immediate predecessor in title did not include the satisfaction of certain Transfer Requirements imposed by the BLM, the Bureau of Indian Affairs or tribal governing authorities on the assignment of such Consent Defect Properties to Seller (or its Affiliate) (the “Consent Defect Approvals”), including the execution and delivery of state, federal and/or tribal documents and instruments required in connection therewith (the “Consent Transfer Documents”). The Parties acknowledge and agree that, except as provided in this Section 11.10(d) , Purchaser shall not be entitled to assert a Title Defect under Article 3 or the special warranty in the Conveyance to the extent based on the failure of any Consent Defect Approval to have been obtained and/or the failure of any Consent Transfer Document to have been properly prepared, executed and filed or delivered. Until the first anniversary of the Closing, Seller shall use commercially reasonable efforts to receive appropriately executed and acknowledged Consent Transfer Documents from the applicable predecessor(s) in title, and to make (or cause to be made) such filings and deliveries of such Consent Transfer Documents as are necessary to obtain the appropriate Consent Defect Approvals. If by the first anniversary of the Closing, the Consent Defect Approval(s) affecting any Consent Defect Property has not been obtained, then Purchaser shall be entitled to a cash reimbursement from Seller equal to the amount of the Allocated Value of such Consent Defect Property, which shall be payable within fifteen (15) days; provided, however , that there shall be no such reimbursement right of Purchaser for such Consent Defect Property so long as Seller has properly filed or delivered (or caused to be filed or delivered) prior to the first anniversary of the Closing Date, as appropriate, all Consent Transfer Documents, executed only by Seller and the applicable immediate predecessor in title, that would be required to obtain or satisfy such Consent Defect Approval(s). In the event Purchaser exercises the reimbursement right for a Consent Defect Property, Purchaser shall, contemporaneously with the reimbursement payment from Seller to Purchaser, assign such Consent Defect Property to Seller pursuant to an assignment and conveyance document substantially in the form of the Conveyance, free and clear of any liens arising from and after the Closing. Without limiting the foregoing, the Parties shall otherwise cooperate in good faith in an attempt to satisfy all such Consent Defect Approvals, and to execute, file and/or deliver at the appropriate time such other transfer documents of Governmental Bodies (or tribal governing authorities) as are necessary to vest record title to the Consent Defect Properties into Purchaser.

ARTICLE 12
MISCELLANEOUS

Section 12.1 Counterparts . This Agreement may be executed and delivered (including by facsimile or email transmission) in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.

Section 12.2 Notice . All notices which are required or may be given pursuant to this Agreement shall be sufficient in all respects if given in writing and delivered personally, by overnight courier service, by electronic mail, or by registered or certified mail, postage prepaid, as follows:

If to Seller:		c/o Halcón Resources Corporation 1000 Louisiana, Suite 6700 Houston, Texas 77002 Attention: Steve Herod Phone: 832-538-0506 E-mail: sherod@halconresources.com and c/o Halcón Resources Corporation 1000 Louisiana, Suite 6700 Houston, Texas 77002 Attention: David Elkouri Phone: 832-538-0514 E-mail: delkouri@halconresources.com

If to Purchaser:		Riverbend Oil & Gas VI, LLC One Allen Center 500 Dallas Street, Suite 1250 Houston, Texas 77002 Attention: Colin Barnett Phone: 713-874-9000, Ext. 226 Email: cbarnett@rboil.com

With a copy to (which shall not constitute Notice to Purchaser):		DLA Piper LLP (US) 1000 Louisiana Street, Suite 2800 Houston, Texas 77002 Attention: Steven Torello Phone: 713-425-8421 Email: steven.torello@dlapiper.com

Each Party may change its address for notice by notice to the other in the manner set forth above. All notices shall be deemed to have been duly given at the time of receipt by the Party to which such notice is addressed.

Section 12.3 Sales or Use Tax Recording Fees and Similar Taxes and Fees . Purchaser shall bear any sales, use, excise, real property transfer, gross receipts, goods and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees (collectively “Transfer Taxes”) incurred and imposed upon, or with respect to, the transactions contemplated by this Agreement and hold Seller harmless with respect to same.

Section 12.4 Expenses . Except as otherwise expressly provided in Section 12.3 or elsewhere in this Agreement, (a) all expenses incurred by Seller in connection with or related to the authorization, preparation or execution of this Agreement, the Conveyance delivered hereunder and the Exhibits and Schedules hereto and thereto, and all other matters related to the Closing, all fees and expenses of counsel, accountants and financial advisers employed by Seller, shall be borne solely and entirely by Seller, and (b) all such expenses incurred by Purchaser and all other fees and expenses relating to the registration of title to the Assets after Closing shall be borne solely and entirely by Purchaser.

Section 12.5 Replacement of Bonds, Letters of Credit and Guarantees . The Parties understand that none of the bonds, letters of credit and guarantees, if any, posted by Seller or any of its Affiliates with Governmental Bodies and relating to the Assets may be transferable to Purchaser. Prior to Closing, Purchaser shall have obtained, or caused to be obtained in the name of Purchaser, replacements for such bonds, letters of credit and guarantees, to the extent such replacements are necessary to permit the cancellation of the bonds, letters of credit and guarantees posted by Seller or any of its Affiliates or to consummate the transactions contemplated by this Agreement.

Section 12.6 Governing Law and Venue . THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS OTHERWISE APPLICABLE TO SUCH DETERMINATIONS. JURISDICTION AND VENUE WITH RESPECT TO ANY DISPUTES ARISING HEREUNDER (EXCEPT FOR DISPUTES REQUIRED HEREUNDER TO BE DETERMINED SOLELY BY ARBITRATION OR OTHER ALTERNATIVE DISPUTE RESOLUTION) SHALL BE PROPER ONLY IN HARRIS COUNTY, TEXAS.

Section 12.7 Captions . The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

Section 12.8 Waivers . Any failure by any Party or Parties to comply with any of its or their obligations, agreements or conditions herein contained may be waived in writing, but not in any other manner, by the Party or Parties to whom such compliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 12.9 Assignment . Subject to the provisions of Section 7.8(c) , no Party shall assign all or any part of this Agreement, nor shall any Party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other Party, which shall not be unreasonably withheld, conditioned or delayed. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. Notwithstanding the forgoing, at Closing, Purchaser may instruct Seller to deliver separate Conveyances of the state, federal or tribal leases included in the Leases to a wholly-owned

subsidiary of Purchaser, as well as the related documents contemplated to be delivered at Closing including under Sections 9.2(b) and 9.2(c) .

Section 12.10 Entire Agreement . The Confidentiality Agreement, this Agreement and the Exhibits and Schedules attached hereto, and the documents to be executed hereunder constitute the entire agreement between the Parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof.

Section 12.11 Amendment .

(a) This Agreement may be amended or modified only by an agreement in writing executed by the Parties.

(b) No waiver of any right under this Agreement shall be binding unless executed in writing by the Party to be bound thereby.

Section 12.12 No Third-Party Beneficiaries . Nothing in this Agreement shall entitle any Person other than Purchaser or Seller to any claims, remedy or right of any kind, except as to those rights expressly provided to the Seller Indemnified Persons and Purchaser Indemnified Persons ( provided , however , any claim for indemnity hereunder on behalf of an Seller Indemnified Person or an Purchaser Indemnified Person must be made and administered by a Party).

Section 12.13 References . In this Agreement:

(a) References to any gender includes a reference to all other genders;

(b) References to the singular includes the plural, and vice versa;

(d) Reference to any Exhibit or Schedule means an Exhibit or Schedule to this Agreement, all of which are incorporated into and made a part of this Agreement;

(e) Unless expressly provided to the contrary, “hereunder”, “hereof”, “herein” and words of similar import are references to this Agreement as a whole and not any particular Section or other provision of this Agreement;

(f) “for example,” “include” and “including” mean without limitation;

(g) “or” means and includes “and/or”; and

(h) Capitalized terms used herein shall have the meanings ascribed to them in this Agreement as such terms are identified and/or defined in the Definitions section hereof, which Definitions section is incorporated herein by reference and made a part hereof.

Section 12.14 Construction . Purchaser is a party capable of making such investigation, inspection, review and evaluation of the Assets as a prudent party would deem appropriate under the circumstances including with respect to all matters relating to the Assets, their value, operation and suitability. Seller and Purchaser have each had substantial input into the drafting and preparation of this Agreement and has had the opportunity to exercise business discretion in relation to the negotiation of the details of the transactions contemplated hereby. This Agreement is the result of arm’s-length negotiations from equal bargaining positions. In the event of a dispute over the meaning or application of this Agreement, it shall be construed fairly and reasonably and neither more strongly for nor against either Party.

Section 12.15 Conspicuousness . The Parties agree that provisions in this Agreement in “bold” and/or “ALL CAPS” type satisfy any requirements of the “express negligence rule” and any other requirements at law or in equity that provisions be conspicuously marked or highlighted.

Section 12.16 Severability . If any term or other provisions of this Agreement is held invalid, illegal or incapable of being enforced under any rule of law, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in a materially adverse manner with respect to either Party; provided, however , that if any such term or provision may be made enforceable by limitation thereof, then such term or provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by applicable Law.

Section 12.17 Time of Essence . Time is of the essence in this Agreement. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

Section 12.18 Limitation on Damages . NOTWITHSTANDING ANY OTHER PROVISION CONTAINED ELSEWHERE IN THIS AGREEMENT TO THE CONTRARY, THE PARTIES ACKNOWLEDGE THAT THIS AGREEMENT DOES NOT AUTHORIZE ONE PARTY TO SUE FOR OR COLLECT FROM THE OTHER PARTY ITS OWN PUNITIVE DAMAGES, OR ITS OWN CONSEQUENTIAL OR INDIRECT DAMAGES IN CONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY AND EACH PARTY EXPRESSLY WAIVES FOR ITSELF AND ON BEHALF OF ITS AFFILIATES, ANY AND ALL CLAIMS IT MAY HAVE AGAINST THE OTHER PARTY FOR ITS OWN SUCH DAMAGES IN CONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY, REGARDLESS OF FAULT (AS SUCH TERM IS DEFINED IN THIS AGREEMENT); PROVIDED, HOWEVER , THE FOREGOING SHALL NOT BE CONSTRUED AS LIMITING AN OBLIGATION OF A PARTY TO INDEMNIFY, DEFEND AND HOLD HARMLESS THE OTHER PARTY AGAINST CLAIMS ASSERTED BY THIRD PARTIES, INCLUDING, BUT NOT LIMITED TO, PUNITIVE DAMAGES, CONSEQUENTIAL OR INDIRECT DAMAGES.

[SIGNATURES BEGIN ON THE FOLLOWING PAGE]

IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties as of the date first above written.

SELLER :

HALCÓN ENERGY PROPERTIES, INC.

HALCÓN OPERATING CO., INC.

HALCÓN HOLDINGS, INC.

HRC ENERGY, LLC

By:	/s/ Steve W. Herod
Name:	Steve W. Herod
Title:	EVP, Corporate Development

SIGNATURE PAGE

AGREEMENT OF SALE AND PURCHASE

PURCHASER :

RIVERBEND OIL AND GAS VI, LLC

By:	/s/ Randy Newcomer Jr.
Name:	Randy Newcomer Jr.
Title:	President

SIGNATURE PAGE

AGREEMENT OF SALE AND PURCHASE

Exhibit 4.1.2

SECOND SUPPLEMENTAL INDENTURE

THIS SECOND SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of October 9, 2017, and effective as of September 7, 2017 for all purposes (the “ Effective Date ”), is by and among Halcón Resources Corporation, a Delaware corporation (the “ Company ”), the guarantors party thereto (the “ Guarantors ”) and U.S. Bank National Association, as trustee (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company and the Guarantors have heretofore executed and delivered to the Trustee the Indenture, dated as of February 16, 2017, among the Company, the Guarantors and the Trustee, as supplemented by the First Supplemental Indenture, dated as of July 24, 2017 (as so amended, supplemented, modified or restated, the “ Indenture ”), relating to the 6.75% Senior Notes due 2025 (the “ Securities ”) of the Company;

WHEREAS, pursuant to Section 9.1 of the Indenture, the Company and the Trustee are authorized to execute and deliver this Supplemental Indenture without the consent of any Holder;

WHEREAS, Section 10.9(b)(2) of the Indenture provides that a Subsidiary Guarantee of a Guarantor shall be automatically unconditionally released in connection with any sale or other disposition of the Capital Stock of a Guarantor (including by way of merger or consolidation) other than to the Company or a Restricted Subsidiary of the Company, if such transaction as of the time of such disposition complies with Section 4.7 of the Indenture and the Guarantor ceases to be a Restricted Subsidiary of the Company as a result of such transaction;

WHEREAS, in accordance with that certain Agreement of Sale and Purchase, dated July 10, 2017 (as amended from time to time, the “ Purchase Agreement ”), by and among Halcón Energy Properties, Inc., a Delaware corporation (“ HEPI ”), Halcón Operating Co., Inc., a Texas corporation (“ HOCI ”), HRC Operating, LLC, a Colorado limited liability company (“ HRC Operating ”), and HRC Energy, LLC, a Colorado limited liability company (“ HRC Energy ,” and together with HEPI, HOCI and HRC Operating, the “ Sellers ,” and each individually, a “ Seller ”), Halcón Williston I, LLC, a Texas limited liability company (“ Williston I ”), Halcón Williston II, LLC, a Texas limited liability company (“ Williston II ,” and collectively with Williston I, the “ Williston Subsidiaries ”), and Bruin Williston Holdings, LLC, a Delaware limited liability company (“ Purchaser ”) and solely for purposes of Section 7.11, Section 7.15, Section 7.16, Section 7.17 and Section 12.21 of the Purchase Agreement, the Company, all of the issued and outstanding membership interests held by HEPI in its capacity as the sole member of each of the Williston Subsidiaries were acquired by Purchaser, effective as of September 7, 2017;

WHEREAS, the Company and the Guarantors desire to enter into, and have requested the Trustee to join with them in entering into, this Supplemental Indenture for the purpose of amending the Indenture to evidence the release of the Williston Subsidiaries; and

WHEREAS, the Company has delivered to the Trustee an Officers’ Certificate and Opinion of Counsel relating to this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Company, the Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Securities as follows:

1. CAPITALIZED TERMS . Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. RELEASE OF SUBSIDIARY GUARANTORS . The Company hereby represents that in accordance with the Purchase Agreement, effective as of the Effective Date, each of the Williston Subsidiaries ceased to be a Restricted Subsidiary of the Company. Therefore, the Company, the Guarantors and the Trustee hereby confirm that pursuant to this Section 2 of this Supplemental Indenture, effective as of the Effective Date, each of the Williston Subsidiaries is released and relieved of any obligations under its Subsidiary Guarantee and the Indenture.

3. NEW YORK LAW TO GOVERN . THE LAWS OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS SUPPLEMENTAL INDENTURE.

4. COUNTERPARTS . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement. This Supplemental Indenture may be executed in multiple counterparts which, when taken together, shall constitute one instrument.

5. EFFECT OF HEADINGS . The section headings herein are for convenience only and shall not affect the construction hereof.

6. THE TRUSTEE . The recitals contained herein shall be taken as the statements of the Company, and the Trustee assumes no responsibility for the correctness of the same. The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture and shall not be liable in connection therewith. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

[Signature pages follow]

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the date first above written to be effective for all purposes as of the Effective Date.

HALCÓN RESOURCES CORPORATION

By:	/s/ Mark J. Mize
	Name:	Mark J. Mize
	Title:	Executive Vice President, Chief Financial Officer and Treasurer


GUARANTORS:

HALCÓN ENERGY PROPERTIES, INC.
HALCÓN FIELD SERVICES, LLC
HALCÓN HOLDINGS, INC.
HALCÓN OPERATING CO., INC.
HALCÓN RESOURCES OPERATING, INC.
HALCÓN LOUISIANA OPERATING, L.P.
	By:	HALCÓN GULF STATES, LLC ,
		its General Partner
HALCÓN GULF STATES, LLC
HRC ENERGY LOUISIANA, LLC
HRC ENERGY, LLC
HRC OPERATING, LLC
HRC ENERGY RESOURCES (WV), INC.
HALCÓN ENERGY HOLDINGS, LLC
HRC PRODUCTION COMPANY
HK OIL & GAS, LLC
HK ENERGY OPERATING, LLC
HK LOUISIANA OPERATING, LLC
HK ENERGY, LLC
HK RESOURCES, LLC
THE 7711 CORPORATION
HALCÓN PERMIAN, LLC

By:	/s/ Mark J. Mize
	Name:	Mark J. Mize
	Title:	Executive Vice President, Chief Financial Officer and Treasurer

[ Signature Page to 6.75% Second Supplemental Indenture ]

U.S. BANK NATIONAL ASSOCIATION ,
as Trustee


By:	/s/ Paula Oswald
	Name:	Paula Oswald
	Title:	Vice President

[ Signature Page to 6.75% Second Supplemental Indenture ]

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Exhibit 12.1

Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
(In thousands, except ratios)

	Successor						Predecessor			Successor			Predecessor

				Period from September 10, 2016 through September 30, 2016			Period from January 1, 2016 through September 9, 2016			Period from September 10, 2016 through December 31, 2016			Period from January 1, 2016 through September 9, 2016
	Nine Months Ended September 30, 2017															Year Ended December 31,
	Nine Months Ended September 30, 2017															2015			2014			2013			2012
Earnings:
Income (loss) before income taxes	$	623,816		$	(447,335	)	$	3,292		$	(474,449	)	$	3,292		$	(1,913,535	)	$	314,880		$	(1,380,378	)	$	(67,066	)
Adjustments:
Equity investment loss (income)		(417	)		—			152			(9	)		152			171			(617	)		(97	)		(373	)
Interest capitalized		—			—			(68,192	)		—			(68,192	)		(113,009	)		(168,897	)		(203,993	)		(53,492	)

Income (loss) before income taxes, as adjusted	$	623,399		$	(447,335	)	$	(64,748	)	$	(474,458	)	$	(64,748	)	$	(2,026,373	)	$	145,366		$	(1,584,468	)	$	(120,931	)
Fixed charges		67,421			5,552			197,640			29,013			197,640			340,399			320,403			262,046			86,589

Total earnings	$	690,820		$	(441,783	)	$	132,892		$	(445,445	)	$	132,892		$	(1,685,974	)	$	465,769		$	(1,322,422	)	$	(34,342	)



Fixed charges:
Interest expense and amortization of finance costs	$	66,447		$	5,428		$	195,698		$	28,553		$	195,698		$	337,554		$	317,732		$	259,159		$	85,372
Rental expense representative of interest factor		974			124			1,942			460			1,942			2,845			2,671			2,887			1,217

Total fixed charges	$	67,421		$	5,552		$	197,640		$	29,013		$	197,640		$	340,399		$	320,403		$	262,046		$	86,589



Ratio of earnings to fixed charges		10.2			—	(1)		—	(3)		—	(5)		—	(3)		—	(7)		1.5			—	(9)		—	(10)



Total fixed charges	$	67,421		$	5,552		$	197,640		$	29,013		$	197,640		$	340,399		$	320,403		$	262,046		$	86,589
Pre-tax preferred dividend requirements		47,625			785			12,320			783			12,320			83,942			32,902			12,132			110,075

Total fixed charges plus preference dividends	$	115,046		$	6,337		$	209,960		$	29,796		$	209,960		$	424,341		$	353,305		$	274,178		$	196,664



Ratio of earnings to combined fixed charges and preference dividends		6.0			—	(2)		—	(4)		—	(6)		—	(4)		—	(8)		1.3			—	(9)		—	(11)

(1): Due to the Company's "Loss before income taxes, as adjusted" for the period from September 10, 2016 through September 30, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $447.3 million to achieve a coverage ratio of 1:1.
(2): Due to the Company's "Loss before income taxes, as adjusted" for the period from September 10, 2016 through September 30, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $448.1 million to achieve a coverage ratio of 1:1.
(3): Due to the Company's "Loss before income taxes, as adjusted" for the period from January 1, 2016 through September 9, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $64.7 million to achieve a coverage ratio of 1:1.
(4): Due to the Company's "Loss before income taxes, as adjusted" for the period from January 1, 2016 through September 9, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $77.1 million to achieve a coverage ratio of 1:1.
(5): Due to the Company's "Loss before income taxes, as adjusted" for the period from September 10, 2016 through December 31, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $474.5 million to achieve a coverage ratio of 1:1.
(6): Due to the Company's "Loss before income taxes, as adjusted" for the period from September 10, 2016 through December 31, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $475.2 million to achieve a coverage ratio of 1:1.
(7): Due to the Company's "Loss before income taxes, as adjusted" for the year ended December 31, 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $2.0 billion to achieve a coverage ratio of 1:1.
(8): Due to the Company's "Loss before income taxes, as adjusted" for the year ended December 31, 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $2.1 billion to achieve a coverage ratio of 1:1.
(9): Due to the Company's "Loss before income taxes, as adjusted" for the year ended December 31, 2013, the ratio coverage was less than 1:1. The Company must generate additional earnings of $1.6 billion to achieve a coverage ratio of 1:1.
(10): Due to the Company's "Loss before income taxes, as adjusted" for the year ended December 31, 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $120.9 million to achieve a coverage ratio of 1:1.
(11): Due to the Company's "Loss before income taxes, as adjusted" for the year ended December 31, 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $231.0 million to achieve a coverage ratio of 1:1.

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Exhibit 12.1

Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends (In thousands, except ratios)

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Exhibit 31.1

CERTIFICATIONS FOR FORM 10-Q

I, Floyd C. Wilson, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Halcón Resources Corporation;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a): Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b): Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c): Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
(d): Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a): All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b): Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

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Exhibit 31.1

CERTIFICATIONS FOR FORM 10-Q

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Exhibit 31.2

CERTIFICATIONS FOR FORM 10-Q

I, Mark J. Mize, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Halcón Resources Corporation;

2.

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

(a): Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b): Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c): Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
(d): Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

(a): All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b): Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

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Exhibit 31.2

CERTIFICATIONS FOR FORM 10-Q

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Exhibit 32

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), Floyd C. Wilson, Chairman of the Board, Chief Executive Officer and President, and Mark J. Mize, Executive Vice President, Chief Financial Officer and Treasurer, of Halcón Resources Corporation (the "Company"), each hereby certifies that, to the best of his knowledge:

(1): The Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2): The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


November 9, 2017		/s/ FLOYD C. WILSON Floyd C. Wilson Chairman of the Board, Chief Executive Officer and President
November 9, 2017		/s/ MARK J. MIZE Mark J. Mize Executive Vice President, Chief Financial Officer and Treasurer

This certification accompanies this Form 10-Q and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that Section.

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

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Exhibit 32

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)