10-Q

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TABLE OF CONTENTS

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 March 31, 2014
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                  to

Commission File Number: 001-35467

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

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

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

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

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

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

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

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

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

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

        At May 5, 2014, 420,476,893 shares of the Registrant's Common Stock were outstanding.

TABLE OF CONTENTS

		Page
PART I—FINANCIAL INFORMATION
ITEM 1.	Condensed Consolidated Financial Statements (Unaudited)		5
	Condensed Consolidated Statements of Operations (Unaudited) for the Three Months Ended March 31, 2014 and 2013		5
	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2014 and December 31, 2013		6
	Condensed Consolidated Statements of Stockholders' Equity (Unaudited) for the Three Months Ended March 31, 2014 and Year Ended December 31, 2013		7
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 2014 and 2013		8
	Notes to Unaudited Condensed Consolidated Financial Statements		9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		35
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		43
ITEM 4.	Controls and Procedures		44
PART II—OTHER INFORMATION
ITEM 1.	Legal Proceedings		45
ITEM 1A.	Risk Factors		45
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		47
ITEM 3.	Defaults Upon Senior Securities		47
ITEM 4.	Mine Safety Disclosures		47
ITEM 5.	Other Information		47
ITEM 6.	Exhibits		48
Signatures			52

2

Special note regarding forward-looking statements

        This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2013, and 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:

•

our ability to successfully integrate acquired oil and natural gas businesses and operations;

•

the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and will divert management's time and energy, which could have an adverse effect on our financial position, results of operations, or cash flows;

•

risks in connection with potential acquisitions and the integration of significant acquisitions;

•

we have substantial indebtedness and may incur more debt; higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;

•

our ability to successfully develop our large inventory of undeveloped acreage in our resource plays;

•

access to and availability of water and other treatment materials to carry out planned fracture stimulations in our resource plays;

•

access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices, which is necessary to fully execute our capital program;

•

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and fully develop our undeveloped acreage positions;

•

volatility in commodity prices for oil and natural gas;

•

our ability to replace our oil and natural gas reserves;

•

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

•

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;

•

our ability to retain key members of senior management and key technical employees;

3

•

competition, including competition for acreage in resource play holdings;

•

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, state and tribal 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 may be sustained in connection with our business activities;

•

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.

4

PART I. FINANCIAL INFORMATION

Item 1.    Condensed Consolidated Financial Statements (Unaudited)

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended March 31,
	2014			2013
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	256,029		$	180,827
Natural gas		9,409			5,669
Natural gas liquids		8,759			3,828
Total oil, natural gas and natural gas liquids sales		274,197			190,324
Other		952			530
Total operating revenues		275,149			190,854
Operating expenses:
Production:
Lease operating		36,638			25,304
Workover and other		2,789			1,624
Taxes other than income		24,160			17,436
Gathering and other		5,073			333
Restructuring		987			671
General and administrative		32,798			31,597
Depletion, depreciation and accretion		119,908			81,858
Full cost ceiling impairment		61,165			—
Total operating expenses		283,518			158,823
Income (loss) from operations		(8,369	)		32,031
Other income (expenses):
Net gain (loss) on derivative contracts		(33,656	)		(18,422	)
Interest expense and other, net		(30,939	)		(4,850	)
Total other income (expenses)		(64,595	)		(23,272	)
Income (loss) before income taxes		(72,964	)		8,759
Income tax benefit (provision)		—			(3,294	)
Net income (loss)		(72,964	)		5,465
Series A preferred dividends		(4,959	)		—
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465
Net income (loss) per share of common stock:
Basic	$	(0.19	)	$	0.02
Diluted	$	(0.19	)	$	0.01
Weighted average common shares outstanding:
Basic		413,521			346,139
Diluted		413,521			383,565

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

5

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	March 31, 2014			December 31, 2013
Current assets:
Cash	$	366		$	2,834
Accounts receivable		309,304			312,518
Receivables from derivative contracts		1,214			2,028
Inventory		4,868			5,148
Prepaids and other		11,436			16,098
Total current assets		327,188			338,626
Oil and natural gas properties (full cost method):
Evaluated		5,382,235			4,960,467
Unevaluated		2,110,612			2,028,044
Gross oil and natural gas properties		7,492,847			6,988,511
Less—accumulated depletion		(2,367,926	)		(2,189,515	)
Net oil and natural gas properties		5,124,921			4,798,996
Other operating property and equipment:
Gas gathering and other operating assets		137,849			125,837
Less—accumulated depreciation		(10,441	)		(8,461	)
Net other operating property and equipment		127,408			117,376
Other noncurrent assets:
Receivables from derivative contracts		14,243			22,734
Debt issuance costs, net		62,350			64,308
Deferred income taxes		4,505			8,474
Equity in oil and natural gas partnership		5,294			4,463
Funds in escrow and other		10,225			1,514
Total assets	$	5,676,134		$	5,356,491
Current liabilities:
Accounts payable and accrued liabilities	$	652,203		$	636,589
Liabilities from derivative contracts		32,890			17,859
Asset retirement obligations		141			71
Current portion of deferred income taxes		4,505			8,474
Current portion of long-term debt		1,389			1,389
Total current liabilities		691,128			664,382
Long-term debt		3,533,193			3,183,823
Other noncurrent liabilities:
Liabilities from derivative contracts		21,018			19,333
Asset retirement obligations		38,834			39,186
Other		11,157			2,157
Commitments and contingencies (Note 8)
Stockholders' equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 345,000 shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding as of March 31, 2014 and December 31, 2013		—			—
Common stock: 670,000,000 shares of $0.0001 par value authorized; 420,521,463 and 415,729,962 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively		41			41
Additional paid-in capital		2,964,903			2,953,786
Accumulated deficit		(1,584,140	)		(1,506,217	)
Total stockholders' equity		1,380,804			1,447,610
Total liabilities and stockholders' equity	$	5,676,134		$	5,356,491

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

6

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)

(In thousands)

	Preferred Stock				Common Stock								Treasury Stock
										Additional Paid-In Capital									Accumulated Deficit			Stockholders' Equity
	Shares		Amount		Shares			Amount					Shares			Amount
Balances at December 31, 2012		—	$	—		259,802		$	26	$	1,681,717			1,650		$	(9,298	)	$	(274,463	)	$	1,397,982
Net income (loss)		—		—		—			—		—			—			—			(1,222,662	)		(1,222,662	)
Dividends on Series A preferred stock		—		—		2,045			—		9,092			—			—			(9,092	)		—
Preferred stock conversion		—		—		108,801			11		695,227			—			—			—			695,238
Sale of Series A preferred stock		345		—		—			—		345,000			—			—			—			345,000
Common stock issuance		—		—		43,700			4		222,866			—			—			—			222,870
Offering costs		—		—		—			—		(17,346	)		—			—			—			(17,346	)
Long-term incentive plan grants		—		—		3,267			—		—			—			—			—			—
Long-term incentive plan forfeitures		—		—		(205	)		—		—			—			—			—			—
Reduction in shares to cover individuals' tax withholding		—		—		(30	)		—		(148	)		—			—			—			(148	)
Retirement of shares in treasury		—		—		(442	)		—		(2,492	)		(442	)		2,492			—			—
Long-term incentive plan grants issued out of treasury		—		—		(1,208	)		—		(6,806	)		(1,208	)		6,806			—			—
Share-based compensation		—		—		—			—		26,676			—			—			—			26,676
Balances at December 31, 2013		345	$	—		415,730		$	41	$	2,953,786			—		$	—		$	(1,506,217	)	$	1,447,610
Net income (loss)		—		—		—			—		—			—			—			(72,964	)		(72,964	)
Dividends on Series A preferred stock		—		—		1,394			—		4,959			—			—			(4,959	)		—
Offering costs		—		—		—			—		45			—			—			—			45
Long-term incentive plan grants		—		—		3,568			—		—			—			—			—			—
Long-term incentive plan forfeitures		—		—		(68	)		—		—			—			—			—			—
Reduction in shares to cover individuals' tax withholding		—		—		(103	)		—		(389	)		—			—			—			(389	)
Share-based compensation		—		—		—			—		6,502			—			—			—			6,502
Balances at March 31, 2014		345	$	—		420,521		$	41	$	2,964,903			—		$	—		$	(1,584,140	)	$	1,380,804

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

7

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net income (loss)	$	(72,964	)	$	5,465
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		119,908			81,858
Full cost ceiling impairment		61,165			—
Deferred income tax provision (benefit)		—			(999	)
Share-based compensation, net		4,332			2,335
Unrealized loss (gain) on derivative contracts		26,021			16,071
Amortization and write-off of deferred loan costs		842			265
Non-cash interest and amortization of discount and premium		554			866
Other income (expense)		354			(1,013	)
Change in assets and liabilities, net of acquisitions:
Accounts receivable		12,062			(50,746	)
Inventory		280			(1,033	)
Prepaids and other		4,662			3,924
Accounts payable and accrued liabilities		2,284			(11,283	)
Net cash provided by (used in) operating activities		159,500			45,710
Cash flows from investing activities:
Oil and natural gas capital expenditures		(432,783	)		(380,117	)
Acquisition of Williston Basin Assets		—			(29,895	)
Other operating property and equipment capital expenditures		(16,036	)		(36,340	)
Advance on carried interest		(62,500	)		—
Funds held in escrow and other		1,821			1,328
Net cash provided by (used in) investing activities		(509,498	)		(445,024	)
Cash flows from financing activities:
Proceeds from borrowings		614,000			844,000
Repayments of borrowings		(266,000	)		(434,476	)
Debt issuance costs		(126	)		(11,483	)
Offering costs and other		(344	)		(431	)
Net cash provided by (used in) financing activities		347,530			397,610
Net increase (decrease) in cash		(2,468	)		(1,704	)
Cash at beginning of period		2,834			2,506
Cash at end of period	$	366		$	802
Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	$	(4,763	)	$	9,569
Asset retirement obligations		(730	)		1,512
Series A preferred dividends paid in common stock		4,959			—

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

8

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 assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries and an equity method investment. 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 2013 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC). Please refer to the notes in the 2013 Annual Report on Form 10-K when reviewing interim financial results.

        During the year ended 2013, the Company determined that "Net cash provided by operating activities" and "Net cash used in investing activities" for the three month period ended March 31, 2013 were both overstated by $9.6 million as a result of the inclusion of capitalized non-cash interest in the change in "Accounts payable and accrued liabilities" line item in operating cash flows and "Oil and natural gas capital expenditures" and "Other operating property and equipment capital expenditures" in investing cash flows. The Company has corrected the error, which had no impact to the net cash flows for the period, and provided related supplemental non-cash information in the accompanying unaudited condensed consolidated statements of cash flows for the three month period ended March 31, 2013.

Use of Estimates

        The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived 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

9

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 allowances for doubtful accounts as of March 31, 2014 or December 31, 2013.

Other Operating Property and Equipment

        Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year estimated useful life. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company capitalized $101.2 million and $92.0 million as of March 31, 2014 and December 31, 2013, respectively, related to the construction of its gas gathering systems.

        Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years; trailers, seven years; heavy equipment, ten years; an airplane and 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.

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

Recently Issued Accounting Pronouncements

        In February 2013, the FASB issued ASU No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU 2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of

10

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

obligations resulting from joint and several liability arrangements, such as debt arrangements, other contractual obligations and settled litigation and judicial rulings. This pronouncement must be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of ASU 2013-04 did not have an impact to the Company's operating results, financial position and disclosures.

        In February 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU 2013-11). ASU 2013-11 provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This pronouncement should be applied prospectively to all unrecognized tax benefits that exist at the effective date and retrospective application is permitted. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this pronouncement did not have an impact to the Company's operating results and financial position.

2. ACQUISITIONS AND DIVESTITURES

Divestitures

Non-core Properties

        During the third quarter of 2013, the Company entered into three separate purchase and sale agreements with unrelated parties to divest parcels of non-core properties located in the United States for total consideration of approximately $302.0 million, all of which closed by December 31, 2013. The transactions and consideration are subject to customary closing conditions and adjustments, with an effective date of July 1, 2013. Proceeds from the sales were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

Eagle Ford Assets

        On July 19, 2013, the Company completed the sale of its interest in Eagle Ford assets located in Fayette and Gonzales Counties, Texas, previously acquired as part of the merger with GeoResources, Inc. (the Merger), to private buyers for proceeds of approximately $147.9 million, before post-closing adjustments. The transaction had an effective date of January 1, 2013. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

3. 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.

11

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. OIL AND NATURAL GAS PROPERTIES (Continued)

        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 capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that are excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the unaudited condensed consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. For the three months ended March 31, 2014 and 2013, the Company capitalized interest costs of $46.6 million and $52.2 million, respectively.

        At March 31, 2014, 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 March 31, 2014 of the West Texas Intermediate (WTI) spot price of $98.46 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 March 31, 2014 of the Henry Hub price of $3.99 per million British thermal units (MMBtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at March 31, 2014 exceeded the ceiling amount by $61.2 million ($39.0 million after taxes) which resulted in a ceiling test impairment of that amount for the quarter. The Company recorded the full cost ceiling test impairment in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

        At March 31, 2013, the ceiling test value of the Company's reserves was calculated based on the first day average of the 12-months ended March 31, 2013 of the WTI spot price of $92.63 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended March 31, 2013 of the Henry Hub price of $2.95 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 March 31, 2013 did not exceed the ceiling amount.

12

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT

        Long-term debt as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014(1)		December 31, 2013(1)
	(In thousands)
Senior revolving credit facility	$	348,000	$	—
9.25% senior notes due 2022		400,000		400,000
8.875% senior notes due 2021(2)		1,371,791		1,372,355
9.75% senior notes due 2020(3)		1,152,029		1,152,099
8.0% convertible note due 2017(4)		261,373		259,369
	$	3,533,193	$	3,183,823

⁽¹⁾

Table excludes $1.4 million of deferred premiums on derivative contracts which were classified as current at March 31, 2014 and December 31, 2013.

⁽²⁾

Amounts are net of a $5.0 million and a $5.1 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $26.8 million and $27.5 million at March 31, 2014 and December 31, 2013, respectively. See "8.875% Senior Notes" below for more details.

⁽³⁾

Amounts are net of a $8.6 million and a $8.9 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2020 Notes. On December 19, 2013, the Company completed the issuance of an additional $400 million principal amount of these notes. The unamortized premium related to these additional 2020 Notes was approximately $10.6 million and $11.0 million at March 31, 2014 and December 31, 2013, respectively. See "9.75% Senior Notes" below for more details.

⁽⁴⁾

Amount is net of a $28.3 million and a $30.3 million unamortized discount at March 31, 2014 and December 31, 2013, respectively. See "8.0% Convertible Note" below for more details.

Senior Revolving Credit Facility

        On February 8, 2012, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Senior Credit Agreement provides for a $1.5 billion facility with a current borrowing base of $800.0 million. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that the Company may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the five-year

13

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

term of the facility. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on the Company's capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses of i) not less than 2.0 to 1.0 through December 31, 2014 (pursuant to the Seventh Amendment, discussed below) and ii) not less than 2.5 to 1.0 for subsequent periods.

        At March 31, 2014, under the borrowing base of $800.0 million, the Company had $348.0 million of indebtedness outstanding, $1.2 million of letters of credit outstanding and $450.8 million of borrowing capacity available under the Senior Credit Agreement, of which approximately $332 million was available under the indebtedness limitation in the Company's indentures.

        On October 31, 2013, the Company entered into the Sixth Amendment to the Senior Credit Agreement , which, amount other things, provides for EBITDA (as defined in the Senior Credit Agreement) to be annualized for the next three fiscal quarters for purposes of measuring compliance with the interest coverage test. Specifically, (i) for the fiscal quarter ended December 31, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the three month period then ended multiplied by 4; (ii) for the fiscal quarter ended March 31, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the six month period then ended multiplied by 2; and (iii) for the fiscal quarter ended June 30, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the nine month period then ended multiplied by 1.333.

        On March 21, 2014, the Company entered into the Seventh Amendment to its Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment increased the borrowing base to $800.0 million in connection with the Company's annual spring redetermination and also provided the Company additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

        At March 31, 2014, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

9.25% Senior Notes

        On August 13, 2013, the Company issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Company's Senior Credit Agreement.

        The 2022 Notes bear interest at a rate of 9.25% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2014. The 2022 Notes will mature on February 15, 2022. The 2022 Notes are senior unsecured obligations of the Company, rank equally with all of its current and future senior indebtedness and are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for

14

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

one minor subsidiary. Halcón, the issuer of the 2022 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        In connection with the sales of the 2022 Notes, the Company entered into registration rights agreements, pursuant to which the Company agreed to conduct a registered exchange offer for the 2022 Notes or cause to become effective a shelf registration statement providing for the resale of the 2022 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement and use its reasonable best efforts to cause such registration statement for the 2022 Notes to become effective, (b) promptly following the effectiveness of such registration statement, offer to exchange new registered notes having terms substantially identical to the 2022 Notes for outstanding 2022 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2022 Notes. If the exchange offer is not consummated within 365 days after August 13, 2013, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2022 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the registration rights agreements it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2022 Notes. On March 14, 2014, the Company filed a registration statement on Form S-4 with the SEC relating to the offer to exchange registered 9.25% senior notes due 2022 for any and all of its 2022 Notes and, on April 18, 2014, the Company commenced such offer to exchange.

        On or before August 15, 2016, the Company may redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.250% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2022 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the related equity offering. In addition, at any time prior to August 15, 2017, the Company may redeem some or all of the 2022 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at August 15, 2017, plus (ii) any required interest payments due on the notes through August 15, 2017 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

        The indenture governing the 2022 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes 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. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount

15

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

8.875% Senior Notes

        On November 6, 2012, the Company issued $750.0 million aggregate principal amount of its 8.875% senior notes due 2021 (the 2021 Notes), at a price to the initial purchasers of 99.247% of par. The net proceeds from the offering of approximately $725.6 million (after deducting the initial purchasers' discounts, commissions and offering expenses) were used to fund a portion of the cash consideration paid in the acquisition of two wholly-owned subsidiaries of Petro-Hunt Holdings, LLC and Pillar Holdings, LLC, which owned acreage prospective for the Bakken / Three Forks formations located in North Dakota, in Williams, Mountrail, McKenzie and Dunn Counties.

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

        The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2021 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for one minor subsidiary. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        On June 4, 2013, the Company completed a registered exchange offer of outstanding 2021 Notes for new registered notes having terms substantially identical to the 2021 Notes.

        On or before November 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds of certain equity offerings at a redemption price of 108.875% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2021 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the date of closing of the related equity offering. In addition, at any time prior to November 15, 2016, the Company may redeem some or all of the 2021 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at November 15, 2016, plus (ii) any required interest payments due on the notes through November 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

        In conjunction with the issuance of the 2021 Notes, the Company recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $5.0 million at March 31, 2014. In conjunction with the issuance of the additional 2021 Notes, the Company recorded a premium of approximately $30.0 million to be amortized over the remaining life of the additional 2021 Notes using the effective interest method. The remaining unamortized premium was $26.8 million at March 31, 2014.

        The indenture governing the 2021 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes 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. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

9.75% Senior Notes

        On July 16, 2012, the Company issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Merger and the acquisition of certain oil and gas leaseholds located in East Texas.

        On December 19, 2013, the Company issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.1 million (after the initial purchasers' fees, commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

        The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2020 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned

17

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

subsidiaries, except for one minor subsidiary. Halcón, the issuer of the 2020 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        On June 4, 2013, the Company completed a registered exchange offer of the outstanding 2020 Notes originally issued, for new registered notes having terms substantially identical to the original 2020 Notes. In connection with the sales of the additional 2020 Notes, the Company entered into registration rights agreements, pursuant to which the Company agreed to conduct a registered exchange offer for the 2020 Notes or cause to become effective a shelf registration statement providing for the resale of the 2020 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement and use its reasonable best efforts to cause such registration statement for the 2020 Notes to become effective, (b) promptly following the effectiveness of such registration statement, offer to exchange new registered notes having terms substantially identical to the 2020 Notes for outstanding 2020 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2020 Notes. If the exchange offer is not consummated within 180 days after December 19, 2013, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2020 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the registration rights agreements it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2020 Notes. On March 14, 2014, the Company filed a registration statement on Form S-4 with the SEC relating to the offer to exchange registered 9.75% senior notes due 2020 for any and all of its 2020 Notes and, on April 18, 2014, the Company commenced such offer to exchange.

        On or before July 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.750% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2020 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the equity offering. In addition, at any time prior to July 15, 2016, the Company may redeem some or all of the 2020 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess , if any of (a) the present value at such time of (i) the redemption price of such note at July 15, 2016, plus (ii) any required interest payments due on the notes through July 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

        In conjunction with the issuance of the 2020 Notes, the Company recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $8.6 million at March 31, 2014. In conjunction with the issuance of the additional 2020 Notes, the Company recorded a premium of approximately $11.0 million to be amortized over the remaining life of the additional 2020 Notes using the effective interest method. The remaining unamortized premium was approximately $10.6 million at March 31, 2014.

        The indenture governing the 2020 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes to incur

18

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

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. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

8.0% Convertible Note

        On February 8, 2012, the Company issued the 2017 Note in the principal amount of $275.0 million together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. The 2017 Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year and matures on February 8, 2017. Through the March 31, 2014 interest payment date, the Company was permitted to elect to pay the interest in kind, by adding to the principal of the 2017 Note, all or any portion of the interest due on the 2017 Note. The Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and added $3.2 million, $5.7 million and $5.8 million of interest incurred during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. The Company did not elect to pay-in-kind interest for the quarterly payments due subsequent to September 30, 2012. As of February 8, 2014, holders of the 2017 Note became entitled to convert at their election each $4.50 of principal and accrued but unpaid interest into one share of the Company's common stock. The 2017 Note is a senior unsecured obligation of the Company.

        The Company allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, the Company recorded a discount of $43.6 million to be amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $28.3 million at March 31, 2014.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. LONG-TERM DEBT (Continued)

Promissory Notes

        On December 28, 2012, the Company completed the acquisition of certain oil and natural gas properties in Brazos County, Texas for approximately $83.7 million, before and subject to, customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. During the three months ended March 31, 2013, the Company completed its review of the properties and paid approximately $62.4 million during the period for properties deemed to have clear title and no defects. In addition, notice was given to the sellers of the Company's assertion of title and environmental defects amounting to $12.9 million for the remaining properties. During the three months ended September 30, 2013, the title and environmental defects were cured by the sellers and the Company paid the remaining portion of the purchase price.

        In conjunction with the issuance of the promissory notes in December 2012, the Company recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. The Company expensed the discount during the first quarter of 2013.

Debt Issuance Costs

        The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. During the first three months of 2014, the Company capitalized approximately $0.1 million in costs associated with the issuance of the additional 2020 Notes. At March 31, 2014 and December 31, 2013, the Company had approximately $62.4 million and $64.3 million, respectively, of unamortized debt issuance costs.

5. FAIR VALUE MEASUREMENTS

        Pursuant to 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.

        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 March 31, 2014 and December 31, 2013. 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.

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. FAIR VALUE MEASUREMENTS (Continued)

There were no transfers between fair value hierarchy levels for the three months ended March 31, 2014.

	March 31, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	15,457	$	—	$	15,457
Liabilities
Liabilities from derivative contracts	$	—	$	51,124	$	2,784	$	53,908

	December 31, 2013
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	24,762	$	—	$	24,762
Liabilities
Liabilities from derivative contracts	$	—	$	34,376	$	2,816	$	37,192

        Derivative contracts listed above as Level 2 include collars, swaps and put options that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" in the Company's unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 6, "Derivative and Hedging Activities" for additional discussion of derivatives.

        Derivative contracts listed above as Level 3 include extendable collars that are carried at fair value. The significant unobservable inputs for these Level 3 contracts include unpublished forward strip prices

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. FAIR VALUE MEASUREMENTS (Continued)

and market volatilities. The following table sets forth a reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy (in thousands):

	Significant Unobservable Inputs (Level 3)
	March 31, 2014			December 31, 2013
Beginning Balance	$	(2,816	)	$	—
Net gain (loss) on derivative contracts		32			(2,816	)
Settlements		—			—
Purchase of derivative contracts		—			—
Buy out of derivative contracts		—			—
Ending Balance	$	(2,784	)	$	(2,816	)
Change in unrealized gains (losses) included in earnings related to derivatives still held at March 31, 2014 and December 31, 2013	$	32		$	(2,816	)

        As of March 31, 2014 and December 31, 2013, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a 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. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in the Company's Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

        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 receivable and accounts payable approximates 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, long-term debt instruments as of March 31, 2014 and December 31, 2013 (excluding discounts, premiums and deferred premiums on derivative contracts):

	March 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
9.25% $400 million senior notes	$	400,000	$	416,924	$	400,000	$	407,432
8.875% $1.35 billion senior notes		1,350,000		1,401,975		1,350,000		1,390,500
9.75% $1.15 billion senior notes		1,150,000		1,242,000		1,150,000		1,197,438
8.0% $289.7 million convertible note		289,669		393,423		289,669		368,418
	$	3,189,669	$	3,454,322	$	3,189,669	$	3,363,788

22

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. FAIR VALUE MEASUREMENTS (Continued)

        The fair value of the Company's fixed interest debt instruments was calculated using Level 2 criteria at March 31, 2014 and December 31, 2013. The fair value of the Company's senior notes is based on quoted market prices from trades of such debt. The fair value of the Company's convertible note is based on published market prices and risk-free rates.

        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; and therefore, the Company has designated these liabilities as Level 3. See Note 7, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

6. DERIVATIVE AND HEDGING ACTIVITIES

        The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to economically hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company 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. Historically, the Company has also entered into interest rate swaps to mitigate exposure to market rate fluctuations. The Company does not enter into derivative contracts for speculative trading purposes.

        It is the Company's policy to enter into derivative contracts, including interest rate derivatives, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in its Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Company's Senior Credit Agreement.

        At March 31, 2014 and December 31, 2013, the Company's crude oil and natural gas derivative positions consisted of swaps, swaptions, costless put/call "collars," extendable costless collars and put options. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. Extendable collars are costless put/call contracts that may be extended annually at the option of the counterparty on a designated date. A sold put option limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. The Company has elected to not 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 all payments

23

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

        At March 31, 2014, the Company had 90 open commodity derivative contracts summarized in the following tables: 11 natural gas collar arrangements, 58 crude oil collar arrangements, two crude oil three-way collars, one crude oil put option, and eight crude oil swaps, eight crude oil swaptions and two crude oil extendable collars.

        At December 31, 2013, the Company had 86 open commodity derivative contracts summarized in the following tables: 10 natural gas collar arrangements, 52 crude oil collar arrangements, five crude oil three-way collars, one crude oil put option, eight crude oil swaps, eight crude oil swaptions and two crude oil extendable collars.

        All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013:

		Asset derivative contracts					Liability derivative contracts
Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	March 31, 2014		December 31, 2013		Balance sheet location	March 31, 2014			December 31, 2013
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	1,214	$	2,028	Current liabilities—liabilities from derivative contracts	$	(32,890	)	$	(17,859	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		14,243		22,734	Other noncurrent liabilities—liabilities from derivative contracts		(21,018	)		(19,333	)
Total derivatives not designated as hedging contracts under ASC 815		$	15,457	$	24,762		$	(53,908	)	$	(37,192	)

24

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

        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:

		Amount of gain or (loss) recognized in income on derivative contracts for the Three Months Ended March 31,
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2014			2013
		(In thousands)
Commodity contracts:
Unrealized gain (loss) oncommodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(26,916	)	$	(16,799	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		(6,740	)		(1,623	)
Total net gain (loss) on derivative contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(33,656	)	$	(18,422	)

        At March 31, 2014 and December 31, 2013, the Company had the following open crude oil and natural gas derivative contracts:

			March 31, 2014
					Floors				Ceilings				Put Options Sold
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
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500	$	95.00	$	95.00	$	98.20 - 101.00	$	99.13	$	70.00	$	70.00
April 2014 - June 2014	Collars	Crude Oil		364,000		90.00		90.00		96.50 - 99.50		98.00
April 2014 - December 2014	Collars	Crude Oil		5,706,250		85.00 - 95.00		88.67		93.60 - 108.45		96.27
April 2014 - December 2014	Collars	Natural Gas		8,937,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015(1)	Collars	Crude Oil		5,475,000		82.50 - 90.00		86.00		90.00 - 100.25		94.34
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015(2)	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
July 2015 - December 2015	Collars	Crude Oil		644,000		85.00		85.00		90.00 - 90.50		90.16
January 2016 - December 2016	Collars	Natural Gas		732,000		4.00		4.00		4.22		4.22
January 2016 - December 2016(3)	Swaps	Crude Oil		2,196,000		88.00 - 88.87		88.30

⁽¹⁾

Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 732,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 366,000 Bbls for the year ended December 31, 2016.

⁽²⁾

Includes an outstanding crude oil swap of which may be extended at a price of $91.25 per Bbl for 732,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 366,000 Bbls for the year ended December 31, 2016.

⁽³⁾

Includes an outstanding crude oil swap which may be extended at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

25

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

			December 31, 2013
					Floors				Ceilings				Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
January 2014 - March 2014	Three-Way Collars	Crude Oil		144,000	$	95.00	$	95.00	$	98.60 - 109.50	$	100.03	$	70.00	$	70.00
January 2014 - June 2014	Collars	Crude Oil		724,000		90.00		90.00		96.50 - 99.50		98.00
January 2014 - December 2014	Collars	Crude Oil		7,573,750		85.00 - 95.00		88.67		93.60 - 108.45		96.22
January 2014 - December 2014	Collars	Natural Gas		11,862,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500		95.00		95.00		98.20 - 101.00		99.13		70.00		70.00
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015(1)	Collars	Crude Oil		5,110,000		82.50 - 90.00		86.07		90.00 - 100.25		94.65
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015(2)	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
January 2016 - December 2016(3)	Swaps	Crude Oil		2,190,000		88.00 - 88.87		88.30

⁽¹⁾

Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2016.

⁽²⁾

Includes an outstanding crude oil swap which may be extended at a price of $91.25 per Bbl for 730,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 365,000 Bbls for the year ended December 31, 2016.

⁽³⁾

Includes an outstanding crude oil swap which may be extended at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

        The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at March 31, 2014 and December 31, 2013 in accordance with ASU 2011-11 and ASU 2013-01:

	Derivative Assets						Derivative Liabilities
Offsetting of Derivative Assets and Liabilities	March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
	(In thousands)						(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	15,457		$	24,762		$	(53,908	)	$	(37,192	)
Amounts Not Offset in the Consolidated Balance Sheet		(14,625	)		(20,036	)		14,235			19,507
Net Amount	$	832		$	4,726		$	(39,673	)	$	(17,685	)

        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.

26

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. ASSET RETIREMENT OBLIGATIONS

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

        The Company recorded the following activity related to its ARO liability for the three months ended March 31, 2014 (in thousands, inclusive of the current portion):

Liability for asset retirement obligations as of December 31, 2013	$	39,257
Liabilities settled and divested		(2,019	)
Additions		1,104
Accretion expense		479
Revisions in estimated cash flows		154
Liability for asset retirement obligations as of March 31, 2014	$	38,975

8. COMMITMENTS AND CONTINGENCIES

Commitments

        The Company leases corporate office space in Houston, Texas; Tulsa, Oklahoma; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $1.9 million and $2.5 million for the three months ended March 31, 2014 and 2013, respectively. In addition, the Company has commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2017. Early termination of the drilling rig commitments would result in termination penalties approximating $42.3 million, which would be in lieu of the remaining $79.7 million of drilling rig commitments as of March 31, 2014. As of March 31, 2014, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2013, as disclosed in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013, approximating $66.6 million in the aggregate, and containing various expiration dates through 2024.

        The Company has entered into various long-term gathering, transportation and sales contracts in its Bakken / Three Forks formations in North Dakota. As of March 31, 2014, the Company had in place nine long-term crude oil contracts and two long-term natural gas contracts in this area. Under the terms of these contracts, the Company has committed a substantial portion of its Bakken / Three Forks production for periods ranging from five to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. The Company believes that there are sufficient available reserves and supplies in the Bakken / Three Forks formations to meet its commitments.

        Additionally, as of March 31, 2014, the Company had one long-term natural gas transportation contract and one long-term natural gas gathering contract in the Woodbine formation in East Texas.

27

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. COMMITMENTS AND CONTINGENCIES (Continued)

The rate under the transportation contract was negotiated based on market rates and the contract term is five years from the date of first production. Under the gathering contract, the Company has committed substantially all of its natural gas production from specific wells in the area, until a contracted volume amount is reached, in exchange for the construction of a gathering system. The contract term is five years from the date of first production.

        Historically, the Company has been able to meet its delivery commitments.

        On December 20, 2013, the Company entered into a carry and earning agreement, as amended (the Agreement), with an independent third party (the Seller) associated with the acquisition of certain properties prospective for the Tuscaloosa Marine Shale, primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The Agreement requires the Company to fund up to $189.4 million (the Carry Amount) in exchange for approximately 117,870 net acres. The Company paid $62.5 million of the Carry Amount at closing on February 28, 2014. The Carry Amount is to be used by the Seller to fund wells prospective for the Tuscaloosa Marine Shale to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, the Company will also receive a 5% working interest in the Carry Wells. The commitment period is from January 1, 2014 through August 31, 2017, and is capped at $120.0 million through December 31, 2014 and up to the full $189.4 million through August 31, 2017. Any amount of the commitment not spent or subject to an approval for expenditure by the Seller on or before August 31, 2017 shall be forfeited.

Contingencies

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

9. STOCKHOLDERS' EQUITY

5.75% Series A Convertible Perpetual Preferred Stock

        On June 18, 2013, the Company completed its offering of 345,000 shares of its 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred Stock) at a public offering price of $1,000 per share (the Liquidation Preference). The net proceeds to the Company from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. The Company used the net proceeds from the offering to repay a portion of the outstanding borrowings under its Senior Credit Agreement.

        Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Company's Board of Directors, cumulative dividends at the rate of 5.75% per annum (the dividend rate) on the Liquidation Preference per share of the Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, in common stock of the Company or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year. On March 3, 2014, the Company paid cumulative, declared dividends of $5.0 million by issuing approximately 1.4 million

28

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

shares of common stock reflected as a non-cash dividend. As of March 31, 2014, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $1.7 million.

        The Series A Preferred Stock has no maturity date, is not redeemable by the Company at any time, and will remain outstanding unless converted by the holders or mandatorily converted by the Company as described below.

        Each share of Series A Preferred Stock is convertible, at the holder's option at any time, initially into approximately 162.4431 shares of common stock of the Company (which is equivalent to an initial conversion price of approximately $6.16 per share), subject to specified adjustments as set forth in the Series A Designation. Based on the initial conversion rate, approximately 56.0 million shares of common stock of the Company would be issuable upon conversion of all the shares of Series A Preferred Stock.

        On or after June 6, 2018, the Company may, at its option, give notice of its election to cause all outstanding shares of the Series A Preferred Stock to be automatically converted into shares of common stock of the Company at the conversion rate (as defined in the Series A Designation), if the closing sale price of the Company's common stock equals or exceeds 150% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days.

        If the Company undergoes a fundamental change (as defined in the Series A Designation) and a holder converts its shares of the Series A Preferred Stock at any time beginning at the opening of business on the trading day immediately following the effective date of such fundamental change and ending at the close of business on the 30th trading day immediately following such effective date, the holder will receive, for each share of the Series A Preferred Stock surrendered for conversion, a number of shares of common stock of the Company equal to the greater of: (1) the sum of (i) the conversion rate and (ii) the make-whole premium, if any, as described in the Series A Designation; and (2) the conversion rate which will be increased to equal (i) the sum of the $1,000 liquidation preference plus all accumulated and unpaid dividends to, but excluding, the settlement date for such conversion, divided by (ii) the average of the closing sale prices of the Company's common stock for the five consecutive trading days ending on the third business day prior to such settlement date; provided that the prevailing conversion rate as adjusted pursuant to this will not exceed 292.3977 shares of common stock of the Company per share of the Series A Preferred Stock (subject to adjustment in the same manner as the conversion rate).

        Except as required by Delaware law, holders of the Series A Preferred Stock will have no voting rights unless dividends are in arrears and unpaid for six or more quarterly periods. Until such arrearage is paid in full, the holders (voting as a single class with the holders of any other preferred shares having similar voting rights) will be entitled to elect two additional directors and the number of directors on the Company's Board of Directors will increase by that same number.

Common Stock

        On August 13, 2013, the Company completed the issuance and sale of 43.7 million shares of its common stock in an underwritten public offering. The shares of common stock sold have been registered under the Securities Act pursuant to a Registration Statement on Form S-3 (No. 333-188640), which was filed with the SEC and became automatically effective on May 16, 2013. The net proceeds to the Company from the offering of common stock were approximately $215.2 million, after deducting the

29

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

underwriting discount and estimated offering expenses. The Company used the net proceeds from the offering to repay a portion of the then outstanding borrowings under its Senior Credit Agreement.

        On January 17, 2013, with stockholder approval, the Company filed a Certificate of Amendment of the Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to increase its authorized common stock by approximately 333.3 million shares for a total of 670.0 million authorized shares of common stock.

Warrants

        In February 2012, in conjunction with the issuance of the 2017 Notes, the Company issued warrants to purchase 36.7 million shares of the Company's common stock at an exercise price of $4.50 per share of common stock, which the Company refers to as the February 2012 Warrants. The Company allocated $43.6 million to the February 2012 Warrants which is reflected in additional paid-in capital in stockholders' equity, net of $0.6 million in issuance costs. The February 2012 Warrants entitle the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

        In August 2012, as part of the Company's acquisition of GeoResources by merger, the Company assumed outstanding GeoResources common stock warrants. At the date of the merger 0.6 million GeoResources warrants were outstanding and were converted to 1.2 million Halcón warrants (the August 2012 Warrants). Each GeoResources warrant was converted into an August 2012 Warrant to acquire one share of Halcón common stock (Share Portion) at an exercise price of $8.40 per share of common stock and the right to receive $20 in cash per equivalent assumed share (Cash Portion) at an exercise price of $0.82 per $1.00 received. The August 2012 Warrants contained substantially the same terms of the original GeoResources warrants with adjustments to the exercise price and addition of the Cash Portion to reflect the impact of the consideration per share in the merger. The August 2012 Warrants expired on June 9, 2013. The August 2012 Warrants were reflected as a current liability in the unaudited condensed consolidated balance sheets at March 31, 2013 and were recorded at fair value. Changes in fair value were recognized in "Interest expense and other, net" in the unaudited condensed consolidated statements of operations.

Incentive Plan

        On May 8, 2006, the Company's stockholders first approved its 2006 Long-Term Incentive Plan (the Plan). On May 23, 2013, shareholders last approved an increase in authorized shares under the Plan from 11.5 million to 41.5 million. As of March 31, 2014 and December 31, 2013, a maximum of 13.2 million and 25.7 million shares of common stock, respectively, remained reserved for issuance under the Plan.

        The Company accounts for share-based payment accruals under authoritative guidance on stock compensation, as set forth in ASC Topic 718. The guidance requires all share-based payments to employees and directors, including grants of performance units, stock options, and restricted stock, to be recognized in the financial statements based on their fair values.

        For the three months ended March 31, 2014 and 2013, the Company recognized $4.3 million and $2.3 million, respectively, of share-based compensation expense as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

30

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

Performance Share Units

        During the three months ended March 31, 2014, the Company granted performance share units (PSU) under the Plan covering 1.6 million shares of common stock to senior management of the Company. The PSU provide that the number of shares of common stock received upon vesting will vary if the market price of the Company's common stock exceeds certain pre-established target thresholds as measured by the average of the adjusted closing price of a share of the Company's common stock during the sixty trading days preceding the third anniversary of issuance, or the measurement date. The PSU utilize $4.00 as the floor price, below which the PSU will not vest and will expire. If the average market price at the measurement date is equal to $4.00, the PSU will vest and represent the right to receive 50% of the number of shares of common stock underlying the PSU. At $7.00, the PSU will vest and represent the right to receive the full number of shares of common stock underlying the PSU; and at $10.00, the PSU will vest and represent the right to receive 200% of the number of shares of common stock underlying the PSU. All stock price targets are subject to customary adjustments based upon changes in the Company's capital structure. In the event the average market price falls between targeted price thresholds, the PSU will vest and represent the right to receive a proportionate number of shares, e.g., 75% of the number of shares of common stock underlying the PSU if the average market price at such time is $5.50, 150% of the number of shares of common stock underlying the PSU if the average market price at such time is $8.50, and so forth. The Company has reserved for issuance under the Plan the maximum right to receive upon vest of the PSU, or 3.2 million shares of common stock. At March 31, 2014, the Company had $4.8 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 2.9 years.

Stock Options

        During the three months ended March 31, 2014, the Company granted stock options under the Plan covering 6.1 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $3.67 to $4.33 with a weighted average exercise price of $3.67. 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. At March 31, 2014, the Company had $20.4 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.6 years.

        During the three months ended March 31, 2013, the Company granted stock options under the Plan covering 1.5 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $6.36 to $8.23 with a weighted average exercise price of $7.20. 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. At March 31, 2013, the unrecognized compensation expense related to stock options totaled $14.4 million and will be recognized on the graded-vesting method over the requisite service periods.

        During the three months ended March 31, 2013, the Company's Board of Directors approved an increase in authorized shares under the Plan from 11.5 million to 41.5 million, subject to stockholder approval. As a result, stock options granted to executive officers and certain other participants covering 4.4 million shares during the three months ended March 31, 2013 were pending stockholder approval on May 23, 2013 because these grants would have caused the Company to exceed the limit of shares

31

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. STOCKHOLDERS' EQUITY (Continued)

available under the Plan. These awards were subject to forfeiture in the event that stockholder approval was not obtained and therefore the Company did not record any expense associated with the amortization of these awards in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2013.

Restricted Stock

        During the three months ended March 31, 2014, the Company granted 3.6 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $3.67 to $4.33 with a weighted average price of $3.67. Employee shares vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six-months from the date of grant. At March 31, 2014, the Company had $19.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.7 years.

        During the three months ended March 31, 2013, the Company granted 2.8 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $6.36 to $7.26 with a weighted average price of $7.10. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant. At March 31, 2013, the Company had $20.1 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.8 years.

Treasury Stock

        During the three months ended March 31, 2013, the Company granted 2.8 million shares of restricted stock under the Plan to directors and employees of the Company of which 1.2 million shares were issued out of treasury stock. In addition, the Company retired 0.4 million shares from treasury stock representing shares that were repurchased for taxes tendered upon vesting of stock based compensation awards in prior years. As of March 31, 2013, the Company had no issued shares held in treasury.

10. INCOME TAXES

        Under guidance contained in Topic 740 of the ASC, deferred taxes are determined by applying the provisions of enacted tax laws and rates for the jurisdictions in which the Company operates to the estimated future tax effects of the differences between the tax basis of assets and liabilities and their reported amounts in the Company's financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

        In assessing the need for a valuation allowance on our deferred tax assets, the Company considers possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. A significant item of objective negative evidence considered was the cumulative three-year book loss driven primarily by ceiling test write-downs in 2013. Based upon the evaluation of the available

32

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. INCOME TAXES (Continued)

evidence the Company continued to record a full valuation allowance against its net deferred tax assets as of March 31, 2014.

        The Company recorded no income tax expense or benefit on a pre-tax loss of $73.0 million for the three months ended March 31, 2014 due to the valuation allowance. For the three months ended March 31, 2013, the Company recorded a tax provision of $3.3 million on pre-tax income of $8.8 million. The effective tax rate for the three months ended March 31, 2014 was 0.0% compared to 37.6% for the three months ended March 31, 2013. The significant difference in the effective tax rate is due to the full valuation allowance that was established during the fourth quarter of 2013.

        During the first quarter of 2014, the Internal Revenue Service commenced an audit of GeoResources, Inc.'s tax returns for the tax years ending December 31, 2010 through August 1, 2012. The audit is ongoing as of the date of this filing.

11. EARNINGS PER COMMON SHARE

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

	Three Months Ended March 31,
	2014			2013
	(In thousands, except per share amounts)
Basic:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465
Weighted average basic number of common shares outstanding		413,521			346,139
Basic net income (loss) per share of common stock	$	(0.19	)	$	0.02
Diluted:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465
Weighted average basic number of common shares outstanding		413,521			346,139
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			14,411
Exercise of August 2012 Warrants		—			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			1,255
Vesting of performance share units		—			—
Conversion of 2017 Notes		Anti-dilutive			Anti-dilutive
Conversion of preferred stock		—			21,760
Conversion of Series A Preferred Stock		Anti-dilutive			—
Weighted average diluted number of common shares outstanding		413,521			383,565
Diluted net income (loss) per share of common stock	$	(0.19	)	$	0.01

33

HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. EARNINGS PER COMMON SHARE (Continued)

        Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock, totaling 173.2 million shares for the three months ended March 31, 2014 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. Common stock equivalents, including stock options, warrants, and convertible debt, totaling 70.6 million shares were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive for the three months ended March 31, 2013.

12. ADDITIONAL FINANCIAL STATEMENT INFORMATION

        Certain balance sheet amounts are comprised of the following:

	March 31, 2014		December 31, 2013
	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	169,640	$	129,355
Joint interest accounts		137,957		170,907
Affiliated partnership		302		500
Other		1,405		11,756
	$	309,304	$	312,518
Prepaids and other:
Prepaids	$	5,974	$	5,636
Income tax receivable		5,404		10,404
Other		58		58
	$	11,436	$	16,098
Accounts payable and accrued liabilities:
Trade payables	$	86,708	$	87,661
Accrued oil and natural gas capital costs		314,094		292,472
Revenues and royalties payable		128,598		124,222
Accrued interest expense		75,177		82,570
Accrued employee compensation		4,960		2,272
Accrued lease operating expenses		24,980		21,469
Drilling advances from partners		16,314		24,882
Accounts payable to affiliated partnership		939		679
Other		433		362
	$	652,203	$	636,589

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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 months ended March 31, 2014 and 2013 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, 2013.

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

Overview

        We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production growth and broad flexibility to direct our capital resources to projects with the greatest potential returns. During 2013 and 2014, we focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays.

        Our oil and natural gas assets consist of undeveloped acreage positions in unconventional liquids-rich basins/fields. We have acquired acreage and may acquire additional acreage in the Bakken / Three Forks formations in North Dakota, the Eagle Ford formation in East Texas and the Tuscaloosa Marine Shale formation in Louisiana and Mississippi, as well as several other areas.

        Our average daily oil and natural gas production increased 41% in the first three months of 2014 compared to the same period in the prior year. During the first three months of 2014, we averaged 36,622 barrels of oil equivalent (Boe) per day compared to average daily production of 26,022 Boe/d during the first three months of 2013. The increase in production compared to the prior year period was driven primarily by operated drilling results and increased production volumes associated with the development of properties we acquired in 2012 in the Bakken / Three Forks and the Eagle Ford formation in East Texas (which we refer to as "El Halcón"). These areas collectively accounted for an increase of approximately 16,100 Boe/d. This increase was partially offset by production decreases from our divestiture of non-core properties during 2013. During the first three months of 2014, we participated in the drilling of 67 gross (30.1 net) wells, all of which were completed and capable of production.

Recent Developments

Amendment to the Senior Credit Agreement and Borrowing Base

        On March 21, 2014, we entered into the Seventh Amendment to our Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment increased the borrowing base under our Senior Credit Agreement to $800.0 million in connection with the annual spring redetermination and also provided us additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

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Capital Resources and Liquidity

        Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from potential non-core asset divestitures, proceeds from potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $800.0 million. Our borrowing base is redetermined on a semi-annual basis (with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations) and adjusted based on the estimated value of our oil and natural gas reserves, the amount and cost of our other indebtedness and other relevant factors. Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base and covenants under our Senior Credit Agreement and our senior unsecured debt indentures. Our Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of i) not less than 2.0 to 1.0 through December 31, 2014 (pursuant to the Seventh Amendment), and ii) not less than 2.5 to 1.0 for subsequent periods. We are subject to additional covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior unsecured debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test, the fixed charge coverage ratio test, applies to all indebtedness and requires that after giving effect to the incurrence of additional debt the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0. The second test allows us to incur additional indebtedness, beyond the limitations of the fixed charge coverage ratio test, as long as this additional debt is incurred under Credit Facilities (as defined in our indentures) and the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination. At March 31, 2014, under the borrowing base of $800.0 million, we had $348.0 million indebtedness outstanding under our Senior Credit Agreement, $1.2 million of letters of credit outstanding and $450.8 million of borrowing capacity, of which approximately $332 million was available to us under the indebtedness limitations in our indentures.

        Our ability to meet our debt covenants and our capacity to incur additional indebtedness will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. For example, lower oil and natural gas prices could result in a redetermination of the borrowing base under our Senior Credit Agreement at a lower level and reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets as determined under our indentures, and thus could reduce our ability to incur indebtedness. Our strategic divestitures of non-core producing properties in favor of investing in undeveloped acreage, coupled with our aggressive drilling plans also impact our near-term ability to comply with our debt covenants, particularly the interest coverage test under our Senior Credit Agreement and the fixed charge coverage ratio under our indentures by reducing our production and reserves on a current and, for purposes of covenant calculations, a pro forma historical basis, while drilling takes time to replace these losses. Of course, over the longer term, we expect that our strategy and our investments will result in increased production and reserves, lower lease operating costs and more abundant drilling opportunities. As a consequence, we constantly monitor our liquidity and capital resources, endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

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        We have in the past obtained amendments to the covenants under our Senior Credit Agreement under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. During 2013, we obtained amendments to the calculation of the interest coverage ratio covenant under our Senior Credit Agreement allowing us to annualize our quarterly EBITDA because, among other things, we anticipated that our strategic decision to divest our Eagle Ford shale producing properties and invest in the acquisition and drilling of undeveloped acreage would have caused us to fall below the interest coverage ratio. We requested reduction in the minimum required interest coverage ratio of 2.0 to 1.0 for 2014 and that request was granted on March 21, 2014, as noted above under "Recent Developments." The basis for the amendment request is similar to previously requested waivers described above, i.e., the potential for us to fall out of compliance primarily as a result of our strategic decision to divest producing properties, invest extensively in undeveloped acreage and the long lead times associated with replacing lost production through our drilling program. As part of our plan to manage liquidity risks, we have scaled back our capital expenditures budget, focused our drilling program on our highest return projects, are actively considering various joint venture opportunities to finance development of our Tuscaloosa Marine Shale properties, and continue to explore opportunities to divest non-core properties.

        If, in the future, the lenders under our Senior Credit Agreement are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Senior Credit Agreement and seek alternative sources of capital to fund our business and anticipated capital expenditures. 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, may be subject to forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and may be forced 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. Further, the failure to comply with the restrictive covenants relating to our indebtedness could result in the declaration of a default and cross default under the instruments governing our indebtedness, potentially resulting in acceleration of our obligations and adversely impacting our financial condition.

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

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

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Cash Flow

        Our primary sources of cash for the three months ended March 31, 2014 were from operating and financing activities and for the three months ended March 31, 2013 were from financing activities. In the first three months of 2014, borrowings on our Senior Credit Agreement were the primary driver of the net cash provided by financing activities. The increase in cash received from operations, coupled with the cash from financing activities, were offset by cash used in investing activities to fund our drilling program and acquire additional leasehold interests. Operating cash flow increases were substantially driven by the significant increase in production volumes, namely from our Bakken and El Halcón areas, as compared to the three months ended March 31, 2013 and, to a lesser extent, higher commodity prices. Fluctuations in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See "Results of Operations" below for a review of the impact of prices and volumes on sales.

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

	Three Months Ended March 31,
	2014			2013
	(In thousands)
Cash flows provided by (used in) operating activities	$	159,500		$	45,710
Cash flows provided by (used in) investing activities		(509,498	)		(445,024	)
Cash flows provided by (used in) financing activities		347,530			397,610
Net increase (decrease) in cash	$	(2,468	)	$	(1,704	)

        Operating Activities.    Net cash provided by operating activities for the three months ended March 31, 2014 and 2013, was $159.5 million and $45.7 million, respectively.

        The $159.5 million of operating cash flows for the three months ended March 31, 2014 primarily reflect the impact of increased production from our acquisitions and developmental drilling activities which drove a 44% increase in revenues, as compared to the prior year period, and outpaced related operating expenses.

        Investing Activities.    The primary driver of cash used in investing activities is capital spending, specifically drilling and completions coupled with the acquisition of unevaluated leasehold acreage in our target areas. Net cash used in investing activities was approximately $509.5 million and $445.0 million for the three months ended March 31, 2014 and 2013, respectively.

        During the first three months of 2014, we incurred cash expenditures of $432.8 million on oil and natural gas capital expenditures, of which $328.6 million related to drilling and completion costs and the remainder was primarily associated with leasing, acquisitions and seismic data. We participated in the drilling of 67 gross (30.1 net) wells, all of which were completed and capable of production. We also spent $62.5 million related to a carried interest in the Tuscaloosa Marine Shale. We spent an additional $16.0 million on other operating property and equipment capital expenditures, of which $13.2 million pertained to pipelines and related infrastructure projects, and the remainder was spent on leasehold improvements, computers and software.

        During the first three months of 2013, we incurred cash expenditures of $380.1 million on oil and natural gas capital expenditures. We participated in the drilling of 53 gross (13.7 net) wells of which 52 gross (12.7 net) wells were completed and capable of production and one gross (1.0 net) well was a dry hole. We spent an additional $36.3 million on other operating property and equipment capital expenditures; of which $30.9 million pertained to pipelines and related infrastructure projects and the

38

remainder was spent on leasehold improvements, computers and software primarily in our corporate office in Houston, Texas.

        Financing Activities.    Net cash flows provided by financing activities were $347.5 million and $397.6 million for the three months March 31, 2014 and 2013, respectively. The primary drivers of cash provided by financing activities for the three months ended March 31, 2014 were borrowings on our Senior Credit Agreement.

        On January 14, 2013, we completed the issuance of an additional $600.0 million aggregate principal amount of our 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees and expenses) and were used to repay all of the then outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program.

Contractual Obligations

        We lease corporate office space in Houston, Texas; Tulsa, Oklahoma; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $1.9 million and $2.5 million for the three months ended March 31, 2014 and 2013, respectively. In addition, we have commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2017. Early termination of the drilling rig commitments would result in termination penalties approximating $42.3 million, which would be in lieu of the remaining $79.7 million of drilling rig commitments as of March 31, 2014. As of March 31, 2014, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2013 disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, approximating $66.6 million in the aggregate, and containing various expiration dates through 2024.

        We have entered into various long-term gathering, transportation and sales contracts in the Bakken / Three Forks formations in North Dakota. As of March 31, 2014, we had in place nine long-term crude oil contracts and two long-term natural gas contracts in this area. Under the terms of these contracts, we have committed a substantial portion of our Bakken / Three Forks production for periods ranging from five to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. We believe that there are sufficient available reserves and supplies in the Bakken / Three Forks formations to meet our commitments.

        Additionally, as of March 31, 2014, we had one long-term natural gas transportation contract and one long-term natural gas gathering contract in the Woodbine formation in East Texas. The rate under the transportation contract was negotiated based on market rates and the contract term is five years from the date of first production. Under the gathering contract, we have committed substantially all of our natural gas production from specific wells in the area, until a contracted volume amount is reached, in exchange for the construction of a gathering system. The contract term is five years from the date of first production.

        Historically, we have been able to meet our delivery commitments.

Critical Accounting Policies and Estimates

        Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

39

Results of Operations

Three Months Ended March 31, 2014 and 2013

        We reported a net loss $73.0 million for the three months ended March 31, 2014 compared to net income of $5.5 million for the three months ended March 31, 2013. The following table summarizes key items of comparison and their related change for the periods indicated.

	Three Months Ended March 31,
In thousands (except per unit and per Boe amounts)	2014			2013			Change
Net income (loss)	$	(72,964	)	$	5,465		$	(78,429	)
Operating revenues:
Oil		256,029			180,827			75,202
Natural gas		9,409			5,669			3,740
Natural gas liquids		8,759			3,828			4,931
Other		952			530			422
Operating expenses:
Production:
Lease operating		36,638			25,304			11,334
Workover and other		2,789			1,624			1,165
Taxes other than income		24,160			17,436			6,724
Gathering and other		5,073			333			4,740
Restructuring		987			671			316
General and administrative:
General and administrative		28,466			29,262			(796	)
Share-based compensation		4,332			2,335			1,997
Depletion, depreciation and accretion:
Depletion—Full cost		117,246			79,891			37,355
Depreciation—Other		2,183			1,071			1,112
Accretion expense		479			896			(417	)
Full cost ceiling impairment		61,165			—			61,165
Other income (expenses):
Net gain (loss) on derivative contracts		(33,656	)		(18,422	)		(15,234	)
Interest expense and other, net		(30,939	)		(4,850	)		(26,089	)
Income tax (provision) benefit		—			(3,294	)		3,294
Production:
Crude oil—MBbls		2,806			1,931			875
Natural gas—Mmcf		1,792			1,811			(19	)
Natural gas liquids—MBbls		191			109			82
Total MBoe(1)		3,296			2,342			954
Average daily production—Boe(1)		36,622			26,022			10,600
Average price per unit(2):
Crude oil price—Bbl	$	91.24		$	93.64		$	(2.40	)
Natural gas price—Mcf		5.25			3.13			2.12
Natural gas liquids price—Bbl		45.86			35.12			10.74
Total per Boe(1)		83.19			81.27			1.92
Average cost per Boe:
Production:
Lease operating	$	11.12		$	10.80		$	0.32
Workover and other		0.85			0.69			0.16
Taxes other than income		7.33			7.44			(0.11	)
Gathering and other		1.54			0.14			1.40
Restructuring		0.30			0.29			0.01
General and administrative:
General and administrative		8.64			12.49			(3.85	)
Share-based compensation		1.31			1.00			0.31
Depletion		35.57			34.11			1.46

⁽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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        For the three months ended March 31, 2014, oil, natural gas and natural gas liquids revenues increased $83.9 million from the same period in 2013. The increase was primarily due to increased production volumes associated with the development of properties in the Bakken / Three Forks and El Halcón areas. These areas collectively accounted for an increase of approximately 16,100 Boe/d and $124.2 million of incremental revenues. This increase was partially offset by production decreases due to our divestitures of non-core properties. Realized average prices per Boe increased $1.92 per Boe to $83.19 per Boe due to the higher natural gas and natural gas liquids prices, partially offset by lower average oil prices.

        Lease operating expenses increased $11.3 million for the three months ended March 31, 2014, primarily due to $23.1 million of costs incurred on acquired properties and an increase in production within these areas as we continue to carry out our development plan. This increase was partially offset by our divestiture of non-core properties in 2013 which, historically, had higher operating costs. Lease operating expenses were $11.12 per Boe for the three months ended March 31, 2014, compared to $10.80 per Boe for the same period in 2013.

        Workover expenses increased $1.2 million for the three months ended March 31, 2014 compared to the same period in 2013 primarily due to $1.3 million of expenses associated with acquired properties and an increase in activity in these areas. This increase was partially offset by decreased workover expenses on our existing properties.

        Taxes other than income increased $6.7 million for the three months ended March 31, 2014 as compared to the same period in 2013 primarily due to $10.2 million of taxes associated with increased production as we continue to carry out our development plan. This increase was partially offset by a decrease in production associated with non-core properties we divested in the second half of 2013. 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 $7.33 per Boe and $7.44 per Boe for the three months ended March 31, 2014 and 2013, respectively. The decrease on a per Boe basis is attributed to lower ad valorem tax expense in 2014 due to the non-core properties we divested in the second half of 2013.

        Gathering and other expenses for the three months ended March 31, 2014 and 2013 were $5.1 million and $0.3 million, respectively. In 2014, approximately $1.2 million of these expenses were attributable to midstream infrastructure that we developed in our El Halcón, Woodbine and Utica / Point Pleasant operating areas and approximately $3.6 million related to gathering and other fees paid on our oil and natural gas production.

        In conjunction with our divestitures of certain non-core properties, we incurred approximately $1.0 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas for the three months ended March 31, 2014. In March 2012, we announced our intention to close the Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the Restructuring). As part of the Restructuring, we offered certain severance and retention benefits to affected employees. We incurred $0.7 million in costs associated with the Restructuring for the three months ended March 31, 2013.

        General and administrative expense for the three months ended March 31, 2014 decreased $0.8 million to $28.5 million as compared to the same period in 2013. The decrease in general and administrative expenses is attributed to decreases in professional fees and office expenses amounting to $3.2 million and $1.4 million, respectively. These were partially offset by increases in transaction costs and payroll and related employee benefit costs of approximately $3.2 million. On a per unit basis, general and administrative expenses were $8.64 per Boe and $12.49 per Boe, for the three months ended March 31, 2014 and 2013, respectively.

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        Share-based compensation expense for the three months ended March 31, 2014 was $4.3 million, an increase of $2.0 million compared to the same period in 2013. The increase in share-based compensation expense results from additional awards to employees and directors since the prior 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 volume for the current period to total remaining reserve volume as of the beginning of the period for the evaluated properties. Depletion expense increased $37.4 million to $117.2 million for the three months ended March 31, 2014 compared to the same period in 2013, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $35.57 per Boe for the three months ended March 31, 2014 compared to $34.11 per Boe for the three months ended March 31, 2013. The increase in depletion expense and the depletion rate per Boe is primarily due to the increase in production volumes associated with the development of our properties.

        Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded accretion expense of $0.5 million for the three months ended March 31, 2014, compared to $0.9 million for the same period in 2013. The decrease in accretion expense is attributable to the non-core properties we divested in the second half of 2013.

        We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling," based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $61.2 million for the three months ended March 31, 2014. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

        We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. We have also, in the past, entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations. At March 31, 2014, we had a $15.5 million derivative asset, $1.2 million of which was classified as current, and we had a $53.9 million derivative liability, $32.9 million of which was classified as current. We recorded a net derivative loss of $33.7 million ($26.9 million net unrealized loss and $6.8 million net realized loss on settled contracts and premium costs) for the three months ended March 31, 2014 compared to a net derivative loss of $18.4 million ($16.8 million net unrealized loss and $1.6 million net realized loss), in the same period in 2013.

        Interest expense increased $26.1 million for the three months ended March 31, 2014 from the same period in 2013. Capitalized interest for the three months ended March 31, 2014 and 2013 was $46.8 million and $52.8 million, respectively. This decrease in capitalized interest was driven by decreases in our unevaluated properties since March 31, 2013. Interest expense subject to capitalization increased to $78.7 million in the three months ended March 31, 2014 from $57.4 million in the comparable prior year period. The increase in interest subject to capitalization is attributed to the issuance of our 2022 Notes and our additional 2020 Notes since March 31, 2013.

        We recorded no income tax benefit or expense for the three months ended March 31, 2014 due to the valuation allowance compared to an income tax provision of $3.3 million due to our income before

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taxes of $8.8 million in the comparable prior year period. The effective tax rate for the three months ended March 31, 2014 was 0.0% compared to 37.6% for the three months ended March 31, 2013. The change in effective tax rate is due to the valuation allowance recorded against our net deferred tax assets as of March 31, 2014.

Recently Issued Accounting Pronouncements

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

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments and Hedging Activity

        We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include costless collars, swaps, and put options. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our current and anticipated production for the next 18 to 24 months. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

        We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender or an affiliate of a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, "Derivative and Hedging Activities" for additional information.

        We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Historically, we entered into interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At March 31, 2014 and 2013, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

        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 6, "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

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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 5, "Fair Value Measurements" for additional information.

Interest Rate Sensitivity

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

        At March 31, 2014, total long-term debt was approximately $3.5 billion of which approximately 90% bears interest at a weighted average fixed interest rate of 9.2% per year. The remaining 10% of our total debt balance at March 31, 2014 bears interest at floating or market interest rates that, at our option, are tied to prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At March 31, 2014, the weighted average interest rate on our variable rate debt was 2.5% per year. If the balance of our variable rate debt at March 31, 2014 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.2 million per quarter.

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 March 31, 2014. 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 quarter ended March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

        On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control—Integrated Framework (the 2013 Framework). Originally issued in 1992 (the 1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of March 31, 2014, we continued to utilize the 1992 Framework and will transition to the 2013 Framework by the end of 2014.

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PART II. OTHER INFORMATION

Item 1.    Legal Proceedings

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

Item 1A.    Risk Factors

        There have been no changes to the risk factors described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, except as described below.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

        We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state, tribal and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or in the future plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

        From time to time, for example, legislation has been proposed in Congress to amend the federal Safe Drinking Water Act to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA is conducting a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. In December 2012, the EPA issued a progress report describing its ongoing study, and announcing its expectation that a final draft report will be released for public comment and peer review in 2014. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing, including, for example, a federal Bureau of Land Management rulemaking for hydraulic fracturing practices on federal and Indian lands that has resulted in a May 2013 proposal that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. These activities could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

        Certain states, including North Dakota, Ohio, Pennsylvania, and Texas where we conduct operations, likewise are considering or have adopted more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic monitoring, waste disposal and water use. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have extended to bans on hydraulic fracturing. On December 19, 2013, the Pennsylvania Supreme Court overturned several portions of Pennsylvania's law regulating hydraulic fracturing, allowing local governments in Pennsylvania to regulate hydraulic fracturing through local land use regulations. Other local jurisdictions, including Dallas, Texas and several cities in Colorado, have adopted restrictions on hydraulic fracturing, and anti-hydraulic fracturing activists are seeking more such controls.

        The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively

45

prevent the extraction of oil and gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

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

        At the federal level, the Obama Administration is attempting to address climate change through a variety of administrative actions. The EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and required reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA extended the reporting obligation to oil and natural gas facilities. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting beginning in September 2012. Beyond measuring and reporting, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, the President released a Strategy to Reduce Methane Emissions that includes consideration of both voluntary programs and targeted regulations for the oil and gas sector. Towards that end, the EPA has released five draft white papers on methane and volatile organic compound emissions and mitigation measures for natural gas compressors, hydraulically fractured oil wells, pneumatic devices, well liquids unloading facilities and natural gas production and transmission facilities. The EPA is seeking responses to the white papers and intends to use this process to determine how best to pursue additional emission reductions from the oil and gas sector. Also as part of the President's strategy, the federal Bureau of Land Management is expected to propose standards for reducing venting and flaring on public lands.

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

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

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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.

	Total Number of Shares Purchased(1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 2014		6,271	$	3.43		—		—
February 2014		95,372		3.81		—		—
March 2014		916		3.82		—		—

⁽¹⁾

All of the shares were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards. The acquisitions of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock, nor were they considered as or accounted for as treasury shares.

Item 3.    Defaults Upon Senior Securities

        None.

Item 4.    Mine Safety Disclosures

        Not applicable.

Item 5.    Other Information

        None.

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Item 6.    Exhibits

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

2.1*	Agreement of Sale and Purchase by and among Halcón Energy Properties, Inc., Halcón Field Services, LLC, HK Energy, LLC, Halcón Operating Co, Inc., HK Energy Operating, LLC, and Halcón Resources Operating, Inc., and New Gulf Resources, LLC, dated February 25, 2014.
3.1	Amended and Restated Certificate of Incorporation of RAM Energy Resources, Inc. dated February 8, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed February 9, 2012).
3.2	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of February 10, 2012 (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed February 9, 2012).
3.3	Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated March 2, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed March 5, 2012).
3.4	Certificate of Elimination of 8% Automatically Convertible Preferred Stock dated November 30, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 4, 2012).
3.5	Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated December 5, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 11, 2012).
3.6	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated January 17, 2013 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed January 23, 2013).
3.7	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of May 23, 2013 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed May 29, 2013).
3.8	Certificate of Designations, Preferences, Rights and Limitations of 5.75% Series A Convertible Perpetual Preferred Stock of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed June 18, 2013).
3.9	Certificate of Elimination of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed June 18, 2013).
3.10	Fourth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed November 6, 2012).
4.1	Convertible Promissory Note dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 9, 2012).

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4.2	Warrant Certificate dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed February 9, 2012).
4.3	Registration Rights Agreement dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed February 9, 2012).
4.4	Indenture dated as of July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 9.75% Senior Notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 17, 2012).
4.5	Registration Rights Agreement dated July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed July 17, 2012).
4.6	First Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 2, 2012).
4.7	Second Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed August 2, 2012).
4.8	Registration Rights Agreement dated as of August 1, 2012, among CH4 Energy II, LLC, PetroMax Leon, LLC and Petro Texas LLC and Halcón Resources Corporation (subsequently joined by U.S. King King LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 7, 2012).
4.9	Registration Rights Agreement dated March 5, 2012, between Halcón Resources Corporation and Barclays Capital, Inc. as lead placement agent for the benefit of the initial holders named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed March 5, 2012).
4.10	Registration Rights Agreement dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed November 7, 2012).
4.11	Indenture dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 8.875% Senior Notes due 2021 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed November 7, 2012).
4.12	First Supplemental Indenture dated December 6, 2012, among Halcón Williston I, LLC and Halcón Williston II, LLC, the existing guarantors, Halcón Resources Corporation, the parties named therein as subsidiary guarantors and U.S. Bank National Association, as trustee, relating to the 8.875% senior notes due 2021 (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed December 11, 2012).

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4.13	Third Supplemental Indenture dated December 6, 2012, among Halcón Resources Corporation and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.4 of our Current Report on Form 8-K filed December 11, 2012).
4.14	Registration Rights Agreement dated December 6, 2012, between Halcón Resources Corporation and Petro-Hunt Holdings LLC and Pillar Holdings LLC (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed December 11, 2012).
4.15	First Amendment to Registration Rights Agreement dated December 6, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed December 11, 2012).
4.16	Registration Rights Agreement, dated as of January 14, 2013, between Halcón Resources Corporation and Wells Fargo Securities, LLC, on behalf of the initial purchasers named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed January 15, 2013).
4.17	Waiver, dated July 3, 2013, relating to Registration Rights Agreement dated December 6, 2012 by and among Halcón Resources Corporation and Petro-Hunt Holdings, LLC and Pillar Holdings, LLC (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 10, 2013).
4.18	Indenture dated as of August 13, 2013, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 9.25% Senior Notes due 2022 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 13, 2013).
4.19	Registration Rights Agreement dated as of August 13, 2013, among Halcón Resources Corporation and BMO Capital Markets Corp., on behalf of the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed August 13, 2013).
4.20	Registration Rights Agreement, dated as of December 19, 2013, between Halcón Resources Corporation and Barclays Capital Inc. and Wells Fargo Securities, LLC as the initial purchasers (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed December 20, 2013).
10.1	Seventh Amendment to Senior Revolving Credit Agreement, dated as of March 21, 2014, among Halcón Resources Corporation, as borrower, each of the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed March 27, 2014).
10.2†	Employment Agreement between Charles E. Cusack, III and Halcón Resources Corporation dated November 8, 2012 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed March 27, 2014).
12.1*	Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
31.1*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer
31.2*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer
32*	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
101.INS*	XBRL Instance Document

50

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.

51

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
May 8, 2014	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer
May 8, 2014	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer
May 8, 2014	By:	/s/ JOSEPH S. RINANDO, III
		Name:	Joseph S. Rinando, III
		Title:	Vice President and Chief Accounting Officer

52

EX-2.1

Exhibit 2.1

AGREEMENT OF SALE AND PURCHASE

BY AND AMONG

HALCÓN ENERGY PROPERTIES, INC.,

HALCÓN FIELD SERVICES, LLC,

HK ENERGY, LLC,

HALCÓN OPERATING CO., INC.,

HK ENERGY OPERATING, LLC, AND

HALCÓN RESOURCES OPERATING, INC.,

AS SELLERS,

AND

NEW GULF RESOURCES, LLC

AS PURCHASER

FEBRUARY 25, 2014

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	6
Section 1.4.	Effective Time; Proration of Costs and Revenues	7
Section 1.5.	Delivery and Maintenance of Records	9
ARTICLE 2. PURCHASE PRICE		9
Section 2.1.	Purchase Price	9
Section 2.2.	Adjustments to Purchase Price	10
Section 2.3.	Allocation of Purchase Price	11
Section 2.4.	Deposit	11
Section 2.5.	Tax Allocation	12
ARTICLE 3. TITLE MATTERS		12
Section 3.1.	Sellers’ Title	12
Section 3.2.	Definitions of Title Matters	13
Section 3.3.	Definition of Permitted Encumbrances	15
Section 3.4.	Notice of Title Defect Adjustments	16
Section 3.5.	Casualty or Condemnation Loss	23
Section 3.6.	Limitations on Applicability	24
Section 3.7.	Government Approvals Respecting Assets	24
ARTICLE 4. ENVIRONMENTAL MATTERS		25
Section 4.1.	Assessment	25
Section 4.2.	NORM, Wastes and Other Substances	26
Section 4.3.	Environmental Defects	26
Section 4.4.	Inspection Indemnity	29
ARTICLE 5. REPRESENTATIONS AND WARRANTIES OF SELLERS		30
Section 5.1.	Generally	30
Section 5.2.	Existence and Qualification	30
Section 5.3.	Power	31
Section 5.4.	Authorization and Enforceability	31
Section 5.5.	No Conflicts	31
Section 5.6.	Liability for Brokers’ Fees	32
Section 5.7.	Litigation	32
Section 5.8.	Taxes and Assessments	32
Section 5.9.	Compliance with Laws	32
Section 5.10.	Contracts	33
Section 5.11.	Payments for Hydrocarbon Production	33
Section 5.12.	Governmental Authorizations	34
Section 5.13.	Preference Rights and Transfer Requirements	34
Section 5.14.	Payout Balances	34
Section 5.15.	Outstanding Capital Commitments	34

Section 5.16.	Imbalances				34
Section 5.17.	Condemnation				35
Section 5.18.	Bankruptcy				35
Section 5.19.	Production Allowables				35
Section 5.20.	Foreign Person				35
Section 5.21.	Drilling Obligations				35
Section 5.22.	Obligations to Make Assignments				35
Section 5.23.	No Material Adverse Change				36
Section 5.24.	Suspended Funds				36
Section 5.25.	Gathering Equipment				36
Section 5.26.	Hydrocarbon Marketing				36
ARTICLE 6. REPRESENTATIONS AND WARRANTIES OF PURCHASER					36
Section 6.1.		Existence and Qualification			36
Section 6.2.		Power			37
Section 6.3.		Authorization and Enforceability			37
Section 6.4.		No Conflicts			37
Section 6.5.		Liability for Brokers’ Fees			37
Section 6.6.		Litigation			37
Section 6.7.		Limitation and Independent Evaluation			38
Section 6.8.		SEC Disclosure			38
Section 6.9.		Bankruptcy			38
Section 6.10.		Qualification			39
Section 6.11.		Financing			39
ARTICLE 7. COVENANTS OF THE PARTIES					39
Section 7.1.			Access		39
Section 7.2.			Government Reviews		40
Section 7.3.			Notification of Breaches		41
Section 7.4.			Letters in Lieu; Assignments; Operatorship		42
Section 7.5.			Public Announcements		42
Section 7.6.			Operation of Business		43
Section 7.7.			Preference Rights and Transfer Requirements		44
Section 7.8.			Tax Matters		46
Section 7.9.			Further Assurances		48
Section 7.10.			Notice of Claims		48
Section 7.11.			Enforcement of Third Party Warranties, Guarantees and Indemnities		48
ARTICLE 8. CONDITIONS TO CLOSING					48
Section 8.1.			Conditions of Sellers to Closing		48
Section 8.2.			Conditions of Purchaser to Closing		49
ARTICLE 9. CLOSING					51
Section 9.1.				Time and Place of Closing	51
Section 9.2.				Obligations of Sellers at Closing	51
Section 9.3.				Obligations of Purchaser at Closing	52
Section 9.4.				Closing Adjustments	53

ii

ARTICLE 10. TERMINATION			54
Section 10.1.	Termination		54
Section 10.2.	Remedies		55
ARTICLE 11. POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS; DISCLAIMERS AND WAIVERS			56
Section 11.1.		Receipts	56
Section 11.2.		Expenses	56
Section 11.3.		Assumed Seller Obligations	57
Section 11.4.		Survival and Limitations; Exclusive Remedy	58
Section 11.5.		Indemnification by Each Seller	60
Section 11.6.		Indemnification by Purchaser	61
Section 11.7.		Indemnification Proceedings	61
Section 11.8.		Release	63
Section 11.9.		Disclaimers	64
Section 11.10.		[Intentionally Omitted]	65
Section 11.11.		Recording	65
ARTICLE 12. MISCELLANEOUS			66
Section 12.1.	Counterparts		66
Section 12.2.	Notice		66
Section 12.3.	Sales or Use Tax Recording Fees and Similar Taxes and Fees		67
Section 12.4.	Expenses		67
Section 12.5.	Change of Name		67
Section 12.6.	Replacement of Bonds, Letters of Credit and Guarantees		68
Section 12.7.	Governing Law and Venue		68
Section 12.8.	Captions		68
Section 12.9.	Waivers		68
Section 12.10.	Assignment		68
Section 12.11.	Entire Agreement		68
Section 12.12.	Amendment		69
Section 12.13.	No Third-Party Beneficiaries		69
Section 12.14.	References		69
Section 12.15.	Construction		69
Section 12.16.	Conspicuousness		70
Section 12.17.	Severability		70
Section 12.18.	Time of Essence		70
Section 12.19.	Limitation on Damages		70
Section 12.20.	Suspended Funds		70
Section 12.21.	Joint and Several Liability		71
Section 12.22.	Seller Representative		71

iii

EXHIBITS

Exhibit A	Leases
Exhibit A-1	Wells and Units
Exhibit A-2	Oil and Gas Surface Rights
Exhibit A-3	Oil and Gas Equipment
Exhibit A-4	Gathering System Plat
Exhibit A-5	Gathering Equipment and Midstream Facilities
Exhibit A-6	Midstream Surface Rights
Exhibit B-1	Oil and Gas Conveyance
Exhibit B-2	Oil and Gas Contract Assignment
Exhibit B-3	Midstream Conveyance
Exhibit B-4	Midstream Contract Assignment
Exhibit C	Transition Services Agreement
Exhibit D-1	Halliday Acquisition Area
Exhibit D-2	Johnson Ranch Acquisition Area
Exhibit D-3	AMI I Acquisition Area
Exhibit D-4	AMI II Acquisition Area

SCHEDULES

Schedule 1.2(a)(iv)	Oil and Gas Contracts
Schedule 1.2(a)(x)	Proprietary Seismic Data
Schedule 1.2(a)(xi)	Vehicles

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Schedule 1.2(b)(vi)	Midstream Contracts
Schedule 1.3(d)	Excluded Assets
Schedule 1.4	Overhead Costs
Schedule 2.3	Allocated Values
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	Governmental Authorizations
Schedule 5.13	Preference Rights and Transfer Requirements
Schedule 5.14	Payout Balances
Schedule 5.15	Outstanding Capital Commitments
Schedule 5.16	Imbalances
Schedule 5.21	Drilling Obligations
Schedule 5.22	Obligations to Make Assignments
Schedule 5.24	Suspended Funds
Schedule 5.25	Gathering Equipment
Schedule 5.26	Hydrocarbon Marketing
Schedule 7.6	Operation of Business
Schedule 9.4(d)	Account Information

v

DEFINITIONS

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

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

“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.

“Aggregate Benefit Deductible” has the meaning set forth in Section 3.4(m).

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

“Aggregate Indemnity Deductible” has the meaning set forth in Section 11.4(c).

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

“Agreement” means this Agreement of Sale and Purchase.

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

“Applicable Date” means, with respect to any Title Defect, Environmental Defect, Title Defect Amount, Environmental Defect Amount or the cure of any such defect, if (a) Section 3.4(k)(ii) or Section 4.3(b)(ii) applies in connection with the applicable Title Defect or Environmental Defect, the Scheduled Closing Date and (b) if Section 3.4(k)(iii) or Section 4.3(b)(iii) applies in connection with the applicable Title Defect or Environmental Defect, the Closing Date, or (c) if Section 3.4(k)(iv) applies in connection with the applicable Title Defect, the date of the receipt by Purchaser of curative documents relating to such Title Defect from Sellers.

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

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

“Assumed Midstream Obligations” has the meaning set forth in Section 11.3.

vi

“Assumed Oil and Gas Obligations” has the meaning set forth in Section 11.3.

“Assumed Seller Obligations” has the meaning set forth in Section 11.3.

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

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

“Claim Notice” has the meaning set forth in Section 11.4(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).

“Contracts” means, collectively, the Oil and Gas Contracts and the Midstream Contracts.

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

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

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

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

“Delegated Matters” has the meaning set forth in Section 12.22.

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

“DOJ” means the Department of Justice.

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

“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 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, (ii) the generation, handling, treatment, storage, disposal or transportation of Hazardous Materials or waste materials, (iii) the regulation of or exposure to Hazardous Materials, (iv) the cleanup, restoration, remediation of, or other environmental 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”); the Texas Solid Waste Disposal Act; 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, (in each case) 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, (in each case) 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.

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

“Escrow Agent” means JPMorgan Chase Bank, N.A.

“Escrow Agreement” means that certain Escrow Agreement of even date herewith, by and among Sellers, Purchaser and Escrow Agent.

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

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

viii

“Excluded Seller Obligations” has the meaning set forth in Section 11.3.

“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(c).

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

“FTC” means the Federal Trade Commission.

“Fundamental Representations” has the meaning set forth in Section 11.4(a).

“GAAP” means generally accepted accounting principles in effect in the United States as amended from time to time, consistently applied throughout the periods involved.

“Gathering Equipment” has the meaning set forth in Section 1.2(b)(i).

“Gathering System” has the meaning set forth in Section 1.2(b)(i).

“Governmental Authorizations” has the meaning set forth in Section 5.12.

“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 the 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.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

“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 or at any point of receipt into or any point of

ix

delivery from any pipeline, gathering system, transportation system, processing plant or other location.

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

“Indemnified Party” has the meaning set forth in Section 11.7(a).

“Indemnifying Party” has the meaning set forth in Section 11.7(a).

“Indemnity Agreement” has the meaning set forth in Section 3.4(d)(ii).

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

“Individual Indemnity Threshold” has the meaning set forth in Section 11.4(c).

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

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

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

“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 or loss of profits, except to the extent a party is required to pay such damages to an un-Affiliated 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 timely addresses the condition present at the lowest cost (considered as a whole after 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 or in connection with such response) as compared to any other response that is required or allowed under Environmental Laws.

x

“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 entering into this Agreement or the announcement of the transactions contemplated by this Agreement, (B) Events resulting from changes in general market, economic, financial or political conditions or any outbreak of hostilities or war or terrorist events, (C) 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 that do not have a disproportionate effect on the Assets), (D) any effect resulting from a change in Laws or regulatory policies, (E) matters that are cured by the Closing at no cost or liability to Purchaser and no material diminution in value of any affected Asset, and (F) the depletion or watering out of any Well(s), collapsed casing or sand infiltration of any Well(s), drilling results of any Well(s), and/or the depreciation of personal property due to ordinary wear and tear with respect to the Assets.

“Material Contracts” has the meaning set forth in Section 5.10.

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

“Midstream Contracts” has the meaning set forth in Section 1.2(b)(vi).

“Midstream Contract Assignment” has the meaning set forth in Section 3.1(b).

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

“Midstream Facilities” has the meaning set forth in Section 3.2(l)(a).

“Midstream Records” has the meaning set forth in Section 1.2(b)(viii).

“Midstream Surface Rights” has the meaning set forth in Section 1.2(b)(ii).

“Negative Imbalance” shall mean, respectively as to each Oil and Gas Property and the Gathering System, and without duplication, the sum (expressed in mcf) of (i) the aggregate make-up, prepaid or other volumes of natural gas 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 an Oil and Gas Property after such Effective Time without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent such Seller will be entitled to receive partial payment therefor), and (ii) the aggregate pipeline or processing plant overdelivery Imbalances for which a 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 Asset.

xi

“Net Mineral Acres” means, for each Lease, (x) the number of gross acres in the lands covered by such Lease, multiplied by (y) the interest in oil and gas covered by such Lease in such lands, multiplied by (z) Sellers’ aggregate undivided interest in such Lease insofar as it covers such lands (provided that if items (y) and/or (z) vary as to any tract or tracts of land covered by the Lease, a separate calculation shall be done for each such tract or tracts, as applicable).

“Net Revenue Interest” has the meaning set forth in Section 3.2(1)(a).

“NORM” means naturally occurring radioactive material.

“Notice Period” has the meaning set forth in Section 11.7(a).

“NORM” means naturally occurring radioactive material.

“Notice Period” has the meaning set forth in Section 11.7(a).

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

“Oil and Gas Assets” has the meaning set forth in Section 1.2(a).

“Oil and Gas Contracts” has the meaning set forth in Section 1.2(a)(iv).

“Oil and Gas Contract Assignment” has the meaning set forth in Section 3.1(b).

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

“Oil and Gas Equipment” has the meaning set forth in Section 1.2(a)(vi).

“Oil and Gas Properties” has the meaning set forth in Section 1.2(a)(iii).

“Oil and Gas Records” has the meaning set forth in Section 1.2(a)(ix).

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

“Oil and Gas Surface Rights” has the meaning set forth in Section 1.2(a)(v).

“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” means, collectively, the Oil and Gas Equipment, the Gathering System, the Gathering Equipment and the Midstream Facilities.

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

“Pipelines” has the meaning set forth in Section 1.2(g).

xii

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

“Preference Right” means any right or agreement that enables any Person (other than Purchaser) 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 (ii) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Preliminary Settlement Statement” has the meaning set forth in Section 9.4(a).

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

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

“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 11.5.

“Purchaser’s knowledge” (and any similar knowledge qualification with respect to Purchaser) means matters within the Actual Knowledge of the officers and employees of Purchaser or its Affiliates identified on Schedule 5.1.

“Purchaser’s Representatives” has the meaning set forth in Section 7.1(a).

“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.

“Records” means, collectively, the Oil and Gas Records and the Midstream Records.

“REGARDLESS OF FAULT” MEANS WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY LOSS, EVEN THOUGH A LOSS 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 ANY INDEMNIFIED PERSON; BUT SPECIFICALLY EXCLUDING THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY INDEMNIFIED PERSON; AND/OR

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

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A PRE-EXISTING DEFECT, WHETHER PATENT OR LATENT, IN, ON, UNDER OR WITH RESPECT TO PURCHASER’S PROPERTY OR SELLERS’ 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, AND/OR THIRD PARTIES.

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

“Retained Employee Liabilities” means any liabilities (i) to employees of a Seller arising under the Worker Adjustment Retraining Notification Act of 1988 or otherwise for severance, notice of termination pay or similar entitlements, in any case as a result of actions taken by such Seller at or prior to the Closing, (ii) arising out of claims by Sellers’ employees that relate to their employment with, or the termination 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) or any other plan, program, policy, practice or arrangement providing compensation or employee benefits that is sponsored by, contributed to, required to be contributed to or maintained by, such Seller, or (iv) arising under ERISA for which Purchaser may have any liability under ERISA with respect to the Assets or Sellers’ employees as a result of the consummation of the transactions contemplated by this Agreement.

“Retained Liabilities” means (a) all obligations, liabilities and Losses to the extent that they are attributable to, or arise out of (i) the Retained Employee Liabilities, (ii) the actions, suits or proceedings, if any, set forth on (or required to be set forth on) Schedule 5.7(a), (iii) the disposal or transportation of any Hazardous Materials from the Assets attributable to the time prior to the Closing Date to any location not on the Assets, (iv) the payment of proceeds or other amounts owed to working interest, royalty, overriding royalty and other interest owners relating to the properties and assets underlying the Assets, including with respect to any amounts held in suspense (other than the Suspended Funds), and attributable to the period of time prior to the Closing Date, including any mispayments or allegations of mispayments of such proceeds or amounts attributable to the period of time prior to the Closing Date and any joint interest audits relating to the period of time prior to the Closing Date, (v) any interest or penalties accruing with respect to the Suspended Funds prior to the Closing Date that are payable to the Persons entitled to such Suspended Funds, (vi) actual or claimed personal injury or death or property damage relating to the Assets or operations thereon and attributable to the period of time prior to the Closing Date, (vii) the gross negligence or willful misconduct of any Seller (or an Affiliate of any Seller) in its capacity as operator of the Assets (as distinguished from the duties of any Seller (or Affiliate thereof) as a joint tenant in the properties and assets comprising the Assets), (viii) any fines or penalties imposed by any Governmental Body relating to the Assets, or the ownership or operation thereof, with respect to the period prior to the Closing, excluding any such fines or penalties imposed by any Governmental Body relating to or arising from any Environmental Liability (other than those fine or penalties relating to or arising from (x) the actions, suits or proceedings and other matters set forth on Schedule 5.7(a) or (y) the matters covered by subsection (iii) in this definition of “Retained Liabilities”), and/or (ix) any indenture, mortgage, loan, credit or sale-leaseback, guaranty of any obligation, bond, letter of credit or

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similar financial contract of any Seller or of any its Affiliates, and (b) any liabilities or obligations of Sellers, or otherwise imposed on the Assets, in respect of any Tax, but excluding any ad valorem, property, production, severance or similar Taxes to the extent specifically allocated to Purchaser pursuant to Section 1.4 or Section 7.8, and any Transfer Taxes specifically allocated to Purchaser pursuant to Section 12.3.

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

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

“Seller Indemnified Persons” has the meaning set forth in Section 11.6.

“Seller Operated Assets” means Assets operated by a Seller or an Affiliate of a Seller.

“Seller Representative” has the meaning set forth in Section 12.22.

“Sellers’ knowledge” (and any similar knowledge qualification with respect to Sellers) means matters within the Actual Knowledge of the officers and employees of any Seller or its Affiliates identified on Schedule 5.1, after due investigation, in their individual capacities and as officers and employees of any Seller or its Affiliates.

“Specified Covenant” has the meaning set forth in Section 11.4(e).

“Subject Representatives” has the meaning set forth in Section 1.5.

“Supplemental Acquisition Period” has the meaning set forth in Section 1.2(c).

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

“Supplemental Closing Date” has the meaning set forth in Section 1.2(c).

“Surface Rights” means, collectively, the Oil and Gas Surface Rights and the Midstream Surface Rights.

“Suspended Funds” means all funds which Sellers are holding as of the Closing Date which are owing to third party owners of royalty, overriding royalty, working or other interests in respect of past production of oil, gas or other hydrocarbons attributable to the properties and Assets.

“Target Acreage” means the aggregate number of Net Mineral Acres set forth on Exhibit A for the Leases.

“Tax” or “Taxes” means all federal, state, local, and foreign income, profits, franchise, sales, use, ad valorem, property, severance, production, excise, stamp, documentary, real

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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 or other tax of any kind whatsoever, including any interest, penalties or additional amounts which may be imposed with respect thereto, whether disputed or not and including any obligation to indemnify or otherwise assume or succeed to the Tax liability of any other Person.

“Tax Allocation” has the meaning set forth in Section 2.5.

“Tax Representations” has the meaning set forth in Section 11.4(a).

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

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

“Third Party Claim” has the meaning set forth in Section 11.7(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)(i).

“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 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 Rights or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Surface Rights or interests or they are customarily obtained subsequent to such sale or conveyance (including consents from state agencies).

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

“Transition Services Agreement” has the meaning set forth in Section 9.2(i).

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“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to an 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(a).

“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 Sellers were 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 Sellers are entitled to receive partial payment therefor) and (ii) the aggregate pipeline or processing plant Imbalances or underdeliveries, not described in Schedule 5.16, for which Sellers are obligated as of the Effective Time 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 without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent Sellers are entitled to receive partial payment therefor).

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

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AGREEMENT OF SALE AND PURCHASE

This Agreement of Sale and Purchase (“Agreement”) is executed as of February 25, 2014, by and among HALCÓN ENERGY PROPERTIES, INC. a Delaware corporation (“HEPI”), HALCÓN FIELD SERVICES, LLC, a Delaware limited liability company (“HFS”), HK ENERGY, LLC, a Texas limited liability company (“HK Energy”), HALCÓN OPERATING CO., INC., a Texas corporation (“HOCI”), HK ENERGY OPERATING, LLC, a Texas limited liability company (“HK Energy Operating”), and HALCÓN RESOURCES OPERATING, INC., a Delaware corporation (“Halcón Resources Operating”) (each of HEPI, HK Energy, HOCI, HK Energy Operating and Halcón Resources Operating an “Oil and Gas Seller”; each Oil and Gas Seller and HFS, a “Seller”; and all Oil and Gas Sellers and HFS, collectively, “Sellers”), and NEW GULF RESOURCES, LLC, a Delaware limited liability company (“Purchaser”).

RECITALS

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

B.            Sellers desire to sell to Purchaser and Purchaser desires to purchase from Sellers the properties and rights of each 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 hereto, intending to be legally bound by the terms hereof, agree as follows:

ARTICLE 1.
PURCHASE AND SALE

Section 1.1.               Purchase and Sale.

(a)           At the Closing, and upon the terms and subject to the conditions of this Agreement, each Oil and Gas Seller agrees to sell, assign, transfer and convey its interests in the Oil and Gas Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the interest of each Oil and Gas Seller in the Oil and Gas Assets and to assume the Assumed Oil and Gas Obligations.

(b)           At the Closing, and upon the terms and subject to the conditions of this Agreement, HFS agrees to sell, transfer and convey its interests in the Midstream Assets to Purchaser, and Purchaser agrees to purchase, accept and pay for the interests of HFS in the Midstream Assets and to assume the Assumed Midstream Obligations.

Section 1.2.               Assets.

(a)           As used herein, the term “Assets” means, collectively, the Oil and Gas Assets and Midstream Assets.  As used herein, the term “Oil and Gas Assets” means subject to the terms

and conditions of this Agreement, all of the Oil and Gas Sellers’ right, title, interest and estate, in and to the following (but excluding the Excluded Assets):

(i)            All of the oil and/or 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 and other restrictions as may be set forth in the oil and gas leases or other agreements of record in respect thereof, 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 covered thereby (collectively, the “Leases”), together with each and every kind and character of right, title, claim, interest and estate that each Seller has in and to the lands covered by the Leases and the interests currently pooled, unitized, communitized or consolidated therewith (the “Lands”);

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

(iii)          All  interests of Sellers 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 Oil and Gas Properties and associated with the Wells shown on Exhibit A-1 (the “Units”; the Units, together with the Leases, Lands, and Wells, being hereinafter referred to as the “Oil and Gas Properties”), and including all interests of Sellers in the 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;

(iv)          All contracts, agreements and instruments by which the Oil and Gas Properties are bound or subject, or that relate to or are otherwise applicable to the Oil and Gas Properties, only to the extent applicable to the Oil and Gas Properties rather than the Oil and Gas Sellers’ or any of their 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 Oil and Gas Properties or the production of Hydrocarbons therefrom or allocable thereto, including those identified on Schedule 1.2(a)(iv)(collectively, the “Oil and Gas Contracts”), but excluding any contracts, agreements and instruments to the extent the transfer thereof would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.4, and provided that “Oil and Gas Contracts” shall not include the instruments constituting the Leases;

(v)           All easements (including subsurface easements), permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (collectively, “Oil and Gas Surface Rights”) appurtenant to, and used or held for use exclusively in connection with the Oil and Gas Properties, whether part of the premises covered by the Leases or Units or otherwise (including those identified on Exhibit A-2), but excluding (A) the Midstream Surface Rights and

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(B) any permits and other rights to the extent the transfer thereof would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.4;

(vi)          All equipment, machinery, fixtures and other tangible personal and mixed property and improvements, whether movable or immovable, located either on or off the Oil and Gas Properties and that is used or held for use exclusively in connection with the ownership, use, development, and operation of the Oil and Gas Properties and the production, treatment, gathering, storage, processing, transportation, and marketing of Hydrocarbons produced therefrom or allocable thereto, including those items of personal property and equipment identified on Exhibit A-3 (the “Oil and Gas Equipment”);

(vii)         All Hydrocarbons (A) produced from or allocable to the Oil and Gas Properties and existing in storage tanks or other storage facilities upstream of the delivery points to the relevant purchasers as of the Effective Time, or (B) produced from or allocable to the Oil and Gas Properties from and after the Effective Time;

(viii)        All claims of the Oil and Gas Sellers against other Persons pertaining to Imbalances in existence as of the Effective Time;

(ix)          all lease files, land files, well files, gas and oil sales contract files, gas processing and transportation files, division order files, abstracts, title opinions, title curative, land surveys, logs, cores, maps, engineering data and reports, interpretive data, technical evaluations and technical outputs, operations, production, facility, and environmental records and files, marketing files, property, severance, and production Tax records and files, regulatory compliance records and files (including reports to Governmental Bodies), and other books, records, data, files, and accounting records (including, but not limited to, records showing all funds payable to owners of working interests, royalties, overriding royalties and other interests in the Oil and Gas Properties held in suspense by an Oil and Gas Seller as of the Closing Date), in each case to the extent related to the Oil and Gas Properties, or used or held for use exclusively in connection therewith and in the Oil and Gas Sellers’ possession (the “Oil and Gas Records”);

(x)           Except for Excluded Assets, to the extent transferable, and subject to the payment by Purchaser of all applicable third Person transfer and license fees (the “Seismic License Fee”), all geological, geophysical and other scientific and technical information, samples, tests, reports, maps, and data (including all seismic data, as well as reprocessed data), and interpretations thereof, related exclusively to the Oil and Gas Properties, including those items identified in Schedule 1.2(a)(x);

(xi)          All vehicles identified on Schedule 1.2(a)(xi); and

(xii)         All Suspended Funds payable to owners of working interests, royalties and overriding royalties, and other interests in the Oil and Gas Properties held in suspense by an Oil and Gas Seller as of the Closing Date.

(b)           As used herein, the term “Midstream Assets” means, subject to the terms and conditions of this Agreement, all of HFS’s rights, titles, interests, and estates in and to the following (but excluding the Excluded Assets):

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(i)            The gas gathering system described more particularly on the plat attached hereto as Exhibit A-4 (the “Gathering System”), including all pipelines, trunk lines, laterals, pipeline interconnects and other receipt and delivery facilities, meters, check meters, and metering stations, measurement and regulation equipment, dehydration equipment, compressors and compression facilities and equipment, quality measurement equipment, valves, generators, motors, pumping stations and equipment, cathodic and electrical protection units, bypasses, gas samplers, regulators, drips, flanges, pigs and pig traps, flow control equipment, and other connections, fittings, spare parts, facilities, fixtures, and tangible personal and mixed property and improvements, whether movable or immovable, that are located on or are appurtenant to, or that affect the Gathering System or are used in connection with, installed in or on, or otherwise relate to the ownership and operation of the Gathering System and the gathering and transportation of Hydrocarbons pursuant thereto, including those items of personal property and equipment identified on Exhibit A-5 (collectively, the “Gathering Equipment”);

(ii)           All easements (including subsurface easements), permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (collectively, the “Midstream Surface Rights”) on which the Gathering System is located or that are otherwise appurtenant to, and used or held for use in connection with, the Gathering System (including those identified on Exhibit A-6), but excluding (A) any Oil and Gas Surface Rights and (B) any permits and other rights to the extent the transfer thereof would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.4;

(iii)          All processing plants, fractionation plants, treatment facilities, condensate removal, handling, and stabilization facilities, and other midstream facilities connected to or used in connection with the Gathering System, together with all  equipment, machinery, fixtures, and tangible personal and mixed property and improvements, whether movable or immovable, that are located on, appurtenant to, or used in connection with such midstream facilities and the treatment, storage, and processing of Hydrocarbons pursuant thereto, including those items of personal property and equipment identified on Exhibit A-5 (the “Midstream Facilities”);

(iv)          All gas and other Hydrocarbons present as line pack in the Gathering System as of the Effective Time;

(v)           All fees, rentals, proceeds, payments, revenues, and other rights and economic benefits of every kind and character accruing or payable to the owners of the items listed in this Section 1.2(b) that are attributable to the period from and after the Effective Time;

(vi)          All contracts and agreements to which the items described in clauses (i) through (v) of this Section 1.2(b) are subject or by which such items are bound, or that relate or are otherwise applicable to such items, including Hydrocarbon purchase, sale, exchange, gathering, storage, processing, fractionation, condensate removal, handling, and stabilization, dehydration, treatment, compression, transportation and marketing agreements, communications, facilities, and equipment leases and

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licenses, and balancing agreements, to the extent applicable to the Gathering System, the Midstream Facilities, or the other items listed in this Section 1.2(b), including those identified on Schedule 1.2(b)(vi) (collectively, the “Midstream Contracts”), but excluding any contracts or agreements to the extent transfer would result in a violation of applicable Law or is restricted by any transfer requirement that is not waived by Purchaser or satisfied pursuant to Section 7.4;

(vii)         All field-based electronic field monitoring and field installed communications and computer hardware, networks, and systems used to record, process, and communicate the telemetry associated with the operation of the Gathering System and any other Midstream Facilities, but specifically excluding all software and custom configurations of the same identified in Section 1.3 as Excluded Assets; and

(viii)        All land files, contract files, abstracts, title opinions, policies of title insurance, title curative, land surveys, alignment and other system maps, construction, testing, and inspection records, operations, facility, and environmental records and files, property, severance, and production Tax records and files, regulatory compliance records and files (including reports to Governmental Bodies), and accounting records, in each case to the extent related to the Gathering System, the Midstream Facilities, or the other items listed in this Section 1.2(b), or used or held for use in connection therewith, and in Sellers’ possession (the “Midstream Records”).

(c)           From and after the date of this Agreement and continuing until the date that is sixty (60) days after the Closing Date (as hereinafter defined) (the “Supplemental Acquisition Period”), if Sellers acquire an oil and gas lease on lands located within the boundaries of the maps attached hereto as Exhibit E-1 (Halliday), Exhibit E-2 (Johnson Ranch), Exhibit E-3 (AMI I Prospect) and Exhibit E-4 (AMI II Prospect) (collectively, the “Acquisition Areas”) (collectively, the “Offered Leases”) prior to the expiration of the Supplemental Acquisition Period, then Sellers shall provide Purchaser with written notice of Sellers’ acquisition of such additional Offered Leases prior to the expiration of the Supplemental Acquisition Period, and such notice shall contain: (i) copies of the Offered Lease(s) acquired (and any other conveyances into Sellers covering such acquired Offered Leases), (ii) any ownership and/or title opinions or reports covering the surface and/or mineral estates of the acreage leased, (iii) a statement of the net mineral acres covered thereby, as well as the Net Revenue Interest and Working Interest attributable to such Offered Leases, (iv) a statement or summary of the pooling permitted under such Offered Lease and (v) with respect to Supplemental Properties covering net mineral acres in excess of the Target Acreage, the acquisition costs associated with such Supplemental Properties.  If the Target Acreage has not been attained as of the Closing Date, then until the expiration of the Supplemental Acquisition Period, Purchaser will be obligated to purchase Offered Leases, as they are offered, at $2,586.88 per Net Mineral Acre attributable to such Offered Leases until the Target Acreage is attained.  Notwithstanding anything in this Section 1.2(c) to the contrary, unless waived by Purchaser, Purchaser shall only be obligated to purchase Offered Leases that are in the same respective Acquisition Area as the Leases that are subject to Title Defects asserted in accordance with Article III of this Agreement.  For purposes of clarity (by way of example and not limitation), if there are no Title Defects with respect to any Leases set forth on Exhibit A that are located within Exhibit E-3 (AMI I Prospect) or Exhibit E-4 (AMI II Prospect), then Purchasers shall not be obligated to take any Offered Leases located

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within Exhibit E-3 (AMI I Prospect) or Exhibit E-4 (AMI II Prospect), regardless of whether the Target Acreage has not been obtained as a result of Title Defects to Leases in other areas.  If the Target Acreage has been obtained, either by the Closing Date or as a result of Purchaser purchasing Offered Leases in accordance with this Section 1.2(c), then Purchaser shall have (10) days after receipt of each such written notice to provide Seller with written response notice whether it elects to acquire any of such Offered Leases under the terms and conditions set forth in this Agreement.  Unless otherwise stipulated in the written notice from Sellers to Purchaser, Seller shall be deemed to have represented (and hereby represents) that all such Offered Leases cover lands located within the boundaries of the Acquisition Areas.  Once Offered Leases have been acquired to attain the Target Acreage as provided above (and if applicable), thereafter, Purchaser is under no obligation to acquire any Offered Leases.  To the extent that any Offered Leases are acquired by Sellers after the date of this Agreement and prior to the expiration of the Supplemental Acquisition Period, and Purchaser elects to acquire them, as described above, then there shall be a supplemental closing (the “Supplemental Closing”) on a date mutually agreed to by the Parties, but in no event later than thirty (30) days after the expiration of the Supplemental Acquisition Period (the “Supplemental Closing Date”), at which time, subject to the terms and conditions hereof, Sellers shall sell all of their interests in and to such Additional Leases, together with all related interests related thereto, and otherwise on the terms set forth in this Agreement as modified by this Section with regard thereto (collectively, the “Supplemental Properties”).  All of the representations, warranties and covenants regarding Oil and Gas Properties and the Closing shall apply correspondingly with regard to the Supplemental Properties and the Supplemental Closing (and, without limitation, representations and warranties in Article V shall be deemed to apply with regard to Supplemental Properties), conditions to closing that must be satisfied or waived in connection with the Closing, must likewise be satisfied or waived for purposes of a Supplemental Closing, and notices that must be provided within certain periods prior to or after the Closing in connection with the Properties, will, likewise, be required to be provided within such same periods prior to or after the Supplemental Closing in connection with the Supplemental Properties (and, by way of example, the notices for Title Defects and Environmental Defects regarding the Supplemental Properties shall be due no later than five (5) Business Days prior to the Supplemental Closing).  The purchase price to be paid by Purchasers to Seller for the Supplemental Properties covering Net Mineral Acres in excess of the Target Acreage accepted by Purchaser shall be the acquisition costs incurred by Sellers for the Supplemental Properties plus five hundred dollars ($500) per Net Mineral Acre covered by the Supplemental Properties.  Acquisition costs for Supplemental Properties include landman and brokerage costs, bonuses and other consideration paid, pre-paid surface damages, recording fees, attorneys’ fees for title review, costs of title curative and any other costs incurred by Sellers to acquire Supplemental Properties.

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 Sellers’ obligations under Section 7.1, (i) all corporate, financial, income and franchise tax and legal records of each Seller that relate to such Seller’s business generally (whether or not relating to the Assets), (ii) all books, records and

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files that relate to the Excluded Assets (but only to the extent related to the Excluded Assets), (iii) all geological and geophysical data not transferred by a Seller pursuant to Section 1.2(i), (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, (v) computer or communications software or intellectual property (Clear SCADA, Field Direct, Flow Cal, AES, and other software and custom configurations of the same, as well as all tapes, codes, data and program documentation, and all tangible manifestations and technical information relating thereto), (vi) attorney-client privileged communications and work product of each Seller’s or any of such Seller’s Affiliates’ legal counsel (other than title opinions), (vii) reserve studies and 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 a Seller pursuant to Section 1.5;

(b)           except to the extent related to any Assumed Seller Obligation, all rights to any refund attributable to periods prior to the Effective Time related to the Excluded Seller Obligations or Taxes or other costs or expenses borne by Sellers or Sellers’ predecessors in interest;

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

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

(e)           except to the extent related to any Assumed Seller Obligation, 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;

(f)            all exchange traded futures contracts and over-the-counter derivative or hedge contracts of a Seller;

(g)           all right, title and interest of Sellers in and to vehicles used in connection with the Assets, other than those identified on Schedule 1.2(a)(xi);

(h)           all rights, titles, claims and interests of a Seller or any Affiliate of a 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)            subject to Section 12.5, any patent, patent application, logo, service mark, copyright, trade name or trademark of or associated with a Seller or any Affiliate of a Seller or any business of a Seller or of any Affiliate of a Seller; and

(j)            all Retained Assets not conveyed to Purchaser pursuant to Section 7.7 and any Asset excluded pursuant to Section 3.4, Section 4.3(b) or Section 4.3(d).

Section 1.4.               Effective Time; Proration of Costs and Revenues.

(a)           Subject to Section 1.5, possession of the Assets shall be transferred from Sellers to Purchaser at the Closing, but certain financial benefits and burdens of the Assets shall be

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transferred to and assumed as described below by Purchaser, effective as of 7:00 A.M., local time, where the Assets are located, on April 1, 2014 (the “Effective Time”).

(b)           Purchaser shall be entitled to (i) all Hydrocarbon production from or allocable to the Oil and Gas Properties occurring at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, revenues,  receipts and credits earned with respect to the Oil and Gas Assets at or after the Effective Time, and  all fees, rentals, proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets at or after the Effective Time.  Purchaser shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred with respect to the Assets acquired by Purchaser at and after the Effective Time. Each Seller shall be entitled to its proportionate share of all Hydrocarbon production from or allocable to the Oil and Gas Properties occurring prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, revenues, receipts, and credits earned with respect to the Oil and Gas Assets prior to the Effective Time.  HFS shall be entitled to all fees, rentals, proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets prior to the Effective Time.  Each Seller shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred with respect to the Assets owned by such Seller prior to the Effective Time.

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

(d)           As used in this Agreement, the term “Property Costs” means all costs attributable to the ownership and operation of the Assets (including costs of insurance relating specifically to the Assets, but excluding all applicable Taxes) and capital expenditures incurred in the ownership and operation of the Assets, and in the case of the Oil and Gas Assets, where applicable, in accordance with the terms of the relevant operating or unit agreement, if any, overhead costs charged to the Oil and Gas Assets under such operating or unit agreement, if any, and regardless of whether charged by an Affiliate of a Seller or by a third Person, or, if none, the amounts shown under Schedule 1.4 shall be the overhead amounts deemed charged to the Oil and Gas Assets.

(e)           For purposes of this Section 1.4, the 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) and other revenues and income under this Section 1.4, (A) liquid Hydrocarbons shall be deemed to be “from or allocable to” the Oil and Gas Properties when such Hydrocarbons are placed into the storage facilities, and (B) gaseous Hydrocarbons shall be deemed to be “from or allocable to” the Oil and Gas Properties when such Hydrocarbons pass through the delivery point sales meters on the pipelines through which they are gathered or, if not first gathered, transported.

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(f)            Sellers shall utilize reasonable interpolative procedures to arrive at an allocation of Hydrocarbon production when exact meter readings or gauging and strapping data is not available. Sellers have provided to Purchaser all data available to Sellers as of five (5) Business Days prior to the Closing Date to support the estimated allocation, for purposes of establishing the adjustments to the Oil and Gas Purchase Price and the Midstream Purchase Price pursuant to Section 2.2, used to determine the Closing Payment. Property Costs 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 production, severance and similar Taxes shall be prorated based on the number of units actually produced, purchased, or sold, or the proceeds of such sale, as applicable, before, and at or after, the Effective Time. In each case, each Purchaser shall be responsible for the portion attributable to the Assets acquired by such Purchaser allocated to the period at and after the Effective Time, and each Seller shall be responsible for the portion attributable to the Assets owned by such Seller allocated to the period before the Effective Time.

Section 1.5.               Delivery and Maintenance of Records.

Sellers shall deliver the Records (FOB at Sellers’ office) to Purchaser within thirty (30) days following Closing.  Purchaser shall be entitled to all original Records maintained by Sellers. Sellers shall be entitled to keep copies of all Records; provided, however, that from and after the Closing and except in connection with its obligations under this Agreement, each Seller shall not, and shall cause its respective Affiliates and its and their respective officers, directors, employees, agents, accountants, attorneys, investment bankers, consultants, advisors and other authorized representatives (with respect to each Seller, the “Subject Representatives”) not to, disclose, permit to be disclosed, use, permit to be used, copy or permit to be copied, the Records or any trade secrets or proprietary or confidential information to the extent relating to the Assets, except for (i) disclosures and uses required by applicable Law or stock exchange rules or of information that has become part of the public domain through no action of any Seller or any Subject Representative after the Closing, and (ii) disclosures to financial institutions or other third Persons in connection with the evaluation of financing or a sales or acquisition transaction provided that such financial institution or other third Person is bound by a reasonable obligation of confidentiality covering such information.  Purchaser shall preserve the Records for five years following the Closing in Purchaser’s offices in accordance with Purchaser’s record retention policy following the Closing and, subject to the foregoing confidentiality obligations, will allow each Seller and their respective representatives, consultants and advisors reasonable access, during normal business hours and upon reasonable notice, to the Records in order for a Seller to comply with a Tax or other legally required reporting obligation or Tax or legal dispute with an un-Affiliated third party for which such Seller is responsible.  Any such access shall be at the sole cost and expense of such Seller.

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ARTICLE 2.
PURCHASE PRICE

Section 2.1.               Purchase Price.

The purchase price for the Assets (the “Purchase Price”) shall be $450,000,000.00, 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 actually received by Sellers between (and including) the Effective Time and the Closing Date (with the period between and including the Effective Time up to 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 Sellers by the purchaser of production) produced from or attributable to the Assets 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 Aggregate 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)  subject to the Individual Title Benefit Threshold and Aggregate Benefit Deductible, 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 and other costs attributable to the ownership and operation of the Assets which are paid by Sellers and incurred during the Adjustment Period (including any overhead costs listed on Schedule 1.4 deemed charged to the Assets with respect to the Adjustment Period even though not actually paid), except (i) any Property Costs and other such costs already deducted in the determination of proceeds in Section 2.2(a), (ii) any costs incurred by Sellers in connection with curing any Title Defect or Environmental Defect or with respect to any casualty loss and (iii) any costs incurred as a result of any breach by any Sellers of this Agreement;

(e)           Reduced to the extent provided in Section 3.4(d)(iii) for any Oil and Gas Properties excluded from the Assets pursuant to Section 3.4(d)(iii) or retained by Sellers pursuant to Section 3.4(d)(iii) and reduced to the extent provided in Section 4.3 for Environmental Defects or Assets retained by Sellers pursuant to Section 4.3;

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

(g)           To the extent the proceeds from the sale thereof have not been received by Sellers, increased by the value of the amount of any and all Hydrocarbons stored in tanks above the load level and in pipelines above the sales meter attributable to the ownership and operation

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of the Assets that belong to Sellers as of the Effective Time (which value shall be computed by Sellers at the applicable third-party contract prices for the month of January 2014 for such stored Hydrocarbons);

(h)   (x) Reduced by the product obtained by multiplying the aggregate amount of Unscheduled (Negative) Imbalances by $3.00 per mcf; and (y) increased by the product obtained by multiplying the aggregate amount of Unscheduled (Positive) Imbalances by $3.00 per mcf;

(i)Reduced by the Deposit (as described in Section 2.4 below);

(j)            Reduced by an amount equal to all Suspended Funds;

(k)           Reduced by the amount of payments required for any lease extension, delay rental or lease renewal relating to Leases which expire on or before December 31, 2014 and which have not been paid by Sellers prior to Closing;

(l)            Increased by the costs and expenses attributable to the Champion Ranch 1H well in Leon County, Texas that is required to be spud prior to April 20, 2014 in order to hold approximately 798 acres of Champion Ranch property, regardless of whether such costs and expenses are incurred prior to the Effective Date, provided that such increase to the Purchase Price shall be limited to 120% of the costs and expenses set forth in the AFE provided by Purchaser to Sellers related thereto;

(m)          Reduced by a mutually agreeable amount for the Seismic License Fee; and

(n)           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 Oil and Gas 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 assigned to the Assets are set forth on Schedule 2.3.  Purchaser shall be responsible for assigning the Allocated Values included on Schedule 2.3, subject to each Seller’s right to review the Allocated Values for reasonableness.

Section 2.4.               Deposit.

A deposit in the amount of $9,000,000.00 (the “Deposit”) shall be paid on or before one (1) Business Day after execution of this Agreement by Purchaser, by wire transfer in immediately available funds, to Escrow Agent to be held pursuant to the terms and conditions of the Escrow Agreement.  The Deposit shall be credited to the Purchase Price to be paid by

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Purchaser at the Closing.  In the event the transaction contemplated hereby is not consummated in accordance with the terms hereof as a result of Purchaser’s breach of its obligations hereunder, Sellers shall be entitled to receive the Deposit as liquidated damages and Sellers’ sole and exclusive remedy for the failure of the transaction to be consummated in accordance with the terms hereof and Purchaser shall execute Joint Instructions (as defined in the Escrow Agreement) consistent with the foregoing and deliver them to the Escrow Agent.  If the transaction contemplated hereby is not consummated due to (i) material breach of Sellers’ obligations hereunder, (ii) the failure of the conditions precedent to the obligations of Purchaser in Section 8.2 to be satisfied or waived in writing by Purchaser, (iii) Sellers’ termination of this Agreement pursuant to Section 10.1(e), (iv) termination of the Agreement pursuant to Section 10.1(a), (v) termination of this Agreement in accordance with Section 10.1(b), Section 10.1(d) or Section 10.1(f), or (vi) any other reason except Purchaser’s breach of this Agreement, then Purchaser shall be entitled to have the Deposit released back to Purchaser by Sellers by wire transfer in immediately available funds, pursuant to written instructions to be delivered by Purchaser to Sellers.  Notwithstanding anything in this Agreement to the contrary, if Purchaser fails to deliver the Deposit to Escrow Agent within one (1) Business Day following the execution of this Agreement, Sellers shall be entitled to immediately terminate this Agreement and pursue one or more of any and all remedies as may be available to Sellers at law or in equity, including specific performance.

Section 2.5.               Tax Allocation.

The Allocated Value shall apply to Sellers and Purchaser for purposes of Section 1060 of the Code and the Treasury Regulations promulgated thereunder (and any similar provision of state, local or foreign law, as appropriate) and shall be determined in accordance with Section 1060 of the Code and the Treasury Regulations promulgated thereunder (the “Tax Allocation”).  If the Purchase Price is adjusted pursuant to this Agreement, the Tax Allocation shall be adjusted in a manner consistent with the procedures set forth in this Section 2.5 by Purchaser.  Purchaser and Sellers shall file all Tax Returns (including, but not limited to, Internal Revenue Service Form 8594) consistent with the Tax Allocation.  Neither Purchaser nor Sellers shall take any Tax position in consistent with such Tax Allocation and neither Purchaser nor Sellers shall agree to any proposed adjustment to the Tax Allocation by any Taxing authority without first giving the other party prior written notice; provided, however, that nothing contained herein shall prevent Purchaser or Sellers from settling any proposed deficiency or adjustment by any Taxing authority based upon or arising out of the Tax Allocation, and neither Purchaser nor Sellers shall be required to litigate before any court any proposed deficiency or adjustment by any taxing authority challenging such Tax Allocation.

ARTICLE 3.
TITLE MATTERS

Section 3.1.               Sellers’ Title.

(a)           Except for the special warranty of title contained in each Conveyance, SELLERS MAKE NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED,

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STATUTORY OR OTHERWISE, WITH RESPECT TO SELLERS’ 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 AND UNDER THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE.

(b)           Sellers shall convey the Assets to Purchaser pursuant to the execution and delivery by Sellers to Purchaser, at the Closing, of an Assignment, Bill of Sale, and Conveyance (Oil and Gas Assets) (the “Oil and Gas Conveyance”), an Assignment of Contracts and Contract Rights (Oil and Gas Contracts) (the “Oil and Gas Contract Assignment”), an Assignment, Bill of Sale, and Conveyance (Midstream Assets) (the “Midstream Conveyance”), and an Assignment of Contracts and Contract Rights (Midstream Contracts) (the “Midstream Contract Assignment”) substantially in the forms attached hereto as, respectively, Exhibit B-1, Exhibit B-2, Exhibit B-3, and Exhibit B-4 (each a “Conveyance” and, collectively, the “Conveyances”).  Each Conveyance will contain a limited warranty of title as set forth therein with respect to the portion of the Assets covered thereby, subject, however, to the Permitted Encumbrances, and will grant to Purchaser full rights of substitution and subrogation in and to all rights and actions of warranty of title which each Seller has or may have against all preceding owners and vendors relating to the relevant Assets.  Except for such limited warranties of title set forth in the Conveyances, Sellers make no warranty or representation, express, implied, statutory or otherwise, with respect to any Seller’s title to any of the Assets.

Section 3.2.               Definitions of Title Matters.

As used in this Agreement, the term “Defensible Title” means that title of Sellers with respect to the Units, Wells or other Assets, except for and subject to Permitted Encumbrances that as of the Effective Time and the Closing which:

(a)           Entitles Sellers to receive an interest (expressed as a percentage or decimal fraction) of the Hydrocarbons produced, saved and marketed from any Unit, Well or other Asset shown in Exhibit A-1 as to all depths unless otherwise indicated on Exhibit A-1 (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 for such Unit, Well or other Asset, except (solely to the extent that such actions do not cause a breach of Sellers’ covenants under Section 7.6(a)) for decreases resulting from the establishment or amendment from and after the date hereof of pools or units, and except as stated in such Exhibit A-1;

(b)           Obligates Sellers to bear a percentage of the costs and expenses for the maintenance and development of, and operations relating to, (i) any Unit, Well or other Asset shown in Exhibit A-1 (including the formation(s) set forth on Exhibit A-1 for such Unit, Well or other Asset) not greater than the “working interest” percentage shown in Exhibit A-1 for such Unit, Well or other Asset, without increase throughout the period when such Unit, Well or other Asset is, except as stated in Exhibit A-1 and except for increases from and after the date hereof resulting from contribution requirements with respect to non-consenting or defaulting co-owners

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under applicable operating agreements and increases that are accompanied by at least a proportionate increase in such Seller’s Net Revenue Interest;

(c)           Is free and clear of liens, encumbrances, obligations, security interests, irregularities, pledges, or other defects;

(d)           Entitles Sellers to the following: (i) no less than the number of Net Mineral Acres set forth on Exhibit A for the Leases as to all depths, unless otherwise indicated on Exhibit A, (ii) no less than 16,000 Net Mineral Acres of Leases that are held by production, and (iii) a Net Revenue Interest of no less than 75% in any Lease which is not currently held by production; and

(e)           Does not subject Sellers to the following: more than 6,650 Net Mineral Acres of Leases having depth limitations of any kind, provided however that, for purposes of clarity, a Lease shall not be deemed to have “depth limitations” solely as a result of the existence of a Pugh clause that has not resulted in any severance of depths as of the Closing.

As used in this Agreement, the term “Title Defect” means any of the following: any lien, charge, encumbrance, obligation (including contract obligation), defect, or other matter (including without limitation a discrepancy in Net Revenue Interest or working interest) that causes the applicable Seller not to have Defensible Title.  Notwithstanding the foregoing, the following shall not be considered Title Defects:

(i)            defects based solely on lack of information in such Seller’s files unless information in the records of the applicable county reflect that any information in Seller’s files is incorrect;

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

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

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

(v)           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 causes Purchaser to reasonably believe that such failure or omission has resulted in another Person’s superior claim of title;

(vi)          defects that have been cured by applicable Laws of limitation or prescription; and

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(vii)         defects based solely on claims that a Well was drilled pursuant to an “allocation well” permit or the failure to obtain a production sharing agreement, as allowed by the Railroad Commission of Texas.

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  Sellers in any Unit, Well or other Asset shown on Exhibit A-1, without causing a greater than proportionate increase in Sellers’ working interest above that shown in Exhibit A-1 as of the Effective Time.

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 on production, to the extent that any such burden does not reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 or increase Sellers’ working interest above that shown in Exhibit A-1 without a proportionate increase in the corresponding Net Revenue Interest;

(b)           All Leases, unit agreements, pooling agreements, operating agreements, Hydrocarbon production sales contracts, division orders and other contracts, agreements and instruments applicable to or affecting the Assets, to the extent that they do not, individually or in the aggregate, (i) reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 or increase Sellers’ working interest above that shown in Exhibit A-1 without a proportionate increase in the corresponding Net Revenue Interest or (ii) 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) and which would be considered acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

(c)           Preference Rights applicable to this or any future transaction;

(d)           Transfer Requirements applicable to this or any future transaction;

(e)           Liens for current Taxes not yet due and payable;

(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, (in each case) that are not delinquent (including any amounts being withheld as provided by Law) and that will be paid in the ordinary course of business;

(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

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pursuant to this or to any future transaction if they are not required and are not customarily obtained prior to such a sale or conveyance;

(h)           Excepting circumstances where such rights have already been triggered, 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 (i) reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 or increase Sellers’ working interest above that shown in Exhibit A-1 without a proportionate increase in the corresponding Net Revenue Interest or (ii) 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) and which would be considered acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

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

(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;

(l)            Imbalances associated with the Assets; and

(m)          Liens granted under applicable joint operating agreements and other similar agreements for amounts that are not delinquent.

Section 3.4.               Notice of Title Defect Adjustments.

(a)           To assert a claim of a Title Defect prior to Closing, Purchaser must deliver claim notices to Sellers (each a “Title Defect Notice”) on or before April 11, 2014 at 5:00 p.m. C.S.T. (the “Title Claim Date”); provided, however, that Purchaser agrees that it shall furnish Sellers once at the end of every two (2) week period until the Title Claim Date with a preliminary Title Defect Notice if any officer of Purchaser or its Affiliates discovers or learns of any Title Defect during such two (2) week period, which notice may be preliminary in nature and supplemented prior to the expiration of the Title Claim Date; provided further that failure to provide preliminary notice of a Title Defect shall not prejudice Purchaser’s right to assert any Title Defect hereunder on or before the Title Claim Date.  To be effective, each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect(s), (ii)  Leases, Units, Wells or other Assets in Exhibit A or Exhibit A-1, as applicable, affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents reasonably necessary for Sellers to verify the existence of and extent of such Title Defect and the amount by which the Allocated Value of each affected Asset is increased by such Title Defect, provided, however, that the sufficiency or volume of documents

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delivered pursuant to this Section 3.4(a)(iv) shall not serve as any basis to dispute the validity of the Title Defect Notice, 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. EXCEPT FOR PURCHASER’S RIGHTS UNDER THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE, PURCHASER SHALL BE DEEMED TO HAVE WAIVED ITS RIGHT TO ASSERT TITLE DEFECTS OF WHICH EACH SELLER HAS NOT BEEN GIVEN NOTICE ON OR BEFORE THE TITLE CLAIM DATE.

(b)           Sellers 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”), which notice to be effective shall include (i) a description of the alleged Title Benefit, (ii) the Leases, Units, Wells or other Assets in Exhibit A or Exhibit A-1, as applicable, affected by such Title Benefit, (iii) the Allocated Value of each Lease, Unit, Well or other Asset in Exhibit A or Exhibit A-1, as applicable, subject to such Title Benefit, (iv) supporting documents reasonably necessary for Purchaser to verify the existence of and extent of such Title Benefit and the amount by which the Allocated Value of each affected Asset is increased by such Title Benefit, provided, however, that the sufficiency or volume of documents delivered pursuant to this Section 3.4(b)(iv) shall not serve as any basis to dispute the validity of the Title Defect Notice, and (v) the amount by which Sellers reasonably believe the Allocated Value of each affected Asset is increased by such Title Benefit and the computations and information upon which Sellers’ belief is based.

(c)           Sellers 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 Sellers have been advised in writing by Purchaser.  Any asserted Title Defects which are cured within the Cure Period or waived in writing 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 in writing or cured on or before Closing, the parties hereto shall mutually agree upon one of the following remedies for such Title Defect:

(i)            subject to the Individual Title Threshold and the Aggregate Defect Deductible, have the Purchase Price reduced by an amount agreed upon (“Title Defect Amount”) pursuant to Section 3.4(g) by Purchaser and Sellers as being the value of such Title Defect, taking into consideration the Allocated Value of the Property affected by such Title Defect, the portion of the Property affected by such Title Defect and the legal effect of such Title Defect on the Property affected thereby; provided, however, that the methodology, terms and conditions of Section 3.4(g) shall control any such determination;

(ii)           have Sellers indemnify Purchaser against all liability, loss, cost and expense resulting from such Title Defect pursuant to an indemnity agreement (the “Indemnity Agreement”) in the form attached hereto as Exhibit C; or

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(iii)          have Sellers retain the entirety of the Property that is affected by such Title Defect, together with all Assets solely related to such Property, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Property and related Assets.  Thereafter, Sellers shall have 180 days after Closing in which to cure the Title Defect with respect to such retained Property and related Assets.  Any Property and related Assets so held back from the initial Closing and retained by Sellers will be conveyed to Purchaser (subject to the satisfaction of the conditions set forth in Section 8.2 with respect to such Property and related Assets) at a delayed Closing (which shall become the new Closing Date with respect to such Property and related Assets) ten (10) Business Days following the date that the Title Defect is cured, at which time Purchaser shall pay to Sellers the full Allocated Value of the Property and related Assets (as adjusted pursuant to Section 2.2 through the new Closing Date therefor), 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 with respect to certain Assets pursuant to this Section 3.4(d)(iii) shall not waive Sellers’ right to dispute the existence of a Title Defect or to contest the Title Defect Amount asserted with respect thereto.  In the event that Sellers are unable to cure the Title Defect with respect to any Property and related Assets held back at the initial Closing within 180 days of the initial Closing, then Sellers shall retain the Property and related Assets affected thereby, such Property and related Assets shall become Excluded Assets hereunder and Purchaser shall have no further obligation to purchase such Property and related Assets.  Any disputes regarding whether such Title Defect has been cured by Sellers within such 180 day cure period shall be resolved pursuant to Section 3.4(k) (provided that the Title Expert shall be selected within fifteen (15) Business Days following the end of the 180 day cure period with respect to such dispute and all other provisions of Section 3.4(k) shall apply as written).

In the event Sellers and Purchaser are unable to mutually agree upon a remedy for any asserted Title Defect prior to Closing, then Sellers and Purchaser shall be deemed to have selected the remedy set forth in Section 3.4(d)(i).  In the event Sellers and Purchaser mutually agree to select the remedy set forth in Section 3.4(d)(i) (or are deemed to have selected such remedy in accordance with the foregoing sentence) but are unable to agree on the Title Defect Amount by the Scheduled Closing Date, then unless the Parties otherwise mutually agree in writing the dispute shall be resolved pursuant to the provisions of Section 3.4(k).

(e)           Subject to the Individual Title Benefit Threshold and the Aggregate Benefit Deductible, with respect to each Lease, Unit, Well or other Asset in Exhibit A or Exhibit A-1, as applicable, 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 Lease, Unit, Well or other Asset in Exhibit A or Exhibit A-1, as applicable, caused by such Title Benefits, as determined pursuant to Section 3.4(j).  In the event that Purchaser and Sellers are unable to agree on the Title Benefit Amount, the affected Assets will nevertheless be conveyed to Purchaser at Closing with no increase to the Purchase Price for such

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Title Benefit, subject to Sellers’ right to a subsequent adjustment in the Purchase Price for such Title Benefit as may result under the provisions of Section 3.4(k), or as may otherwise be agreed to by the parties.

(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).  Section 3.4(e) shall be the exclusive right and remedy of Sellers with respect to Title Benefits asserted by Sellers 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 (determined in accordance with Schedule 2.3) 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 Sellers 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 affecting the Title Defect Property;

(iii)          if the Title Defect results from a Seller having a lesser Net Revenue Interest in such Title Defect Property than the Net Revenue Interest specified therefor in Exhibit A-1 (or less than 75% with respect to any Lease not currently held by production) and there is a proportional decrease in the working interest for the affected Title Defect Property 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 (determined in accordance with Schedule 2.3) 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;

(iv)          if the Title Defect results from a Seller owning fewer Net Mineral Acres in such Title Defect Property than the Net Mineral Acres specified therefor in Exhibit A, 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 (determined in accordance with Schedule 2.3) by a fraction, the numerator of which is the reduction in Net Mineral Acres and the denominator of which is the number of Net Mineral Acres specified for such Title Defect Property in Exhibit A;

(v)           if the Title Defect results from a Seller owning fewer than 16,000 Net Mineral Acres of Leases that are held by production, the Title Defect Amount shall be equal to the product obtained by multiplying $2,586.88 by a fraction, the numerator of which is the reduction below 16,000 in Net Mineral Acres of Leases held by production and the denominator of which is 16,000;

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(vi)          if the Title Defect results from a Seller owning more than 6,650 Net Mineral Acres of Leases having depth limitations of any kind, the Title Defect Amount shall be equal to the product obtained by multiplying $2,586.88 by a fraction, the numerator of which is the excess above 6,650 in the Net Mineral Acres subject to depth restrictions, and the denominator of which is 6,650;

(vii)         if the Title Defect results from any matter not described in subsections (i), (ii), (iii), (iv), (v) or (vi) 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 accordance with Schedule 2.3 to such Title Defect Property and the cost to cure such Title Defect if such Title Defect is reasonably susceptible of being cured);

(viii)        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; and

(ix)          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 such Title Defect Property.

(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 Lease, Unit, Well or other Asset, the amount by which the value of the affected Lease, Unit, Well or other Asset is enhanced by virtue of such Title Benefit, which amount shall be determined as follows:

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

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(ii)           If the Title Benefit Amount results from a Seller having a greater Net Revenue Interest in such Unit, Well or other Asset than the Net Revenue Interest specified therefor in Exhibit A-1 with a proportional increase in the working interest of the affected Unit, Well or other Asset, 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 other Asset (determined in accordance with Schedule 2.3) 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 other Asset in Exhibit A-1.

(iii)          if the Title Benefit results from a Seller owning greater Net Mineral Acres in such Lease than the Net Mineral Acres specified therefor in Exhibit A, the Title Benefit Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Lease (determined in accordance with Schedule 2.3) by a fraction, the numerator of which is the increase in Net Mineral Acres and the denominator of which is the number of Net Mineral Acres specified for such Title Defect Property in Exhibit A;

(iv)          If the Title Benefit results from any matter not described in subsections (i), (ii) or (iii) above, the Title Benefit Amount shall be an amount equal to the difference between the value of the Property affected by such Title Benefit and the value of such Property without such Title Benefit (taking into account the portion of the Purchase Price allocated to such Property in accordance with Schedule 2.3).

(v)           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)           Sellers and Purchaser shall attempt in good faith to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts prior to the Scheduled Closing Date.  If Seller and Purchaser are unable to agree by the Scheduled Closing Date, the Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved pursuant to this Section 3.4(k); in addition, should the parties dispute whether or not any Title Defect has been cured by Sellers, such dispute shall be exclusively and finally resolved pursuant to this Section 3.4(k), in each case as follows:

(i)            (i)            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 relevant Oil and Gas Properties are located and who shall not have performed professional services for either party or any of their respective Affiliates during the previous three (3) years, as selected by mutual agreement of Purchaser and Sellers within fifteen (15) Business Days after the Applicable Date (and absent such agreement, by the Houston office of the American Arbitration Association) (the “Title Expert”). Within ten (10) Business Days following the selection of the Title Expert, each of Purchaser, on the one hand, and Sellers, on the other hand, shall submit to the Title Expert

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written explanations of their respective positions in the disputed title matters.  The Title Expert’s determination shall be made within fifteen (15) Business Days after submission of the title 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 provisions of this Article 3, 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 Title Expert, including without limitation petroleum engineers.  The Title Expert shall act as an expert for the limited purpose of determining the specific disputed title matters submitted by either party and may not award damages, interest or penalties to any party with respect to any matter.  Sellers and Purchaser shall each bear their 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 Sellers and one-half by Purchaser, including any costs incurred by the Title Expert that are attributable to such third party consultation.

(ii)           If the Title Defect Amounts alleged by Purchaser that are applicable to the disputed title matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f)  and Section 8.2(f) (including any Environment Defect Amounts alleged by Purchaser pursuant to Section 4.3) that are not resolved prior to the Scheduled Closing Date, exceed twenty percent (20%) of the Purchase Price, then the date for Closing shall be extended until the disputed title matters are resolved pursuant to Section 3.4(k)(i).  Upon resolution of such disputed title matters pursuant to Section 3.4(k)(i), then, subject to the other terms and conditions of this Agreement, the Closing shall occur on the tenth (10th) Business Day following the date upon which the Title Expert delivers written notice to Purchaser and Sellers of his determination with respect to any disputed title matters, including any applicable Title Defect Amount or a Title Benefit Amount.

(iii)          If the Title Defect Amounts alleged by Purchaser that are applicable to the disputed title matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f) and Section 8.2(f) (including any Environment Defect Amounts alleged by Purchaser pursuant to Section 4.3), are equal to or less than twenty percent (20%) of the Purchase Price, then the affected Assets will nevertheless be conveyed to Purchaser at Closing with no reduction in the Purchase Price for any such Title Defect and a portion of the Purchase Price equal to the disputed Title Defect Amount alleged by Purchaser shall be placed in escrow by Purchaser pursuant to an escrow agreement in a form to be mutually agreed upon by Seller Representative, Purchaser and JP Morgan Chase Bank, NA as escrow agent. The Purchase Price shall be subject to a subsequent adjustment

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for any such Title Defect upon the resolution of such disputed title matters pursuant to Section 3.4(k)(i) or as may be otherwise be mutually agreed by the parties.  Upon such resolution of such disputed title matters pursuant to Section 3.4(k)(i), then (A) Purchaser and Seller Representative shall instruct escrow agent to deliver to Sellers the amount, if any, so awarded by the Title Expert to Sellers, plus interest accrued on such amount pursuant to the terms of the Escrow Agreement, if any, and (B) Purchaser and Seller Representative shall instruct escrow agent to pay to Purchaser the amount, if any, so awarded by the Title Expert to Purchaser, plus interest accrued on such amount pursuant to the terms of the escrow agreement, if any.

(iv)If any title disputed matter under this Article 3 relates to whether or not any Title Defect has been cured post-Closing pursuant to Section 3.4(d)(iii), then such title disputed matter shall be resolved pursuant to the determination of the Title Expert pursuant to Section 3.4(k)(i).

(l)Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for any individual uncured Title Defect affecting a Title Defect Property for which the Title Defect Amount therefor does not exceed $15,000 (“Individual Title Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers 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 0.5% of the unadjusted Purchase Price (“Aggregate 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 and uncured Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts are in excess of such Aggregate Defect Deductible; for the avoidance of doubt, Title Defect Amounts and Environmental Defect Amounts which do not meet the Individual Title Threshold and the Individual Environmental Threshold shall not be included in reaching the Aggregate Defect Deductible.

(m)Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual Title Benefit for a Property for which the Title Benefit Amount therefor does not exceed $15,000 (“Individual Title Benefit Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price for Title Benefits unless the aggregate Title Benefits attributable to all Title Benefits exceeds a deductible in an amount equal to 0.5% of the unadjusted Purchase Price (“Aggregate Benefit Deductible”), after which point adjustments to the Purchase Price shall be made available to Sellers only with respect to Title Benefits where the aggregate Title Benefit Amounts are in excess of such Aggregate Benefit Deductible; for the avoidance of doubt, Title Benefit Amounts which do not meet the Individual Title Benefit Threshold shall not be included in reaching the Aggregate Benefit Deductible.

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Section 3.5.Casualty or Condemnation Loss.

(a)From and after the Effective Time, but subject to the provisions of Section 3.5(b), Purchaser shall assume all risk of loss with respect to 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, Sellers shall promptly notify Purchaser in writing of the nature and extent of such casualty loss or government taking and Sellers’ 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 or threatened to be 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 required to repair or replace that portion of the Assets affected by the casualty loss or the agreed value of the Assets taken or threatened to be taken by the government, and the parties will proceed with Closing, subject to the other terms and conditions of this Agreement; provided that if the parties mutually agree, in lieu of adjustments to the Purchase Price, Sellers shall (i) pay over to Purchaser: (A) all insurance proceeds payable to Sellers with respect to any such casualty loss (if applicable), (B) all sums paid to Sellers by third parties by reason of any such casualty loss (if applicable), and (C) all compensation paid to Sellers with respect to any such government taking (if applicable), and (ii) assign to Purchaser any and all claims that Seller may have against any third party with respect to such casualty loss or government taking, as applicable.

Section 3.6.Limitations on Applicability.

The right of Purchaser to assert a Title Defect under this Agreement and Sellers’ 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 Sellers’ 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 and State Approvals. Purchaser shall, within thirty (30) days after Closing and at Purchaser’s own expense, file for approval with the applicable Governmental Bodies all assignment documents and other state and federal transfer documents required to effectuate the transfer of the Assets representing state or federal Leases or other Lands.  Purchaser further agrees, promptly after Closing, to take all other actions reasonably required of Purchaser by federal or state agencies having jurisdiction to obtain all requisite regulatory approvals with respect to this transaction with respect to Assets representing state or federal Leases or other Lands, and to use its commercially reasonable efforts to obtain such approval by such federal or state agencies, as applicable, of Sellers’ assignment documents requiring such federal or state approval in order for Purchaser to be recognized by the federal or state agencies as the owner of the Assets representing state or federal Leases or other Lands. Purchaser shall

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provide each Seller with approved copies of such assignment documents and other state and federal transfer documents, as soon as they are available.

(b)Title Pending Governmental Approvals. Until all of the governmental approvals provided for in Section 3.7(a) have been obtained, the following shall occur with respect to the affected portion of the Assets representing state or federal Leases or other Lands:

(i)Sellers 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)Sellers shall act as Purchaser’s nominee but shall be authorized to act only upon and in accordance with Purchaser’s instructions, and Sellers 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, unless otherwise specifically requested and authorized by Purchaser in writing;

(iv)Sellers shall not be obligated to incur any expenses in Sellers’ capacity as nominee for the benefit of Purchaser under this Section 3.7(b), and, provided that Sellers give Purchaser prior written notice of any expenses that Sellers are required to incur to comply with their obligations under the applicable Leases or applicable Law, Purchaser agrees to pay or reimburse Sellers for any such expenses promptly upon receiving notice thereof; and

(v)For purposes of Article 11, Sellers 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 Sellers to Purchaser at Closing.

ARTICLE 4.
ENVIRONMENTAL MATTERS

Section 4.1.Assessment.

From and after the date of execution of this Agreement until the Closing Date, each Seller shall afford to Purchaser and Purchaser’s Representatives access to the Assets, including the Records in accordance with Section 7.1. Upon reasonable notice to Sellers, 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 E1527-05) 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

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expense of Purchaser, and shall be subject to the indemnity provisions of Section 4.4.  Each Seller or its respective designee shall have the right to accompany Purchaser and Purchaser’s Representatives whenever they are onsite on Assets.  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 Sellers or their Affiliates do not have the authority to grant access for such due diligence; provided, however, Sellers and their Affiliates shall use their commercially reasonable efforts to obtain permission from any other Person to allow Purchaser and Purchaser’s Representatives such access and the ability to conduct environmental due diligence in accordance herewith and as long as Sellers and their Affiliates have exercised such commercially reasonable efforts, Sellers shall have no liability to Purchaser for failure to obtain any such other Person’s permission.  Notwithstanding anything herein to the contrary, Purchaser shall not have the right to conduct any Phase II environmental property assessments or such other activities intended to constitute the conduct of “all appropriate inquiries” under 30 CFR Part 312 without the prior written consent of Sellers; provided, however, that if any Seller fails to provide such written consent, then Sellers shall retain the affected Asset, such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset.  Purchaser and Sellers 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 or other due diligence activity as strictly confidential until the Closing occurs (and thereafter, with respect to Sellers if Closing occurs), unless disclosure of any facts discovered through such Phase I or other due diligence activity is required under any Laws. Purchaser shall provide each 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 activity conducted on the Oil and Gas Properties. In the event that any necessary disclosures under applicable Laws are required with respect to matters discovered by any Phase I activity conducted by, for or on behalf of Purchaser, Purchaser agrees that Sellers shall be the responsible parties for disclosing such matters to the appropriate Governmental Bodies; provided that, if Sellers fail to promptly make such disclosure and Purchaser or any of its Affiliates is legally obligated to make such disclosure, Purchaser or any such Affiliate 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 Oil and Gas 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 Oil and Gas 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.

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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 an Environmental Liability with respect to any Asset (other than with respect to NORM) (in each case an “Environmental Defect”), then on or prior to April 11, 2014 at 5:00 p.m. C.S.T. (the “Environmental Claim Date”), Purchaser may notify each Seller in writing of such Environmental Defect (an “Environmental Defect Notice”). EXCEPT WITH RESPECT TO PURCHASER’S RIGHTS FOR ANY BREACH BY SELLERS OF THEIR REPRESENTATIONS SET FORTH IN SECTION 5.9 OR ANY BREACH BY SELLERS OF THEIR COVENANTS HEREUNDER, 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. To be effective, each such notice must set forth (i) a description of the matter constituting the alleged Environmental Defect, (ii) the Units, Wells and associated Assets affected by the Environmental Defect, (iii) the estimated Lowest Cost Response to eliminate the Environmental Defect in question (the “Environmental Defect Amount”) and (iv) supporting documents reasonably necessary for Sellers to verify the existence of the alleged Environmental Defect and the Environmental Defect Amount, provided, however, that the sufficiency or volume of documents delivered pursuant to this Section 4.3(a)(iv) shall not serve as any basis to dispute the validity of the Environmental Defect Notice.  Purchaser agrees that it shall furnish Sellers once at the end of every two (2) week period until the Environmental Claim Date with a preliminary Environmental Defect Notice if any officer of Purchaser or any of its Affiliates discovers or learns of any Environmental Defect during such two (2) week period, which notice may be preliminary in nature and supplemented prior to the expiration of the Environmental Claim Date; provided further that failure to provide preliminary notice of an Environmental Defect shall not prejudice Purchaser’s right to assert any Environmental Defect hereunder on or before the Environmental Claim Date.

(b)Sellers shall have the right, but not the obligation, to cure any Environmental Defect before Closing or, provided that the parties shall have mutually 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 Sellers disagree with any of Purchaser’s assertions with respect to the existence of an Environmental Defect or the Environmental Defect Amount or the cure thereof prior to the Scheduled Closing Date, Purchaser and Sellers will attempt to resolve the dispute prior to the Scheduled Closing Date. If such dispute or any dispute among the parties on whether or not any Environmental Defect has been cured by Sellers by the Scheduled Closing Date (unless the parties have mutually agreed to allow Sellers to cure such Environmental Defect after Closing) has not been resolved by the Scheduled Closing Date, then such matters remaining in dispute shall be exclusively and finally resolved pursuant to this Section 4.3(b) as follows:

(i)The parties shall submit such dispute to an environmental consultant approved in writing by Sellers and Purchaser (and absent such mutual approval, appointed by the Houston office of the American Arbitration Association) that is experienced in environmental corrective action at oil and gas properties in the regional area where the relevant Oil and Gas Properties are located and that shall not have performed professional services for either party or

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any of their respective Affiliates during the previous three (3) years (the “Independent Expert”). Within ten (10) Business Days following the selection of the Independent Expert, each of Purchaser, on the one hand, and Sellers, on the other hand, shall submit to the Independent Expert written explanations of their respective positions in the disputed environmental matters. The Independent Expert may elect to conduct the dispute resolution proceeding by written submissions from Purchaser and Sellers with exhibits, including interrogatories, supplemented with appearances by Purchaser and Sellers, 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.

(ii)If the Environmental Defect Amounts alleged by Purchaser that are applicable to the disputed environmental matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f) and Section 8.2(f) (including any Title Defect Amounts alleged by Purchaser pursuant to Article 3) that are not resolved prior to the Scheduled Closing Date, exceed twenty percent (20%) of the Purchase Price, then the date for Closing shall be extended until the disputed environmental matters are resolved pursuant to Section 4.3(b)(i).  Upon resolution of such disputed environmental matters pursuant to Section 4.3(b)(i), then, subject to the other terms and conditions of this Agreement, the Closing shall occur on the tenth (10th) Business Day following the date upon which the Independent Expert delivers written notice to Purchaser and Sellers of his determination with respect to any disputed environmental matters, including any applicable Environmental Defect Amount.

(iii)If the Environmental Defect Amounts alleged by Purchaser that are applicable to the disputed Environmental matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f)  and Section 8.2(f) (including any Title Defect Amounts alleged by Purchaser pursuant to Article 3), are equal to or less than twenty percent (20%) of the Purchase Price, then the Assets affected by such Environmental Defects shall be retained by Sellers at Closing, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Assets.  If the Allocated Value of the Asset so held back from the initial Closing is greater than the Environmental Defect Amount determined by the Independent Expert or agreed by the parties, then such Asset will be conveyed to Purchaser (subject to the satisfaction of the conditions set forth in Section 8.2 with respect to such Asset) at a delayed Closing (which shall become the new Closing Date with respect to such Asset) within ten (10) Business Days following the date that the Independent Expert delivers written notice to Purchaser and Sellers of his award with respect to such Environmental Defect and/or Environmental Defect Amount, at which time Purchaser shall pay to Sellers the

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full Allocated Value of the Asset less such Environmental Defect Amount (as adjusted pursuant to Section 2.2 through the new Closing Date therefor with respect to such Asset).  If the Allocated Value of the Asset so held back from the initial Closing is less than the Environmental Defect Amount determined by the Independent Expert, then such Asset will be retained by Seller, such Asset will become an Excluded Asset hereunder and Purchaser shall have no further obligation to purchase such Asset.

(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. Sellers 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 Sellers and one-half by Purchaser.

(d)Subject to Section 4.3(b) and the following provisions of this Section 4.3(d), 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, as applicable, 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 (affecting one or more Assets) for which the Environmental Defect Amounts therefor do not exceed $15,000 (“Individual Environmental Threshold”); (ii) if the parties agree or the Independent Expert determines that the Environmental Defect Amount with respect to any Asset exceeds the Allocated Value thereof, then Sellers shall retain the affected Asset, such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset, (iii) if the Environmental Defect Amounts for all Environmental Defects affecting any Asset,  when combined with the Title Defect Amounts for all Title Defects affecting the same Asset, exceeds the Allocated Value of such affected Asset then Sellers shall retain the affected Asset, such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset, and (iv) in no event shall there be any adjustments to the Purchase Price for any uncured Environmental Defect unless the aggregate Environmental Defect Amounts attributable to all such Environmental Defects, taken together with the aggregate Title Defect Amounts attributable to all uncured Title Defects, exceed the Aggregate Defect Deductible, after which point Purchaser shall be entitled to adjustments to the Purchase Price or other remedies only with respect to uncured Title Defects and uncured Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts attributable thereto are in excess of such Aggregate Defect Deductible; for the avoidance of doubt, Title Defect Amounts and Environmental Defect Amounts which do not meet the Individual Title Threshold and the Individual Environmental Threshold shall not be included in reaching the Aggregate Defect Deductible.

Section 4.4.Inspection Indemnity.

PURCHASER HEREBY AGREES TO DEFEND, INDEMNIFY, RELEASE, PROTECT, SAVE AND HOLD HARMLESS THE SELLER INDEMNIFIED PERSONS

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FROM AND AGAINST ANY AND ALL LOSSES ARISING OUT OF, OR RELATING TO, ANY DUE DILIGENCE ACTIVITY CONDUCTED ON THE ASSETS BY PURCHASER OR ITS AGENTS OR REPRESENTATIVES, WHETHER BEFORE OR AFTER THE EXECUTION OF THIS AGREEMENT, EXCEPT TO THE EXTENT ARISING OUT OF, OR RELATING TO, THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SELLER INDEMNIFIED PERSON. 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 SELLERS

Section 5.1.Generally.

(a)Any representation or warranty qualified “to the knowledge of Sellers” or “to Sellers’ knowledge” or with any similar knowledge qualification is limited to matters within the Actual Knowledge of the officers and employees of each Seller who have direct responsibility for the Assets, as specified on Schedule 5.1.  “Actual Knowledge”, for purposes of this Agreement, means information actually and personally known by the individuals specified on Schedule 5.1 after due investigation, in their individual capacities and as officers and employees of any Seller or its Affiliates.  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 Sellers 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 interest of Sellers.  Descriptions of or references to particular contracts, agreements, notices and other documents herein are qualified in their entirety by reference to such documents. Certain sections of this Agreement may be qualified by the matters set forth in the related Schedule, and the disclosure of any fact or item in any of the Schedules shall, should the existence of such fact or item be relevant to any other of the Schedules or sections in this Agreement, be deemed to be disclosed with respect to that other section or Schedule, in each case as long as it is readily apparent on its face.  In disclosing information pursuant to the Schedules, no Seller waives any attorney-client privilege associated with such information or any protection afforded by the work-product doctrine.

(b)Subject to the foregoing provisions of this Section 5.1, the disclaimers and waivers contained in Sections 11.9 and 11.10 and the other terms and conditions of this Agreement, Sellers, jointly and severally, represent and warrant to Purchaser the matters set out in the remainder of this Article 5.

Section 5.2.Existence and Qualification.

HEPI 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 corporation in the

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jurisdictions where the Assets it owns are located.  HFS is a limited liability company 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 limited liability company in the jurisdictions where the Assets it owns are located.  HK Energy is a limited liability company 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 limited liability company in the jurisdictions where the Assets it owns are located.  HOCI 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 corporation in the jurisdictions where the Assets it owns are located.  HK Energy Operating is a limited liability company 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 limited liability company in the jurisdictions where the Assets it owns are located.  Halcón Resources Operating 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 corporation in the jurisdictions where the Assets it owns are located.

Section 5.3.Power.

Each 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 each Seller. This Agreement has been duly executed and delivered by each Seller (and all documents required hereunder to be executed and delivered by any Seller at Closing will be duly executed and delivered by such Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of each Seller, enforceable against each 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 on 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 the HSR Act (if applicable), the execution, delivery and performance of this Agreement by each Seller, and the transactions contemplated by this Agreement will not (i) violate any provision of (A) the certificate of formation or incorporation, as applicable, bylaws or limited liability company agreement or any similar governing document of any Seller or (B) any loan or credit agreement, note, bond, mortgage, indenture, lease, permit, concession, franchise, license or other contract, agreement or instrument applicable to any 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 any Seller is a party or which affect the Assets, (iii) violate any judgment, order, ruling, or decree applicable to any Seller as a party in interest, (iv) violate any Laws applicable to any Seller or

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any of the Assets, except for 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 and that are customarily obtained subsequent to the sale or conveyance thereof.

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 any 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 any Seller’s or any of its Affiliates’ ownership, operation, development, maintenance, or use of any of the Assets, except as set forth in: (i)  Schedule 5.7(a), no proceeding, claim, arbitration, action, suit, 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 such Seller or any of its Affiliates is a party is pending or, to such Seller’s knowledge, threatened in writing against such Seller or any of its Affiliates; and (ii) Schedule 5.7(b), to Sellers’ knowledge, no Proceeding or investigation to which such Seller is not a party which relates to the Assets is pending or threatened.

Section 5.8.Taxes and Assessments.

(a)All Tax reports, returns, statements (including estimated reports, returns or statements), and other similar filings relating to the Sellers’ acquisition, ownership or operation of the Assets (the “Tax Returns”) required to be filed 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, and all such Tax Returns are true and correct in all material respects, and all such Taxes have been timely paid in full and no Seller is delinquent in the payment of such Taxes.

(b)With respect to all Taxes related to the Sellers’ acquisition, ownership or operation of the Assets, (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 pending or, to Sellers’ knowledge, threatened against the Assets or such 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 and payable.  No Asset is subject to any tax partnership agreement or provisions requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute.

Section 5.9.Compliance with Laws.

Except as disclosed on Schedule 5.9, the Assets are, and the ownership, operation, development, maintenance, and use of any of the Assets are, currently in material compliance with the provisions and requirements of all Laws applicable to the Assets.  Except as disclosed

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on Schedule 5.9, (i) no Seller has 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 and (ii) no Seller has received any written notice of any claims with respect to material Environmental Liabilities with respect to the Assets or any demands to clean-up any portion of the Assets, except for such claims or demands which have been resolved and closed with the applicable Governmental Bodies.  Notwithstanding the foregoing, except as set forth in this Section 5.9, Sellers make no representation or warranty, express or implied, relating to any Environmental Liabilities or Environmental Laws.

Section 5.10.Contracts.

All Material Contracts are included within the list of Contracts in Schedule 1.2(a)(iv) and Schedule 1.2(b)(vi).  Sellers are in material compliance with and, to Sellers’ knowledge, all counterparties are in material compliance with, all Material Contracts, except as disclosed on Schedule 5.10.  Except as set forth on Schedule 5.10 and except for such matters that would not, individually or in the aggregate, have a Material Adverse Effect, no event has occurred that with notice or lapse of time or both would constitute any default under any such Material Contract by any Seller or, to Sellers’ knowledge, by any other Person who is a party to such Material Contract.  No Seller has received or given any unresolved written notice of default, amendment, waiver, price redetermination, market out, curtailment or termination with respect to any Material Contract.  “Material Contracts” means any of the following types of Contracts: (a) any Contract that could reasonably be expected to result in aggregate payments or receipts of revenues by Sellers or Purchaser with respect to the Assets of more than $100,000 during the current or any subsequent year (based solely on the terms thereof and without regard to any expected increase in volumes or revenues); (b) any Hydrocarbon purchase and sale, gathering, transportation, processing or similar Contract unless terminable by each party without penalty on 30 days or less notice; (c) any Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, any Seller conducts business, including area of mutual interest Contracts; (d) any Contract with any Affiliate of any Seller which will be binding on Purchaser after the Effective Time and will not be terminable by Purchaser within 30 days or less notice; (e) any Contract that contains a call on production; and (f) any joint or unit operating agreement.

Section 5.11.Payments for Hydrocarbon Production.

Except as set forth on Schedule 5.11,

(a)to each Seller’s knowledge, all rentals, royalties, excess royalty, overriding royalty interests, Hydrocarbon production payments, and other payments due and payable by any 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, Sellers are otherwise entitled under applicable Law and the terms of any applicable Lease to withhold payment, without penalty or interest, while resolving questions of title or obtaining division orders; and

(b)Sellers are not obligated under any contract or agreement for the sale of Hydrocarbons from the Assets containing a take-or-pay, advance payment, prepayment, or

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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 Hydrocarbons attributable to the Assets without then or thereafter receiving full payment therefor.

Section 5.12.Governmental Authorizations.

Except as disclosed on Schedule 5.12, each Seller has obtained and is maintaining all material federal, state and local governmental licenses, permits, franchises, orders, exemptions, variances, waivers, authorizations, certificates, consents, rights, privileges and applications therefor (the “Governmental Authorizations”) that are presently necessary or required for the ownership and operation of the Seller Operated Assets operated by such Seller as currently owned and operated (excluding Governmental Authorizations required by Environmental Law). To Sellers’ knowledge, except as disclosed in Schedule 5.7(a), Schedule 5.7(b) or Schedule 5.12, (i) each Seller has operated its Seller Operated Assets in all material respects in accordance with the conditions and provisions of such Governmental Authorizations, and (ii) no written notices of material violation have been received by any Seller, and no Proceedings are pending or, to Sellers’ knowledge, threatened in writing that might result in any material modification, revocation, termination or suspension of any such Governmental Authorizations or which would require any material corrective or remedial action by any Seller.

Section 5.13.Preference Rights and Transfer Requirements.

None of the Assets, or any portion thereof, is subject to any Preference Right or Transfer Requirement which may be applicable to the transactions contemplated by this Agreement, except for the Preference Rights and Transfer Requirements set forth on Schedule 5.13.

Section 5.14.Payout Balances.

Schedule 5.14 contains a complete list in all material respects, of the status, as of February 1, 2014, of any “payout” balance 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 date hereof, there are no outstanding AFEs or other commitments to make capital expenditures which are binding on the Assets and which any Seller reasonably anticipates will individually require expenditures by the owner of the Assets after the Effective Time in excess of $100,000 other than those shown on Schedule 5.15.

Section 5.16.Imbalances.

To Sellers’ knowledge, Schedule 5.16 accurately sets forth in all material respects all of the Imbalances of Sellers arising with respect to the Assets or production therefrom and, except as disclosed in Schedule 5.16, (i) no Person is entitled to receive any material portion of any Sellers’ Hydrocarbons produced from the Assets or to receive material 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

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agreement, gas transportation agreement, gas purchase agreement, or other agreements, whether similar or dissimilar, (ii) Sellers are not obligated to deliver any material quantities of Hydrocarbons or to pay any material penalties or other material 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) Sellers are not obligated to pay any material penalties or other material payments under any gas transportation or other agreement as a result of the delivery of quantities of Hydrocarbons from the Wells in excess of the contract requirements. Except as set forth on Schedule 5.16, Sellers have not received, or are not obligated to receive, prepayments (including payments for gas not taken pursuant to “take-or-pay” arrangements) for any of Sellers’ share of the Hydrocarbons produced from the Oil and Gas Properties, as a result of which the obligation exists to deliver Hydrocarbons produced from the Oil and Gas Properties after the Effective Time without then or thereafter receiving payment therefor.

Section 5.17.Condemnation.

To Sellers’ knowledge, there is no actual or written threatened taking (whether permanent, temporary, whole or partial) of any part of the Assets by reason of condemnation or the threat of condemnation.

Section 5.18.Bankruptcy.

There are no bankruptcy, reorganization, or receivership proceedings pending against, or, to Sellers’ knowledge, being contemplated by or threatened against any Seller.  Each Seller is, and will be immediately after giving effect to the transactions contemplated by this Agreement, solvent.

Section 5.19.Production Allowables.

Except as set forth on Schedule 5.19, since the date hereof, no Seller has received written notice that there has been any change proposed in the production allowables for any Wells listed on Exhibit A-1 or otherwise with respect to production from the Leases.

Section 5.20.Foreign Person.

No Seller is a “foreign person” within the meaning of Section 1445 of the Code.

Section 5.21.Drilling Obligations.

Except as set forth on Schedule 5.21, to such Seller’s knowledge, except to the extent of those obligations previously fulfilled by Sellers or any of their predecessors, none of the Leases or Contracts contain express provisions obligating Sellers or their successors to drill any wells on the Oil and Gas Properties (other than provisions requiring optional drilling as a condition of maintaining or earning all or a portion of a presently non-producing Lease).

Section 5.22.Obligations to Make Assignments.

Except as set forth in Schedule 5.22, the Assets are not subject to any Contract containing an area of mutual interest, maintenance of uniform interest, or other provision under

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which a Seller may be obligated to make assignments to third Persons of interests in any Asset after the Effective Time.

Section 5.23.No Material Adverse Change.

Since the Effective Time up to the date of this Agreement, there has been no material damage, destruction or loss to the Assets or Material Adverse Effect.

Section 5.24.Suspended Funds.

Schedule 5.24 lists all funds held in suspense (including funds held in suspense for unleased interests) by any Seller or its Affiliates as of the date of this Agreement that are attributable to the Assets, a description of the source of such funds and the reason they are being held in suspense, and, if known, the name or names of the Persons claiming such funds or to whom such funds are owed.

Section 5.25.Gathering Equipment.

The Gathering Equipment constitutes all of the personal property, equipment, and facilities necessary for the operation of the Gathering System in the manner presently owned and operated by HFS and in material compliance with applicable Laws.  Except as set forth in Schedule 5.25, each item of tangible Gathering Equipment is in good operating condition and repair, ordinary wear and tear excepted.

Section 5.26.Hydrocarbon Marketing.

There are no calls on production, options to purchase, or similar rights in effect with respect to any portion of the Hydrocarbons produced from or allocable to the Oil and Gas Properties, and, except as set forth on Schedule 5.26, all Contracts for the sale of Hydrocarbons are terminable without penalty on no more than thirty (30) days’ prior notice.  Except as set forth in Schedule 5.26, none of the Oil and Gas Properties is subject to any acreage, well, or reserve commitment or dedication under the terms of any Hydrocarbon sales, gathering, processing, transportation, or similar agreement, or any obligation under any such agreement to pay any capacity charge, reservation charge, through-put fee, or similar charge or fee without regard to the quantity of Hydrocarbons actually delivered.  To the knowledge of Sellers, all proceeds from the sale of Hydrocarbons attributable to the interests of each Seller in the Oil and Gas Properties have been and are being disbursed to such Seller under appropriate division orders, transfer orders, or similar documents signed by or otherwise binding on such Seller, and no portion of any such proceeds is being held in suspense, subject to a Claim for refund by the purchaser, used as an offset or as collateral for other obligations (whether disputed or undisputed), or otherwise not being paid to such Seller as it becomes due in the ordinary course of business.

ARTICLE 6.
REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to each Seller the following:

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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 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 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 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 on public policy.

Section 6.4.No Conflicts.

Subject to compliance with the HSR Act, 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 or indenture 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 Purchaser’s ability to perform its obligations with respect to the transactions contemplated hereby.

Section 6.5.Liability for Brokers’ Fees.

Sellers 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.

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Section 6.6.Litigation.

There are no Proceedings pending, or to the Actual Knowledge of Purchaser, threatened in writing before any Governmental Body against Purchaser or any Affiliate of Purchaser which are reasonably likely to materially impair 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 each 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 and absent fraud by any Seller, Purchaser acknowledges that there are no representations or warranties, express, statutory or implied, as to the Assets or prospects thereof made by any Seller.  Without limiting the generality of the foregoing, subject to Section 5.9, Purchaser acknowledges that no Seller has made nor will 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 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.  Subject to Sellers’ compliance with Section 4.1, Purchaser acknowledges that it has or will have access to the Assets, the officers and employees of Sellers, and the books, records and files made available by Sellers relating to the Assets, and in making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Purchaser has relied solely on the representations of Sellers contained in Article 5 and 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 Oil and Gas Properties.

Section 6.8.SEC Disclosure.

Purchaser is acquiring the Oil and Gas Properties 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 Assets involves certain risks; and (ii) neither the SEC nor any federal, state or foreign agency has passed upon the Assets or made any finding or determination as to the fairness of an investment in the Assets 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.

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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 Sellers at Closing.

ARTICLE 7.
COVENANTS OF THE PARTIES

Section 7.1.Access.

(a)From and after the date of this Agreement up to and including the date the Records are delivered to Purchaser pursuant to Section 1.5 (or the earlier termination of this Agreement), Sellers shall cooperate with Purchaser and provide Purchaser and its officers, directors, employees, agents, accountants, attorneys, investment bankers, consultants, advisors and other authorized representatives (“Purchaser’s Representatives”), access to the Assets and access to the Records, but only to the extent that Sellers may do so without violating any obligations to any un-Affiliated third party or any Laws and to the extent that Sellers have authority to grant such access without breaching any restriction legally or contractually binding on Sellers; provided, however, that each Seller shall use its commercially reasonable efforts to obtain any necessary consents or approvals from un-Affiliated third parties or applicable Governmental Bodies in order to provide Purchaser and Purchaser’s Representatives such access. Purchaser shall conduct all such inspections and other information gathering described above only (i) (x) during regular business hours and (y) during any weekends and after hours requested by Purchaser that can be reasonably accommodated by Seller, and (ii) in a manner which will not unduly interfere with Sellers’ 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 February 10, 2014 (the “Confidentiality Agreement”), by and between Sellers and Purchaser; provided, however, that if the Closing should occur, the foregoing confidentiality restriction on Purchaser, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets).  Sellers shall also make available to Purchaser and Purchaser’s Representatives, upon reasonable notice during normal business hours, Sellers’ personnel knowledgeable with respect to the Assets in order that Purchaser may make such diligence investigation as Purchaser considers necessary or appropriate.

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(b)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 AVAILABLE TO PURCHASER AS AN ACCOMMODATION, AND, EXCEPT TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT AND IN THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE, ARE MADE 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 PURCHASER’S RIGHTS WITH RESPECT TO THE REPRESENTATIONS SET FORTH IN ARTICLE 5 OF THIS AGREEMENT OR THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND EXCLUDING FRAUD BY ANY SELLER, ANY RELIANCE UPON OR CONCLUSIONS DRAWN BY PURCHASER FROM SUCH MATERIALS, DOCUMENTS AND OTHER INFORMATION SHALL BE AT PURCHASER’S RISK AND SHALL NOT GIVE RISE TO ANY LIABILITY OF OR AGAINST SELLERS, AND PURCHASER HEREBY ACKNOWLEDGES THAT IT IS NOT RELYING ON ANY REPRESENTATIONS OTHER THAN THOSE REPRESENTATIONS AND WARRANTIES SET FORTH IN ARTICLE 5 OF THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE.  EXCEPT FOR PURCHASER’S RIGHTS WITH RESPECT TO THE REPRESENTATIONS AND WARRANTIES OF THE SELLERS SET FORTH IN ARTICLE 5 OF THIS AGREEMENT, THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND THE INDEMNITY OBLIGATIONS SET FORTH IN THIS AGREEMENT, AND EXCLUDING FRAUD BY ANY SELLER, 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 IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 7.2.Government Reviews.

(a)Sellers and Purchaser shall in a timely manner (i) make all required filings, if any, with, prepare applications to and conduct negotiations with, each Governmental Body as to which such filings, applications or negotiations by such party are necessary or appropriate in connection with the consummation of the transactions contemplated hereby and (ii) provide such information to the other parties hereto as Sellers or Purchaser, as applicable, may reasonably request to make such filings, prepare such applications and conduct such negotiations. Each

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party to this Agreement shall cooperate with and use all commercially reasonable efforts to assist the other parties hereto with respect to such filings, applications and negotiations.

(b)If compliance with the HSR Act is required in connection with the transactions contemplated by this Agreement, within ten Business Days following the execution by Purchaser and Sellers of this Agreement, Purchaser, on the one hand, and Sellers, on the other hand, will each prepare and simultaneously file with the DOJ and the FTC the notification and report form required for the transactions contemplated by this Agreement by the HSR Act, and request early termination of the waiting period thereunder.  Purchaser and Sellers agree to respond promptly to any inquiries from the DOJ or the FTC concerning such filings and to comply in all material respects with the filing requirements of the HSR Act.  Purchaser and Sellers shall cooperate with each other and, subject to the terms of the Confidentiality Agreement, shall promptly furnish all information to the other parties hereto that is necessary in connection with Purchaser’s and Sellers’ compliance with the HSR Act.  Purchaser and Sellers shall keep each other fully advised with respect to any requests from or communications with the DOJ or FTC concerning such filings and shall consult with each other with respect to all responses thereto.  Each Seller and Purchaser shall use its reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act filing to consummate the transactions consummated hereby. Any fees or expenses related to filings required to this Section 7.2(b) shall be shared equally by Sellers, on the one hand, and Purchaser, on the other hand.

Section 7.3.Notification of Breaches.

Until the Closing,

(a)Purchaser shall notify Sellers 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)Sellers shall notify Purchaser promptly after any 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 Sellers’ 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 Sellers’ 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, so long as the non-breaching party does not incur any costs of liabilities on account of such breach (and, if the non-breaching party is Purchaser, no Asset suffers a diminution in value on account of such breach), such breach shall be considered not to have occurred for all purposes of this Agreement.

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(d)No notification by a party of any breach pursuant to this Section 7.3 shall affect the representations, warranties or covenants of the parties or the conditions to their respective obligations hereunder.

(e)There shall be no breach of the covenants in this Section 7.3 as a result of a party’s failure to report a breach of any representation or warranty or a breach of an obligation to perform or observe any covenant or agreement of which it had Actual Knowledge if the party subject to the breach or failure also had knowledge thereof prior to Closing.

Section 7.4.Letters in Lieu; Assignments; Operatorship.

(a)Sellers will execute on the Closing Date letters in lieu of division and/or transfer orders relating to the Assets, on forms prepared by Sellers and reasonably satisfactory to Purchaser, to reflect the transactions contemplated hereby.

(b)Sellers will prepare and execute, and Purchaser will execute, on the Closing Date, the Conveyances and any additional assignments necessary to convey to Purchaser all federal and state Leases and Surface Rights in the form as prescribed by the applicable Governmental Body and otherwise acceptable to Purchaser and Sellers.

(c)Except as set forth in Article 5 and the special warranty of title contained in the Conveyances, Sellers make no representations or warranties to Purchaser, express, implied or by statute, as to transferability or assignability of operatorship of any Seller Operated Assets. Rights and obligations associated with operatorship of any such Seller Operated Assets may be governed by operating and similar agreements that control the appointment of a successor operator, and in such case, whether Purchaser will succeed as operator of the subject Seller Operated Assets (or portions thereof) will be determined in accordance with the terms of such agreements. However, Sellers will assist Purchaser in Purchaser’s efforts to succeed Sellers or Sellers’ Affiliate(s) as operator of any Oil and Gas Properties included in the Assets, including designating and/or appointing by assignment, to the extent legally possible, Purchaser as successor operator or taking any other actions permitted or required under the applicable operating agreement or other governing document (including executing letters whereby the applicable Seller resigns as operator of all Seller Operated Assets).  Purchaser shall, promptly following Closing, to the extent required by Law, file all appropriate forms, declarations or bonds with the applicable federal and/or state agencies relative to its assumption of operatorship with respect to the Oil and Gas Properties. For all Seller Operated Assets, Sellers and Purchaser shall execute appropriate change or transfer of operator forms on the Closing Date, and the applicable Seller shall thereafter promptly file said forms with the applicable Governmental Body transferring operatorship of such Assets to Purchaser.

Section 7.5.Public Announcements.

(a)Until the Closing, Purchaser shall neither make or issue, or cause or permit any agent or Affiliate to make or issue, 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 other parties hereto; provided, however, that the foregoing shall not restrict disclosures by Purchaser which are required by applicable securities or other Laws or

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the applicable rules of any stock exchange having jurisdiction over the disclosing party or its Affiliates.  At or after Closing, Purchaser shall be permitted to issue press releases or other public announcements concerning the existence of this Agreement, the contents hereof and the transactions contemplated hereby; provided, however, that the content of any such press release or public announcement shall be subject to the prior review and reasonable approval of Sellers (which shall not be unreasonably denied); and provided further, however, that the foregoing shall not restrict disclosures by Purchaser 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.

(b)           No Seller shall issue press releases or other public announcements concerning the existence of this Agreement, the contents hereof and the transactions contemplated hereby until the content of any such press release or public announcement has been subject to the prior review and reasonable approval of Purchaser (which shall not be unreasonably denied); provided, however, that the foregoing shall not restrict disclosures by any 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.

(a)           Except as set forth on Schedule 7.6, from and after the date of this Agreement until the Closing, Sellers: (i) will operate and maintain the Seller Operated Assets and the business thereof as a reasonably prudent operator, consistent with past practices and in accordance with applicable Contracts and applicable Laws, (ii) shall use their commercially reasonable efforts to cause the applicable un-Affiliated third party to operate and maintain any Assets not operated by a Seller (or an Affiliate of a Seller) as a reasonably prudent operator, consistent with past practices and in accordance with applicable Contracts and applicable Laws, (iii) shall maintain the books of account and records relating to the Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of the applicable Seller, (iv) shall notify Purchaser of any authorizations for expenditure relating to the Assets that are received by any Seller or an Affiliate of any Seller, and keep Purchaser reasonably informed of ongoing operations and capital projects with respect to the Assets, (v) shall not propose or commit to any single operation, or series of related operations, reasonably anticipated to require capital expenditures by Purchaser as owner of the Assets in excess of $100,000, or make any capital expenditures with respect to any operation, or series of related operations, in respect of the Assets in excess of $100,000 (net to Sellers’ or its Affiliates’ interest), (vi) shall not terminate (other than by failing to renew an existing term), amend or waive any material right under any Contract or Lease, extend the terms of any Contracts or enter into any contracts or agreements that if entered into prior to the date of this Agreement would be required to be listed in a Schedule attached to this Agreement, (vii) shall maintain insurance coverage on the Assets presently furnished by un-Affiliated third parties in the amounts and of the types presently in force as of the date of this Agreement, (viii) shall use commercially reasonable efforts to maintain in full force and effect all Leases and all Surface Rights, (ix) shall maintain all material Governmental Authorizations applicable to the Assets, (x) will not abandon, transfer, farmout, sell, hypothecate, mortgage, pledge, encumber, grant overriding royalties or other interests in, or otherwise dispose of any of the Assets, except for (A) sales and dispositions of Hydrocarbon production in the ordinary course of business consistent with past practices and/or (B) sales of

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equipment that is no longer necessary in the operation of the Assets or for which replacement equipment has been obtained, (xi) will not enter into any settlement, compromise or other agreement with respect to Taxes with any Governmental Body, or make or change any election with respect to Taxes, relating to the Assets, or consent to any extension or waiver of the limitation period applicable to any claim or assessment with respect to Taxes relating to the Assets, (xii) shall not (A) settle or compromise any claim relating to the Assets for which the Purchaser would have liability or (B) settle or compromise any claim relating to the Assets against a third party that would compromise or waive any claim in excess of $100,000, and (xiii)  will not commit to do any of the items described in Section 7.6(a)(v), Section 7.6(a)(vi), Section 7.6(a)(x), Section 7.6(a)(xi) and Section 7.6(a)(xii) above. In the event of an emergency, Sellers may take such action as a prudent operator would take without the prior written consent of Purchaser; provided, however, that Sellers shall notify Purchaser of such action promptly thereafter.

(b)           Purchaser acknowledges that Sellers may own an undivided interest in certain of the Assets, and Purchaser agrees that the acts or omissions of the other working interest owners who are not a Seller or an Affiliate of a Seller 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 each Seller (and any Affiliate of Sellers) 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. Within 10 Business Days following the execution of this Agreement, Sellers shall initiate all procedures which are reasonably required to comply with or obtain the waiver of all Preference Rights and Transfer Requirements set forth in Schedule 5.13 with respect to the transactions contemplated by this Agreement. Sellers shall use commercially reasonable efforts to obtain all applicable consents and to obtain waivers of applicable Preference Rights; provided, however, Sellers shall not be obligated to pay any consideration to (or incur any out of pocket cost or expense for the benefit of) the holder of any Preference Right or Transfer Requirement in order to obtain the waiver thereof or compliance therewith; and provided further that, except as provided in Section 7.7(c), any Transfer Requirement that states that consent thereto cannot unreasonably be withheld (or words to similar effect), and as to which the lessor, or other holder of such Transfer Requirement, has not objected to the transfer or affirmatively stated that consent thereto will not be forthcoming, shall be deemed waived and otherwise satisfied fifteen (15) days after Sellers make written request to said lessor, or other holder of such Transfer Requirement, for consent to transfer the affected Asset(s) to Purchaser.

(b)           If 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 Sellers receives written notice of such election prior to the Closing, such Preference Property will be eliminated from the Assets and the Purchase Price shall be reduced by the Allocated Value of the Preference Property.

(c)           If

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(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 (A) provides that the transfer of such Asset without compliance with such Transfer Requirement will, or that pursuant to applicable Law will, result in termination or other material impairment of any rights in relation to such Asset or the value thereof, (B) that is held by a Governmental Body, (C) provides that any assignment of the Asset affected thereby is, or that pursuant to applicable Law is, void or voidable or (D) is expressly denied by the holder thereof, and (in each case) such Transfer Requirement is not waived by the holder thereof or obtained 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 Sellers 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 (subject to the satisfaction of the conditions in Section 8.2 with respect to such Retained Asset) at a delayed Closing (which shall become the new Closing Date with respect to such Retained Asset), within ten (10) Business 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) permitting transfer of the Retained Asset to Purchaser pursuant to this Agreement and Sellers obtain a waiver of or notice of election not to exercise from the applicable third parties, or otherwise satisfy, 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 Sellers 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 with respect to such Retained Asset); provided, however, if all such Preference Rights and Transfer Requirements with respect to any Retained Asset so held back at the initial Closing are not obtained or waived by the holder thereof 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 Sellers 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 Preference Rights and Transfer Requirements with respect to such Retained Asset(s).

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(d)           Purchaser acknowledges that Sellers desire 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 Sellers do 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 (other than the Retained Assets or other Assets excluded pursuant to the express provisions of this Agreement). In furtherance of the foregoing, Sellers’ 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 any delayed Closing Date pursuant to Section 7.7(c)).

Section 7.8.               Tax Matters.

(a)           Subject to the provisions of Section 12.3, Sellers shall be responsible for all Taxes related to the Assets (including ad valorem, property, severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom, which are addressed and apportioned as set forth in Section 1.4) attributable to any period of time prior to the Effective Time, and Purchaser shall be responsible for all such Taxes related to the Assets attributable to any period of time on and after the Effective Time. Notwithstanding the foregoing, Sellers shall handle payment to the appropriate Governmental Body of all Taxes with respect to the Assets which are required to be paid prior to Closing (and shall file all Tax Returns with respect to such Taxes). Sellers shall also handle payment to the appropriate Governmental Body of all Texas ad valorem and property Taxes based on units of Hydrocarbons produced prior to the Closing Date and for which payment is due after the Closing Date. If requested by Purchaser, Sellers will assist Purchaser with preparation of all ad valorem and property Tax Returns for periods ending on or before the Closing Date (including any extensions requested), but which are required to be paid after the Closing Date. Sellers shall deliver to Purchaser within thirty (30) days of filing copies of all Tax Returns to be filed by Sellers relating to the Assets and any supporting documentation to be provided by Sellers to Governmental Bodies for Purchaser’s approval, which shall not be unreasonably withheld, excluding Tax Returns related to income tax, franchise tax, or other similar Taxes. Purchaser shall file all Tax Returns covering Taxes treated as Property Costs that are required to be filed after the Closing Date unless covered above. With respect to such Tax Returns covering a taxable period which includes the Effective Time, Purchaser shall provide a copy of such Tax Return to Sellers within thirty (30) days prior to filing for Sellers’ approval, which shall not be unreasonably withheld.  If any Taxes allocated to Sellers pursuant to this Section 7.8 or Section 1.4 are actually paid by Purchaser, then, after the Closing Date and upon written request by Purchaser, Sellers shall, within fifteen (15) Business Days of such request, make a payment to Purchaser of the amount of any such Taxes paid by Purchaser but allocated to Sellers.  If any Taxes allocated to Purchaser pursuant to this Section 7.8 or Section 1.4 are actually paid by Sellers and not already accounted for in an adjustment to the Purchase Price pursuant to Section 2.2(d), then, after the Closing Date and upon written request by Sellers,

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Purchaser shall, within fifteen (15) Business Days of such request, make a payment to Sellers of the amount of any such Taxes paid by Sellers but allocated to Purchaser.

(b)           Purchaser and Sellers shall cooperate fully, as and to the extent 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 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. Purchaser and each Seller agree (i) to retain all books and records with respect to 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 Sellers, 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 Sellers 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.  Sellers shall promptly notify Purchaser in writing upon receipt by any Seller of notice of any pending or threatened Tax audits or assessments relating to the income, properties or operations of Seller that reasonably may be expected to relate to or give rise to a lien on the Assets.  Each of Purchaser and Sellers shall promptly notify the other in writing upon receipt of notice of any pending or threatened Tax audit or assessment challenging the Allocation.

(c)           Purchaser and Sellers shall cooperate fully, as and to the extent reasonably requested by the other party, in connection with accommodating a 1031 exchange (as provided for under Section 1031 of the Code). Purchaser and each 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. If Purchaser so elects, Purchaser may assign its rights under this Agreement to the 1031 Assets to the Qualified Intermediary and its right to receive the Conveyance to an Affiliate. Seller hereby (i) consents to Purchaser’s assignment of its rights in this Agreement with respect to the 1031 Assets, and (ii) if such an assignment is made, agrees to transfer all or a portion of the Assets into the qualified trust account or into Purchaser’s Affiliate at Closing as directed in writing by Purchaser. Purchaser and each 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

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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.  The Closing Date shall not be delayed or affected by reason of the Like-Kind Exchange.

(d)           Any payments made to any party pursuant to Article 11 shall constitute an adjustment of the Purchase Price for Tax purposes and shall be treated as such by Purchaser and Sellers on their Tax Returns to the extent permitted by Law.

Section 7.9.               Further Assurances.

After the Closing, Sellers and Purchaser shall, and shall cause their Affiliates, as applicable to, execute, acknowledge and deliver from time to time all such further conveyances, transfer orders, division orders, notices and such other instruments, and shall take such further actions as any party hereto may reasonably request and as may be necessary or appropriate to accomplish the transactions described in this Agreement (including 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 and/or the Exhibits attached to each of the foregoing and to perfect Purchaser’s title thereto.

Section 7.10.            Notice of Claims.

Sellers shall promptly notify Purchaser as soon as reasonably practicable (but in any event within five Business Days) of any written notice received or given by any Seller or Affiliate of any Seller with respect to (a) any alleged material breach of any Lease or Contract, (b) any action to alter, terminate, rescind or procure a judicial reformation of any Lease or Contract or (c) any new claim for damages or any new investigation, suit, action or litigation with respect to the Assets.

Section 7.11.            Enforcement of Third Party Warranties, Guarantees and Indemnities.

Sellers agree that as of the Closing Date, to the extent relating to the Assumed Seller Obligations and at Purchaser’s request, Sellers shall use their commercially reasonable efforts to enforce, for the benefit of Purchaser and at Purchaser’s cost and expense, all of Sellers’ (or their respective Affiliates’) rights against un-Affiliated third parties under any warranties, guarantees or indemnities given by such third parties with respect to the Assets.

ARTICLE 8.
CONDITIONS TO CLOSING

Section 8.1.               Conditions of Sellers to Closing.

The obligations of Sellers 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 Sellers:

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(a)           Representations. Each of the representations and warranties of Purchaser contained in Article 6 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 the Closing Date and shall be ready, willing and able to perform, in all material respects, all covenants and agreements to be performed by Purchaser under this Agreement on the Closing Date;

(c)           Proceedings. No Proceeding by an un-Affiliated third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit, or seeking substantial damages in connection with (excluding any damage that Purchaser expressly agrees to be responsible for), the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction, decree, award or judgment shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction to restrain, enjoin, or prohibit, or awarding substantial damages (excluding any damage that Purchaser expressly agrees to be responsible for) in connection with, the transactions contemplated by this Agreement, 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;

(d)           Deliveries. Purchaser shall have delivered (or be ready, willing and able to immediately deliver) to Sellers duly executed counterparts of the Conveyances 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;

(e)           HSR Act. Except to the extent set forth in Section 7.2(b), and to the extent this transaction is subject to the HSR Act, any waiting period applicable to the consummation of the transactions contemplated by this Agreement under the HSR Act shall have lapsed or terminated (by early termination or otherwise); and

(f)            Price Adjustment Limitations.  The aggregate maximum downward adjustment (if any) of the Purchase Price which will result from adjustments pursuant to Section 3.4 (Notice of Title Defect Adjustments), Section 3.5 (Casualty or Condemnation Loss) and Section 4.3 (Environmental Defects) does not exceed twenty percent (20%) of the Purchase Price.

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Section 8.2.               Conditions of Purchaser to Closing.

The obligations of Purchaser to consummate the transactions contemplated by this Agreement are subject, at the option of Purchaser, to the satisfaction or waiver by Purchaser on or prior to Closing of each of the following conditions:

(a)           Representations. Each of the representations and warranties of Sellers contained in Article 5 shall be true and correct in all material respects (other than those representations and warranties of Sellers that are qualified by materiality, which shall be true and correct in all respects) as of the date hereof 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 material respects (other than those representations and warranties of Sellers that are qualified by materiality, which shall be 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 (without regard to any materiality qualifiers, including a Material Adverse Effect) would not, individually or in the aggregate, result in a Material Adverse Effect;

(b)           Performance.  Sellers shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by Sellers under this Agreement prior to the Closing Date and shall be ready, willing and able to perform, in all material respects, all covenants and agreements to be performed by Sellers under this Agreement on the Closing Date;

(c)           Proceedings. No Proceeding by an un-Affiliated third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit, or seeking substantial damages in connection with (excluding any damages that Sellers expressly agree to be responsible for), the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction, decree, award or judgment shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction to restrain, enjoin, or prohibit, or awarding substantial damages (excluding any damages that Sellers expressly agree to be responsible for) in connection with, the transactions contemplated by this Agreement, 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;

(d)           Deliveries. Sellers shall have delivered or cause to be delivered (or be ready, willing and able to immediately deliver or cause to be delivered) to Purchaser duly executed counterparts of the Conveyances and all other documents and certificates to be delivered or caused to be delivered by Sellers under Section 9.2;

(e)           HSR Act. Except to the extent set forth in Section 7.2(b), and to the extent this transaction is subject to the HSR Act, any waiting period applicable to the consummation of the transactions contemplated by this Agreement under the HSR Act shall have lapsed or terminated (by early termination or otherwise); and

(f)            Price Adjustment Limitations.  The aggregate maximum downward adjustment (if any) of the Purchase Price which will result from adjustments pursuant to Section 3.4 (Notice of Title Defect Adjustments), Section 3.5 (Casualty or Condemnation Loss) and Section 4.3 (Environmental Defects) does not exceed twenty percent (20%) of the Purchase Price.

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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 Sections 3.4 and 7.7 relating to delayed Closings, the Closing, shall take place at 10:00 a.m., local time, on April 18, 2014 (such date the “Scheduled Closing Date”), at the offices of Halcón Resources Corporation, 1000 Louisiana, Suite 6700, Houston, Texas, unless the date for Closing is extended pursuant to Section 3.4(k) and/or Section 4.3(b), in which case the Closing shall take place on such extended date or such other date, time or place is mutually agreed to in writing by Purchaser and Sellers.  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.  For purposes of clarity with respect to the Material Adverse Effect qualification set forth in the closing condition in Section 8.2(a), the Closing and completion of the transactions contemplated by this Agreement shall not prohibit or preclude Purchaser from asserting any claims against Sellers for breach of the representations or warranties of Sellers contained in Article 5 that Purchaser would otherwise be entitled to assert in accordance with the terms of this Agreement.

(b)           The date on which the Closing occurs is herein referred to as the “Closing Date”.

Section 9.2.               Obligations of Sellers at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Sellers shall deliver or cause to be delivered to Purchaser, or perform or cause to be performed, the following:

(a)           the Conveyances, in sufficient number of counterpart originals to allow recording in all appropriate jurisdictions and offices, duly executed and acknowledged by each Seller;

(b)           assignments, on appropriate forms and in sufficient number of counterpart originals to allow filing in the applicable state and federal offices, of any state and federal leases comprising part of the Assets, duly executed and (if applicable) acknowledged by each Seller;

(c)           transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Purchaser of proceeds attributable to production from the Assets from and after the Effective Time, in each case duly executed by the applicable Seller and prepared in accordance with Section 7.4(a);

(d)           a certificate duly executed by an authorized corporate officer of each Seller, dated as of Closing, certifying on behalf of Sellers that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

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(e)           evidence that all lien releases from the Sellers’ current lenders have been obtained relating to all mortgages, deeds of trust, fixture filings and security agreements affecting the Assets, and that releases of any related financing statements have been obtained (where applicable, in accordance with the Uniform Commercial Code);

(f)            the change or transfer of operator forms referenced in Section 7.4(c) to be executed by each applicable Seller and which forms shall be filed by Purchaser pursuant to Section 7.4(c) after Closing;

(g)           a certificate that such Seller is not a foreign person within the meaning of the Code, as described in Treasury Regulation 1.1445-2(b)(2);

(h)           the Preliminary Settlement Statement, duly executed by each Seller;

(i)            a Transition Services Agreement in substantially the form attached hereto as Exhibit D (the “Transition Services Agreement”) duly executed by Sellers; and

(j)            duly executed counterparts of any other agreements, instruments or documents which are required by the other terms of this Agreement to be executed and/or delivered by Sellers at the Closing.

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 Sellers, or perform or caused to be performed, the following:

(a)           a wire transfer to each Seller (to the accounts designated in Schedule 9.4(d)) in an amount equal to such Seller’s Closing Payment, in immediately available funds;

(b)           the Conveyance, in sufficient number of counterpart originals to allow recording in all appropriate jurisdictions and offices, duly executed and acknowledged by Purchaser;

(c)           assignments, on appropriate forms and in sufficient number of counterpart originals to allow filing in the applicable state and federal offices, of any state and federal leases comprising portions of the Assets, duly executed and (if applicable) acknowledged by Purchaser;

(d)           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;

(e)           transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Purchaser of proceeds attributable to production from the Assets from and after the Effective Time, in each case duly executed by Purchaser and prepared in accordance with Section 7.4(a);

(f)            the Preliminary Settlement Statement, duly executed by Purchaser;

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(g)           The Transition Services Agreement, duly executed by Purchaser; and

(h)           duly executed counterparts of any other agreements, instruments or documents which are required by the other terms of this Agreement to be executed and/or delivered by Purchaser at the Closing.

Section 9.4.               Closing Adjustments.

(a)           Not later than five (5) Business Days prior to the Closing Date, Sellers shall prepare in good faith and deliver to Purchaser, based upon the best information available to Sellers at such time, a draft preliminary settlement statement (the “Preliminary Settlement Statement”) estimating each Seller’s share of the Adjusted Purchase Price after giving effect to all adjustments listed in Section 2.2 and any amounts to be escrowed pursuant to Section 3.4(k) and reflecting the calculation of the adjustments used to determine such amounts. Within three (3) Business Days of receipt of the Preliminary Settlement Statement, Purchaser will deliver to Sellers a written report containing all changes, with the explanation therefor, that Purchaser proposes to be made to the Preliminary Settlement Statement.  The Preliminary Settlement Statement, as agreed upon by Sellers and Purchaser, will be used to adjust the Adjusted Purchase Price and determine the dollar amount to be paid by Purchaser to each Seller at the Closing (each, the “Closing Payment”). If Sellers and Purchaser cannot agree on the Preliminary Settlement Statement prior to Closing, the Preliminary Settlement Statement as presented by Sellers (with such changes agreed to by the parties) will be used to adjust the Adjusted Purchase Price and determine each Closing Payment.

(b)           As soon as reasonably practicable after the Closing but not later than 120 days following the Closing Date, Sellers shall prepare and deliver to Purchaser a statement (the “Final Settlement Statement”) setting forth the final calculation of the Adjusted Purchase Price, and each Seller’s share thereof, and showing the calculation of each adjustment, based 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, including any amount escrowed pursuant to Section 3.4(k) (the “Final Purchase Price”). Sellers shall, at Purchaser’s request, supply reasonable documentation in Sellers’ or their Affiliates’ possession available to support any credit, charge, receipt or other item for which adjustments are made. Sellers 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 Sellers’ statement hereunder, Purchaser shall deliver to Sellers a written report containing any changes that Purchaser proposes be made to such statement.

(c)           Sellers and Purchaser shall undertake to agree on the Final Settlement Statement, including the final statement of the Final Purchase Price, and each Seller’s share thereof, no later than one hundred eighty (180) days after the Closing Date (the “Final Settlement Date”). In the event that Sellers and Purchaser cannot reach agreement by the Final Settlement Date, either party may refer the remaining matters in dispute to a nationally-recognized independent

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accounting firm as may be mutually selected by Purchaser and Sellers (and absent such mutual selection, as appointed by the Houston office of the American Arbitration Association), for review and final determination (the “Agreed Accounting Firm”).  Each of Purchaser, on the one hand, and Sellers, on the other hand, 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 Sellers’ position or Purchaser’s position, whichever is most accurate based on the terms of this Agreement and the materials described above. The Agreed Accounting Firm may not award damages or penalties to any party.  Any decision rendered by the Agreed Accounting Firm pursuant hereto shall be final, conclusive and binding on Sellers and Purchaser and will be enforceable against any of the parties hereto in any court of competent jurisdiction. The fees of the Agreed Accounting Firm shall be borne and paid one-half by Sellers and one-half by Purchaser.  Sellers 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 Sellers and Purchaser or the Agreed Accounting Firm, as applicable, finally determines the disputed matters, subject to Section 3.4(k) with respect to any amounts escrowed pursuant thereto (x) Purchaser shall pay to Sellers each Seller’s share of the amount by which the Final Purchase Price exceeds the Closing Payment or (y) each Seller shall pay to Purchaser the amount by which such Seller’s share of the Closing Payment exceeds such Seller’s share of the Final Purchase Price, as applicable.

(d)           All payments made or to be made hereunder to a Seller shall be by electronic transfer of immediately available funds to the account of such Seller as set forth on Schedule 9.4(d), for the credit of Sellers or to such other bank and account as may be specified by such Seller to Purchaser 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 Sellers.

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:

(a)           by mutual written consent of Sellers and Purchaser;

(b)           by Sellers or by Purchaser, by written notice to the other, if:

(i)            the Closing shall not have occurred on or before May 18, 2014; provided that if any title or environmental matters are submitted to a Title Expert and/or Independent Expert in accordance with Section 3.4(k) or Section 4.3(b), as applicable, such date will be extended to be the date that is the 15th Business Day following  the decision of the Title Expert and/or Independent Expert pursuant to such Section or Sections, as applicable (such date, as may be so

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extended, the “Termination Date”); provided, however, that the right to terminate this Agreement under this Section 10.1(b)(i) shall not be available (A) to any Seller, if any breach of this Agreement by a Seller has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date or (B) to Purchaser, if any breach of this Agreement by Purchaser has been the principal cause of, or resulted in, the failure of the Closing to occur on or before 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 Sellers, if Purchaser shall have failed to fulfill in any material respect any of its obligations under this Agreement; and such failure has not been cured within twenty (20) 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;

(d)           by Purchaser, if a Seller shall have failed to fulfill in any material respect any of its obligations under this Agreement, and, such failure, if curable, has not been cured within ten (10) days after written notice thereof from Purchaser to such Seller; provided that any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date;

(e)           by Sellers, if the condition set forth in Section 8.1(f) has not been satisfied or waived in writing by Sellers; or

(f)            by Purchaser, if the condition set forth in Section 8.2(f) has not been satisfied or waived in writing by Purchaser.

Section 10.2.            Remedies.

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 2.4, Section 4.4, Section 5.6, Section 6.5, Section 7.5, Section 11.9 and Section 11.10 of this Agreement and this Article 10, the Section entitled “Definitions,” and Article 12 (other than Section 12.3, Section 12.4, Section 12.5, Section 12.6 and Section 12.20), all of which shall continue in full force and effect).  Notwithstanding the foregoing but subject to the remainder of this Section 10.2, nothing contained in this Section 10.2 shall relieve any party from liability for Losses resulting from its breach of this Agreement.  If Sellers terminate this Agreement (a) because the Closing has not occurred on or before the Termination Date and Purchaser’s breach of this Agreement has been the principal cause of, or resulted in, the failure of Closing to occur on or before the Termination Date; or (b) as the result of any failure of Purchaser to fulfill in any material respect any of Purchaser’s obligations hereunder and such failure is not cured as provided in Section 10.1(c), then Sellers shall be entitled to receive the Deposit from Escrow Agent as liquidated damages

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and Sellers’ sole and exclusive remedy on account of the termination of this Agreement and any such breaches. If Purchaser terminates this Agreement or is entitled to terminate this Agreement (i) because the Closing has not occurred on or before the Termination Date and a Seller’s breach of this Agreement has been the principal cause of, or resulted in, the failure of Closing to occur on or before the Termination Date; or (ii) as the result of any failure of any Seller to fulfill in any material respect any of such Seller’s obligations hereunder and such failure is not cured as provided in Section 10.1(d), then Purchaser shall be entitled to (A) seek specific performance of the terms of this Agreement (in which case, this Agreement shall not terminate) or (B) the Deposit (and the Deposit shall be released back to Purchaser by wire transfer in immediately available funds, pursuant to written instructions to be delivered to Escrow Agent by Purchaser to Sellers) and damages from Sellers for the Losses suffered by Purchaser on the account of a breach of this Agreement by any Seller.

ARTICLE 11.

POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS;

DISCLAIMERS AND WAIVERS

Section 11.1.            Receipts.

Except as otherwise provided in this Agreement, Any Hydrocarbons produced from or allocable to the Oil and Gas Properties (and all products and proceeds attributable thereto) and any other income, proceeds, revenues, receipts and credits attributable to the Assets which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a)  (i) all Hydrocarbons produced from or allocable to the Oil and Gas Properties (and all products and proceeds attributable thereto) and all other revenues, income, proceeds, receipts and credits earned with respect to the Oil and Gas Assets to which Purchaser is entitled under Section 1.4 shall be the sole property and entitlement of Purchaser; (ii) all fees, rentals proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets to which Purchaser is entitled under Section 1.4 shall be the sole property and entitlement of Purchaser; and (iii) to the extent received by Sellers, Sellers shall fully disclose, account for and remit the same promptly to the relevant Purchaser; and (b)  (i) all Hydrocarbons produced from or allocable to the Oil and Gas Properties (and all products and proceeds attributable thereto) and all other income, proceeds, revenues, receipts and credits earned with respect to the Oil and Gas Assets to which the Oil and Gas Sellers are entitled under Section 1.4 shall be the sole property and entitlement of the Oil and Gas Sellers; (ii) all fees, rentals proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets to which HFS is entitled under Section 1.4 shall be the sole property and entitlement of HFS; and (iii) to the extent received by Purchaser, Purchaser shall fully disclose, account for and remit the same promptly to the relevant Seller(s).

Section 11.2.            Expenses.

Any Property Costs which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a) all Property Costs for which Sellers are responsible under Section 1.4 shall be the sole obligation of Sellers and Sellers shall promptly pay, or if paid by Purchaser, promptly reimburse Purchaser for and hold Purchaser harmless from and against same; and (b) all Property Costs for which

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Purchaser is responsible under Section 1.4 shall be the sole obligation of Purchaser, and Purchaser shall promptly pay, or if paid by Sellers, promptly reimburse Sellers for and hold Sellers harmless from and against same. Sellers are entitled to resolve all joint interest audits and other audits of Property Costs (including payment of any third party audit fees and expenses) covering periods for which Sellers are wholly responsible and Purchaser is entitled to resolve all joint interest audits and other audits of Property Costs (including payment of any third party audit fees and expenses) covering periods for which Purchaser is in whole or in part responsible; provided that Purchaser shall not agree to any adjustments to previously assessed costs for which Sellers are liable without the prior written consent of Seller, such consent not to be unreasonably withheld, conditioned or delayed. Purchaser shall provide Sellers with a copy of all applicable audit reports and written audit agreements received by Purchaser and relating to periods for which Sellers are partially or wholly responsible, and Sellers shall provide Purchaser with a copy of all applicable audit reports and written audit agreements received by a Seller and relating to periods for which Purchaser is partially or wholly responsible.

Section 11.3.            Assumed Seller Obligations.

Subject to the indemnification by Sellers under Section 11.5 and Purchaser’s rights under (a) any title indemnity agreement entered into by the parties pursuant to this Agreement and (b) the special warranty of title contained in the Conveyances, from and after the Closing Purchaser shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) (i) all of the following obligations and liabilities of each 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 up to the Closing Date: (A) the obligation to 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) the obligation to pay the holders of working interests, royalties, overriding royalties and other interests the Suspended Funds to which they are entitled (it being agreed that, notwithstanding anything in this Agreement to the contrary, subject to the provisions of Section 12.20 below, Purchaser shall be solely responsible for the distribution of all Suspended Funds transferred or credited to Purchaser pursuant hereto, and that Purchaser’s obligations relating thereto shall be limited to the Suspended Funds actually delivered by Sellers to Purchaser), (C) the obligation to properly plug and abandon any and all wells, including inactive wells or temporarily abandoned wells, drilled on the Properties, as required by Law, (D) the obligation to replug any well, wellbore, or previously plugged well on the Properties to the extent required by any Governmental Body, (E) the obligation to 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) the obligation to clean up, restore, remediate or otherwise respond to Hazardous Materials on, at or migrating from the premises covered by or included in the Assets in accordance with applicable Contracts 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) the obligation to perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and related joint operating agreements, or as required by applicable Laws; and (ii) the obligation to perform all obligations applicable to or imposed on Sellers under the Contracts (excluding any joint operating agreements), insofar as and only insofar as the same arise and are solely and directly attributable to the periods from and after the Effective Time.  All of such duties, obligations, responsibilities,

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and liabilities to be assumed by Purchaser with respect to the Oil and Gas Assets and Midstream Assets shall be referred to herein as the “Assumed Oil and Gas Obligations” and the “Assumed Midstream Obligations,” respectively (collectively, the “Assumed Seller Obligations”).  Notwithstanding the terms of Section 11.3 to the contrary, the Assumed Seller Obligations shall not include, and Purchaser shall have no obligation to assume, any obligations or liabilities to the extent that they are (such excluded obligations and liabilities, the “Excluded Seller Obligations”):

(A)          attributable to, or arise out of, the ownership, use or operation of the Excluded Assets;

(B)          the continuing responsibility of Sellers under Section 11.1 or Section 11.2;

(C)          Property Costs for which any Seller is responsible pursuant to Section 1.4(b); and

(D)          attributable to, or arise out of, the Retained Liabilities.

Section 11.4.            Survival and Limitations; Exclusive Remedy.

(a)           The representations and warranties contained in Article 5 and Article 6 (other than the Fundamental Representations and the Tax Representations) shall terminate six (6) months after Closing (the “Survival Date”).  The representations and warranties contained in Section 5.2, Section 5.3, Section 5.4, Section 5.6, Section 6.1, Section 6.2, Section 6.3, and Section 6.5 (collectively, the “Fundamental Representations”) shall survive the Closing without time limit, and the representations and warranties of Sellers contained in Section 5.8 and Section 5.20 shall survive the Closing until the expiration of the applicable statute of limitations period plus 30 days (collectively, the “Tax Representations”). 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; provided that, subject to Section 11.4(b), there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation or warranty prior to its expiration date. The covenants and other agreements of each 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 survive the Closing Date and delivery and recordation of the Conveyance hereunder until the Survival Date; provided however, that covenants and agreements of each Seller and Purchaser set forth in Section 7.8 shall survive until the expiration of the applicable statute of limitations period plus thirty (30) days.  The covenants and agreements of each 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 the date that is six (6) months after such covenants and agreements are fully performed pursuant to the terms of this Agreement; provided however, that covenants and agreements of each Seller and Purchaser set forth in Section 7.8 shall survive until the expiration of the applicable statute of limitations period plus thirty (30) days. 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; provided that, subject to Section 11.4(b), there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a covenant or agreement prior to its expiration date.  The indemnities in Section 11.5(a), Section 11.5(b), Section 11.6(a) and Section 11.6(b) shall terminate as of the termination date of each respective representation, warranty, covenant or

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agreement that is subject to indemnification.  Notwithstanding anything in this Agreement to the contrary, (i) Sellers’ indemnity set forth in Section 11.5(c) shall survive the Closing without time limit and (ii) Purchaser’s indemnities set forth in Section 11.6(c) and Section 11.6(d) shall survive the Closing without time limit.  Subject to Section 11.4(b), there shall be no termination of a bona fide claim asserted pursuant to the indemnities prior to the date of termination for such indemnity.

(b)           No party hereto 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 11.4(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 11.4(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. A Claim Notice shall set forth with reasonable specificity (1) the basis for such claim under this Agreement, and the facts that otherwise form the basis of such claim and (2) to the extent reasonably estimable, an estimate of the amount of such claim (which estimate shall not be conclusive of the final amount of such claim) and an explanation of the calculation of such estimate.

(c)           No party shall have any liability for any indemnification under Section 11.5(a) and/or Section 11.6(a) of this Agreement, as applicable (except for breaches of Fundamental Representations and Tax Representations), until and unless (i) the amount of the Loss 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 or Sellers, as applicable, and for which the Indemnifying Party is liable, exceeds $15,000 (“Individual Indemnity Threshold”), and (ii) the aggregate amount of the Losses for all claims for which Claim Notices are delivered by Purchaser or Seller, as applicable, and for which the Indemnifying Party is liable under this Agreement after application of the provisions of clause (i) above, exceeds one-half of one percent (0.5%) of the Purchase Price, and then only to the extent such damages exceed one-half of one percent (0.5%) of the Purchase Price (the “Aggregate Indemnity Deductible”); provided that (A) Sellers’ indemnities in Section 11.5(a) (with respect to the Fundamental Representations and Tax Representations only), Section 11.5(b) and Section 11.5(c) and (B) Purchaser’s indemnities in Section 11.6(a) (with respect to the Fundamental Representations only), Section 11.6(b), Section 11.6(c) and Section 11.6(d) shall not be limited by this Section 11.4(c).  For the avoidance of doubt, claims for which Claim Notices are delivered by Purchaser or Sellers, as applicable, which do not meet the Individual Indemnity Threshold shall not be included in reaching the Aggregate Indemnity Deductible.  For purposes of determining whether there has been a breach of any of Sellers’ representations and warranties for which Purchaser is entitled to indemnification under Section 11.5(a) and the Losses resulting from any such breach, any dollar or materiality qualifiers in Sellers’ representations and warranties shall be disregarded.

(d)           Except as expressly provided elsewhere in this Agreement, Sellers shall not be required to indemnify Purchaser pursuant to Section 11.5(a) (except with respect to breaches of Fundamental Representations and Tax Representations) for aggregate Losses in excess of twenty

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percent (20%) of the Purchase Price.  Except as expressly provided elsewhere in this Agreement, Sellers shall not be required to indemnify Purchaser pursuant to Section 11.5(a) for aggregate Losses attributable to breaches of Fundamental Representations in excess of one hundred percent (100%) of the Purchase Price.

(e)           Absent fraud, the sole and exclusive remedy of the parties with respect to the Assets and the transactions contemplated hereby shall be pursuant to the express provisions of this Agreement (including pursuant to this Section 11.4(e)) and any agreement delivered between the parties at Closing (including any title indemnity agreement entered into by the parties pursuant to this Agreement and the Conveyances).  Without limitation of the foregoing, absent fraud and except with respect to (i) Purchaser’s rights with respect to the special warranty of title contained in the Conveyances and (ii) any claims or Losses attributable to any breach by Purchaser or Sellers (as applicable) of any of the provisions of Section 1.5, Section 3.7(b), Section 7.5, Section 7.7, Section 7.8, Section 7.9, Section 7.11, Section 9.4, Section 11.1 and Section 11.2 (each, a “Specified Covenant”), if the Closing occurs, the sole and exclusive remedy of the parties 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 Agreement and any other agreement delivered between the parties at Closing and, and if no such right of indemnification is expressly provided, then such claims are hereby waived to the fullest extent permitted by Law.  In the event of any breach by a party of any of the provisions of any Specified Covenant, the non-breaching party(ies), in addition to any rights of indemnification set forth herein or in any agreement delivered between the parties at Closing, shall have all rights at Law or in equity with respect to or on account of such breach, including the right to seek specific performance and injunctive relief (without the necessity of posting any bond in connection therewith).

Section 11.5.            Indemnification by Each Seller.

Subject to the terms, conditions, and limitations of this Article 11, from and after the Closing, Sellers are responsible for, shall pay on a current basis and hereby jointly and severally indemnify, defend and hold harmless Purchaser and its Affiliates, and its and their respective directors, officers, employees, members, agents, consultants, advisors and other representatives (including legal counsel, accountants and financial advisors) and the successors and permitted assigns of each of the foregoing (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, directly or indirectly, to the extent resulting from, arising out of or relating to:

(a)           any breach of any representation or warranty of a Seller contained in this Agreement or in any certificate furnished by or on behalf of a Seller in connection with this Agreement;

(b)           any breach or nonfulfillment of or failure to perform any covenant or agreement of a Seller contained in this Agreement or in any certificate furnished by or on behalf of a Seller in connection with this Agreement; and

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(c)           the Excluded Seller Obligations, REGARDLESS OF FAULT.

Notwithstanding anything to the contrary contained herein, the indemnity obligations of Sellers in Section 11.5(b) and Section 11.5(c) shall not be subject to the deductibles, cap and other monetary limitations in Section 11.4.  Notwithstanding anything to contrary contained herein, the indemnity obligations of Sellers set forth in Section 11.5(c) shall survive Closing without time limit.

Section 11.6.            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 each Seller, its Affiliates and its and their directors, officers, employees, agents, consultants, advisors and other representatives (including legal counsel, accountants and financial advisors) and the successors and permitted assigns of each of the foregoing (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 Sellers in connection with this Agreement;

(b)           any breach or nonfulfillment of or failure to perform any covenant or agreement of Purchaser contained in this Agreement or any certificate furnished by or on behalf of Purchaser to Sellers in connection with this Agreement;

(c)           the Assumed Seller Obligations, REGARDLESS OF FAULT; and

(d)           the indemnity obligations set forth in Section 4.4;

but excepting, in each case, Losses with respect to which Sellers are required to indemnify Purchaser and the Purchaser Indemnified Persons pursuant to Section 11.5 or otherwise pursuant to this Agreement or any document or agreement executed in connection herewith.

The indemnity obligations in Section 11.6(b), (c) and (d) shall not be subject to the deductibles and other monetary limitations in Section 11.4.

Section 11.7.            Indemnification Proceedings.

(a)           In the event that any claim or demand for which Sellers or Purchaser (in each case, as applicable, an “Indemnifying Party”) may be liable to a Purchaser Indemnified Person under Section 11.5 or to a Seller Indemnified Person under Section 11.6 (as applicable, an “Indemnified Party”) is asserted against or sought to be collected from an Indemnified Party by an un-Affiliated third party (a “Third Party Claim”), the Indemnified Party shall with reasonable promptness after the Indemnified Party has Actual Knowledge of the Third Party Claim notify the Indemnifying Party of such Third Party Claim by delivery of a Claim Notice and a copy of

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all papers (if any) served with respect to such Third Party Claim, provided that, except as otherwise expressly provided in this Article 11 (including Section 11.4(b)), 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 that the Indemnifying Party demonstrates (to the reasonable satisfaction of the Indemnified Party) that (i) it had insufficient time available to permit such Indemnifying Party to effectively defend against the Third Party Claim or (ii) its defense of such Third Party Claim is otherwise materially prejudiced by such failure or delay. In the case of a claim for indemnification based on a Third Party Claim, the Indemnifying Party shall have thirty (30) days from receipt of the Claim Notice from the Indemnified Party (in this Section 11.7, 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)           Subject to Section 11.7(d), the Indemnifying Party shall have the right to assume the defense of such Third Party Claim (at its sole cost and expense) 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 agrees to cooperate in contesting any such Third Party Claim to the extent such cooperation is so requested by the Indemnifying Party, and, further, 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, conditioned or delayed). 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, otherwise is not entitled to assume such defense or fails to diligently prosecute or

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settle the Third Party Claim), 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, (except with respect to the matters on Schedule 5.7(a) for which Sellers have indemnified Purchaser) the Indemnifying Party shall not be entitled to control the defense of (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, settlement, compromise, admission or acknowledgment of any Third Party Claim if (i) the Indemnified Person has been advised by counsel that an actual conflict of interest exists between the Indemnifying Party and the Indemnified Party in connection with the defense of such Third Party Claim, (ii) the Third Party Claim, individually or in the aggregate with any other claim, involves potential Losses that exceed the amount of the indemnification available under this Agreement, (iii) the Third Party Claim seeks injunctive relief or is part of a criminal proceeding or (iv) the Third Party Claim would reasonably be expected to have a material adverse effect on the Indemnified Person’s business or relates to its customers, suppliers, vendors or other service providers; provided, however, in the event that the Indemnifying Party is not entitled to assume exclusive control of the defense, then the Indemnifying Party shall not be bound by any determination resulting from any compromise or settlement effected without its consent (which may not be unreasonably withheld, conditioned or delayed).

(e)           Subject to Section 11.4(b), 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 actual knowledge of the Loss giving rise to indemnification hereunder. Except as otherwise expressly provided in this Article 11 (including Section 11.4(b)), 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 or otherwise prejudices the Indemnifying Party.  In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to (i) cure the Losses complained of, (ii) admit its obligation to indemnify for and bear all expenses associated with such Losses or (iii) dispute the claim for such Losses.  If the Indemnifying Party does not notify the Indemnified Party within such 30 day period that it has cured the subject Losses or that it disputes the claim for such Losses, the amount of such Losses shall conclusively be deemed a liability of the Indemnifying Party hereunder.

Section 11.8.            Release.

EXCEPT WITH RESPECT TO (A) POST-CLOSING REMEDIATION AGREED TO PURSUANT TO SECTION 4.3 AND (B) PURCHASER’S REMEDIES UNDER SECTION 11.5, PURCHASER HEREBY RELEASES, REMISES AND FOREVER DISCHARGES THE SELLER INDEMNIFIED PERSONS FROM ANY AND ALL

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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 TO OR ARISING OUT OF (1) THE VIOLATION OF ANY ENVIRONMENTAL LAWS WITH RESPECT TO THE ASSETS, (II) ANY ENVIRONMENTAL LIABILITIES WITH RESPECT TO THE ASSETS, (III) ANY ENVIRONMENTAL DEFECTS, (IV) THE RELEASE OF MATERIALS INTO THE ENVIRONMENT WITH RESPECT TO THE ASSETS OR THE PROTECTION OF NATURAL RESOURCES OR THE ENVIRONMENT, INCLUDING, WITHOUT LIMITATION, RIGHTS TO CONTRIBUTION UNDER CERCLA, REGARDLESS OF FAULT.

Section 11.9.            Disclaimers.

(a)           EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, OR IN THE CERTIFICATE OF EACH SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCES, (I) SELLERS MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLERS EXPRESSLY DISCLAIM 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 SELLERS OR ANY OF THEIR RESPECTIVE AFFILIATES).

(b)           EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 5 OF THIS AGREEMENT, OR IN THE CERTIFICATE OF EACH SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCEs, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, EACH 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 SELLERS 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

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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 (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(c)           OTHER THAN AS SET FORTH IN SECTION 5.9, SELLERS HAVE 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.

Section 11.10.          [Intentionally Omitted].

Section 11.11.          Recording.

As soon as practicable after Closing, Purchaser shall record the Conveyances in the appropriate counties where the Oil and Gas Properties and the Surface Rights are located and provide each Seller with copies of all recorded or approved instruments. The Conveyances in the form attached as Exhibit B-1 and Exhibit B-2 are intended to convey all of the Oil and Gas Properties and Surface Rights being conveyed pursuant to this Agreement. Certain Oil and Gas Properties and Surface Rights or specific portions of the Oil and Gas Properties and Surface Rights that are leased from, or require the approval to transfer by, a Governmental Body are conveyed under the Conveyances and also are described and covered under separate assignments made by Sellers to Purchaser on officially approved forms, 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 Conveyances attached as Exhibit B-1 and Exhibit B-2.  Further, such assignments shall be deemed to contain all of the exceptions, reservations, rights, titles, power and privileges set forth herein and in the Conveyances as fully and only to the extent as though they were set forth in each such separate assignment.

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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 Sellers or Seller Representative:	Halcón Resources Corporation 1000 Louisiana, Suite 6700 Houston, Texas 77002 Attention: Steve Herod Phone: 832-538-0506 Email: sherod@halconresources.com and Halcón Resources Corporation 1000 Louisiana, Suite 6700 Houston, Texas 77002 Attention: David Elkouri Phone: 832-538-0514 Email: delkouri@halconresources.com
If to Purchaser:	New Gulf Resources, LLC Spirit Bank Event Center, 2nd Floor Tulsa, Oklahoma 74133 10441 S. Regal Blvd., Ste. 210 Attention: Tracy A. Poole Phone: 918-728-3020 Email: tpoole@newgulfresources.com and New Gulf Resources, LLC Spirit Bank Event Center, 2nd Floor Tulsa, Oklahoma 74133

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	10441 S. Regal Blvd., Ste. 210 Attention: Tyler P. Evans Phone: 918-728-3020 Email: tevans@newgulfresources.com
With a copy to (which shall not constitute notice to Purchaser):	Conner & Winters, LLP 4000 One Williams Center Tulsa, Oklahoma 74172-0148 Attention: R. Kevin Redwine Phone: (918) 586-8540 Email: kredwine@cwlaw.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. Purchaser will determine the amount of any Transfer Taxes, if any, that is due in connection with the transactions contemplated by this Agreement and Purchaser agrees to pay any such Transfer Tax to the appropriate Governmental Body. If any of the transactions contemplated by this Agreement are exempt from any such Transfer Taxes upon the filing of an appropriate certificate or other evidence of exemption, Purchaser will timely furnish to Sellers such certificate or evidence.

Section 12.4.            Expenses.

Except as otherwise expressly provided in Section 12.3 or elsewhere in this Agreement, (a) all expenses incurred by Sellers in connection with or related to the authorization, preparation or execution of this Agreement, the Conveyances 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 Sellers, shall be borne solely and entirely by Sellers, 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.            Change of Name.

As promptly as practicable, but in any case within sixty (60) days after the Closing Date, Purchaser shall eliminate the names “Halcón”, “HK”, “HRC”, “HFS” and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Sellers or any of their Affiliates.

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Section 12.6.            Replacement of Bonds, Letters of Credit and Guarantees.

The parties understand that none of the Bonds, if any, posted by Sellers or any of their Affiliates with Governmental Bodies and relating to the Assets may be transferable to Purchaser.  Except as provided in Section 7.4(c), prior to Closing, Purchaser shall have obtained, or caused to be obtained in the name of Purchaser, replacements for such Bonds, to the extent such replacements are necessary to permit the cancellation of such Bonds posted by Sellers or any of their Affiliates or to consummate the transactions contemplated by this Agreement.

Section 12.7.            Governing Law and Venue.

THIS AGREEMENT AND THE LEGAL RELATIONS AMONG 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 TO BE DETERMINED UNDER SECTION 3.4(k), SECTIONS 4.3(b) AND (c) AND SECTION 9.4) SHALL BE PROPER ONLY IN HARRIS COUNTY, TEXAS.  EACH PARTY HERETO WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY DISPUTE.

Section 12.8.            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 12.9.            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 12.10.          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, except that Purchaser may assign any of its rights and obligations hereunder to one or more of its Affiliates without the consent of any other party.  No assignment hereunder by any party shall relieve such party of any obligations and responsibilities hereunder. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.

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Section 12.11.          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 12.12.          Amendment.

(a)           This Agreement may be amended or modified only by an agreement in writing executed by the parties hereto.

(b)           No waiver of any right under this Agreement shall be binding unless executed in writing by the party to be bound thereby.

Section 12.13.          No Third-Party Beneficiaries.

Nothing in this Agreement shall entitle any Person other than Purchaser or Sellers 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 may only be made and administered by a party to this Agreement).

Section 12.14.          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;

(c)           Reference to any Article or Section means an Article or Section of this Agreement;

(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 include or including, as applicable, without limitation; and

(g)           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.

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Section 12.15.          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. Each Seller and Purchaser has 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 12.16.          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 12.17.          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 any materially adverse manner with respect to either party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 12.18.          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 12.19.          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 special, punitive, exemplary, consequential or indirect damages or loss of profits 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.

70

Section 12.20.          Suspended Funds.

Sellers covenant to deliver to Purchaser, within thirty (30) days after Closing, in Microsoft Excel format, the owner name, owner number, social security or federal ID number, reason for suspense, and the amount of Suspended Funds payable for each entry, together with monthly line item production detail including gross and net volumes and deductions for all suspense entries.  Upon receipt of such information, Purchaser shall administer all such accounts and distribute such Suspended Funds in accordance with all applicable Laws to the proper parties.

Section 12.21.          Joint and Several Liability.

The representations, warranties and covenants made by (and the obligations of) Sellers in and under this Agreement are joint and several.

Section 12.22.          Seller Representative.

For purposes of this Agreement, each Seller, without any further action, shall be deemed to have consented to the appointment of HEPI as its representative (in such capacity, the “Seller Representative”), as the attorney-in-fact for and on behalf of such Seller, with respect to the exercise of any decision, right, consent, election or other action that such Seller is required or permitted to make or take under the terms of this Agreement (the “Delegated Matters”) and Purchaser may rely on the decisions of Seller Representative with respect to all Delegated Matters.  For the avoidance of doubt, notwithstanding anything to the contrary herein, Sellers will be treated as a single party for purposes of any election, exercise of a right, consent or similar action to be made by Sellers under this Agreement.  The parties further acknowledge that Purchaser shall have no responsibility to determine the portion of the Purchase Price or Adjusted Purchase Price to be paid to any Seller and shall be entitled to rely on the Preliminary Settlement Statement and Final Settlement Statement, as well as instructions by the Seller Representative as to the portion of the Purchase Price or Adjusted Purchase Price payable to any Seller hereunder.

[SIGNATURES BEGIN ON THE FOLLOWING PAGE]

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IN WITNESS WHEREOF, this Agreement has been signed by each of the parties hereto as of the date first above written.

SELLERS:
HALCÓN ENERGY PROPERTIES, INC.
By:	/s/ Steve W. Herod
Name:	Steve W. Herod
Title:	President
HALCÓN FIELD SERVICES, LLC
By:	/s/ Rich DiMichele
Name:	Rich DiMichele
Title:	President
HK ENERGY, LLC
By:	/s/ Steve W. Herod
Name:	Steve W. Herod
Title:	President
HALCÓN OPERATING CO., INC.
By:	/s/ Steve W. Herod
Name:	Steve W. Herod
Title:	President
HK ENERGY OPERATING, LLC
By:	/s/ Steve W. Herod
Name:	Steve W. Herod
Title:	President
HALCÓN RESOURCES OPERATING, INC.
By:	/s/ Steve W. Herod
Name:	Steve W. Herod
Title:	President

72

PURCHASER:
NEW GULF RESOURCES, LLC
By:	/s/ Tracy A. Poole
Name:	Tracy A. Poole
Title:	President and Chief Executive Officer

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EX-12.1

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Exhibit 12.1

Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
(In thousands, except ratios)

	Three Months Ended March 31,						Years Ended December 31,
	2014			2013			2013			2012			2011		2010		2009
Earnings:
Income (loss) before income taxes	$	(72,964	)	$	8,759		$	(1,380,378	)	$	(67,066	)	$	5,399	$	3,412	$	(74,730	)
Adjustments:
Equity investment (income) loss		(831	)		67			(97	)		(373	)		—		—		—
Interest capitalized		(46,816	)		(52,804	)		(203,993	)		(53,492	)		—		—		—
Income (loss) before income taxes, as adjusted	$	(120,611	)	$	(43,978	)	$	(1,584,468	)	$	(120,931	)	$	5,399	$	3,412	$	(74,730	)
Fixed charges		79,275			58,221			262,046			86,589			17,808		23,087		19,021
Total earnings	$	(41,336	)	$	14,243		$	(1,322,422	)	$	(34,342	)	$	23,207	$	26,499	$	(55,709	)
Fixed charges:
Interest expense and amortization of finance costs	$	78,654		$	57,398		$	259,159		$	85,372		$	17,373	$	22,655	$	18,590
Rental expense representative of interest factor		621			823			2,887			1,217			435		432		431
Total fixed charges	$	79,275		$	58,221		$	262,046		$	86,589		$	17,808	$	23,087	$	19,021
Ratio of earnings to fixed charges		—(1)			—(3)			—(4)			—(5)			1.3		1.1		—(7)
Total fixed charges	$	79,275		$	58,221		$	262,046		$	86,589		$	17,808	$	23,087	$	19,021
Pre-tax preferred dividend requirements		4,959			—			12,132			110,075			—		—		—
Total fixed charges plus preference dividends	$	84,234		$	58,221		$	274,178		$	196,664		$	17,808	$	23,087	$	19,021
Ratio of earnings to combined fixed charges and preference dividends		—(2)			—(3)			—(4)			—(6)			1.3		1.1		—(7)

⁽¹⁾

Due to the Company's "Loss before income taxes, as adjusted" for the three months ended March 31, 2014, the ratio coverage was less than 1:1. The Company must generate additional earnings of $120.6 million to achieve a coverage ratio of 1:1.

⁽²⁾

Due to the Company's "Loss before income taxes, as adjusted" for the three months ended March 31, 2014, the ratio coverage was less than 1:1. The Company must generate additional earnings of $125.6 million to achieve a coverage ratio of 1:1.

⁽³⁾

Due to the Company's "Loss before income taxes, as adjusted" for the three months ended March 31, 2013, the ratio coverage was less than 1:1. The Company must generate additional earnings of $44.0 million to achieve a coverage ratio of 1:1.

⁽⁴⁾

Due to the Company's "Loss before income taxes, as adjusted" in 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.

⁽⁵⁾

Due to the Company's "Loss before income taxes, as adjusted" in 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.

⁽⁶⁾

Due to the Company's "Loss before income taxes, as adjusted" in 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.

⁽⁷⁾

Due to the Company's "Loss before income taxes, as adjusted" in 2009, the ratio coverage was less than 1:1. The Company must generate additional earnings of $74.7 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)

EX-31.1

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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.

	HALCÓN RESOURCES CORPORATION
May 8, 2014	By:	/s/ FLOYD C. WILSON
		Name:	Floyd C. Wilson
		Title:	Chairman of the Board and Chief Executive Officer

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Exhibit 31.1

CERTIFICATIONS FOR FORM 10-Q

EX-31.2

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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.

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 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.

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.

	HALCÓN RESOURCES CORPORATION
May 8, 2014	By:	/s/ MARK J. MIZE
		Name:	Mark J. Mize
		Title:	Executive Vice President, Chief Financial Officer and Treasurer

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Exhibit 31.2

CERTIFICATIONS FOR FORM 10-Q

EX-32

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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 and Chief Executive Officer, 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 three months ended March 31, 2014 (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.

May 8, 2014	/s/ FLOYD C. WILSON Floyd C. Wilson Chairman of the Board and Chief Executive Officer
May 8, 2014	/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)

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DERIVATIVE AND HEDGING ACTIVITIES (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivative and hedging activities
Asset derivative contracts	$ 15,457	$ 24,762
Liability derivative contracts	(53,908)	(37,192)
Derivatives not designated as hedging
Derivative and hedging activities
Asset derivative contracts	15,457	24,762
Liability derivative contracts	(53,908)	(37,192)
Derivatives not designated as hedging | Commodity contracts
Derivative and hedging activities
Number of open commodity derivative contracts	90	86
Derivatives not designated as hedging | Commodity contracts | Current assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	1,214	2,028
Derivatives not designated as hedging | Commodity contracts | Other noncurrent assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts	14,243	22,734
Derivatives not designated as hedging | Commodity contracts | Current liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts	(32,890)	(17,859)
Derivatives not designated as hedging | Commodity contracts | Other noncurrent liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts	$ (21,018)	$ (19,333)
Derivatives not designated as hedging | Commodity contracts | Collars | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts	11	10
Derivatives not designated as hedging | Commodity contracts | Collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	58	52
Derivatives not designated as hedging | Commodity contracts | Swaps | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	8	8
Derivatives not designated as hedging | Commodity contracts | Three-way collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	2	5
Derivatives not designated as hedging | Commodity contracts | Put options | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	1	1
Derivatives not designated as hedging | Commodity contracts | Swaptions | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	8	8
Derivatives not designated as hedging | Commodity contracts | Extendable collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	2	2

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ADDITIONAL FINANCIAL STATEMENT INFORMATION (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$ 169,640	$ 129,355
Joint interest accounts	137,957	170,907
Affiliated partnership	302	500
Other	1,405	11,756
Total	309,304	312,518
Prepaids and other:
Prepaids	5,974	5,636
Income tax receivable	5,404	10,404
Other	58	58
Total	11,436	16,098
Accounts payable and accrued liabilities:
Trade payables	86,708	87,661
Accrued oil and natural gas capital costs	314,094	292,472
Revenues and royalties payable	128,598	124,222
Accrued interest expense	75,177	82,570
Accrued employee compensation	4,960	2,272
Accrued lease operating expense	24,980	21,469
Drilling advances from partners	16,314	24,882
Accounts payable to affiliated partnerships	939	679
Other	433	362
Total	$ 652,203	$ 636,589

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INCOME TAXES (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
INCOME TAXES
Period of cumulative book loss that limits ability to consider other subjective evidence for growth	3 years
Income tax expense or benefit		$ (3,294,000)
Pre-tax income (loss)	$ (73,000,000)	$ 8,800,000
Effective income tax rate (as a percent)	0.00%	37.60%

XML

LONG-TERM DEBT (Details 4) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014 February 2012 Warrants	Sep. 30, 2012 8.0% Convertible Note	Jun. 30, 2012 8.0% Convertible Note	Mar. 31, 2012 8.0% Convertible Note	Mar. 31, 2014 8.0% Convertible Note	Feb. 08, 2014 8.0% Convertible Note	Dec. 31, 2013 8.0% Convertible Note	Feb. 08, 2012 8.0% Convertible Note
Long-term debt
Principal amount					$ 289.7		$ 289.7	$ 275.0
Term	5 years
Interest rate (as a percent)					8.00%		8.00%	8.00%
Interest in kind		5.8	5.7	3.2
Principal outstanding					289.7
Amount of principal and accrued interest that is convertible into one share of the entity's common stock (in dollars per share)						$ 4.50
Unamortized discount					$ 28.3		$ 30.3	$ 43.6

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ADDITIONAL FINANCIAL STATEMENT INFORMATION (Tables)

3 Months Ended

Mar. 31, 2014

ADDITIONAL FINANCIAL STATEMENT INFORMATION

Schedule of additional financial statement information, balance sheet

	March 31, 2014		December 31, 2013
	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	169,640	$	129,355
Joint interest accounts		137,957		170,907
Affiliated partnership		302		500
Other		1,405		11,756
	$	309,304	$	312,518
Prepaids and other:
Prepaids	$	5,974	$	5,636
Income tax receivable		5,404		10,404
Other		58		58
	$	11,436	$	16,098
Accounts payable and accrued liabilities:
Trade payables	$	86,708	$	87,661
Accrued oil and natural gas capital costs		314,094		292,472
Revenues and royalties payable		128,598		124,222
Accrued interest expense		75,177		82,570
Accrued employee compensation		4,960		2,272
Accrued lease operating expenses		24,980		21,469
Drilling advances from partners		16,314		24,882
Accounts payable to affiliated partnership		939		679
Other		433		362
	$	652,203	$	636,589

XML

ASSET RETIREMENT OBLIGATIONS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Activity related to ARO liability
Liability for asset retirement obligations at the beginning of the period	$ 39,257
Liabilities settled and divested	(2,019)
Additions	1,104
Accretion expense	479
Revisions in estimated cash flows	154
Liability for asset retirement obligations at the end of the period	$ 38,975

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FAIR VALUE MEASUREMENTS (Details 2) (Recurring, USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Recurring
Reconciliation of changes in the fair value of the Company's oil derivative instruments classified as Level 3 in the fair value hierarchy
Beginning Balance	$ (2,816)
Net gain (loss) on derivative contracts	32	(2,816)
Ending Balance	(2,784)	(2,816)
Change in unrealized gains (losses) included in earnings related to derivatives still held at the end of the period	$ 32	$ (2,816)

XML

EARNINGS PER COMMON SHARE (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Basic:
Net income (loss) available to common stockholders	$ (77,923)	$ 5,465
Weighted average basic number of common shares outstanding	413,521,000	346,139,000
Basic net income (loss) per common share (in dollars per share)	$ (0.19)	$ 0.02
Diluted:
Net income (loss) available to common stockholders	$ (77,923)	$ 5,465
Weighted average basic number of common shares outstanding	413,521,000	346,139,000
Common stock equivalent shares representing shares issuable upon exercise of February 2012 Warrants		14,411,000
Common stock equivalent shares representing shares included upon vesting of restricted shares		1,255,000
Common stock equivalent shares representing shares issuable upon conversion of preferred stock		21,760,000
Weighted average diluted number of common shares outstanding	413,521,000	383,565,000
Diluted net income (loss) per common share (in dollars per share)	$ (0.19)	$ 0.01
Common stock equivalents of stock options, restricted shares, warrants and convertible debt and convertible preferred stock, not included in the computations of diluted earnings per share of common stock as their effect would have been anti-dilutive (in shares)	173,200,000	70,600,000

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OIL AND NATURAL GAS PROPERTIES

3 Months Ended

Mar. 31, 2014

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES

3. 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.

        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 capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that are excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts are recorded as additions to unevaluated oil and natural gas properties on the unaudited condensed consolidated balance sheets. As the costs excluded are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool. For the three months ended March 31, 2014 and 2013, the Company capitalized interest costs of $46.6 million and $52.2 million, respectively.

        At March 31, 2014, 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 March 31, 2014 of the West Texas Intermediate (WTI) spot price of $98.46 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 March 31, 2014 of the Henry Hub price of $3.99 per million British thermal units (MMBtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at March 31, 2014 exceeded the ceiling amount by $61.2 million ($39.0 million after taxes) which resulted in a ceiling test impairment of that amount for the quarter. The Company recorded the full cost ceiling test impairment in "Full cost ceiling impairment" in the Company's unaudited condensed consolidated statements of operations and in "Accumulated depletion" in the Company's unaudited condensed consolidated balance sheets. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine the Company's ceiling test calculations and impairment analyses in future periods.

        At March 31, 2013, the ceiling test value of the Company's reserves was calculated based on the first day average of the 12-months ended March 31, 2013 of the WTI spot price of $92.63 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended March 31, 2013 of the Henry Hub price of $2.95 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 March 31, 2013 did not exceed the ceiling amount.

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	3 Months Ended							0 Months Ended	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Gathering, transportation and sales North Dakota item	Mar. 31, 2014 Gathering, transportation and sales North Dakota Minimum	Mar. 31, 2014 Gathering, transportation and sales North Dakota Maximum	Mar. 31, 2014 Transportation East Texas item	Mar. 31, 2014 Gathering East Texas item	Feb. 28, 2014 Agreement Seller Tuscaloosa Marine Shale	Mar. 31, 2014 Agreement Seller Tuscaloosa Marine Shale	Dec. 20, 2013 Agreement Seller Tuscaloosa Marine Shale acre	Dec. 20, 2013 Agreement Seller Tuscaloosa Marine Shale Maximum
COMMITMENTS AND CONTINGENCIES
Rent expense	$ 1,900,000	$ 2,500,000
Non-cancelable termination penalties	42,300,000
Total Obligation Amount
Drilling rig commitments	79,700,000
Office and equipment lease agreements amount	66,600,000
Commitments and contingencies
Number of long-term crude oil sales contracts to which the entity is committed			9
Number of long-term natural gas sales contracts to which the entity is committed			2			1	1
Period of commitment for production from the date of first production				5 years	10 years	5 years	5 years
Amount to be funded											189,400,000
Net acres exchanged for funding by entity										117,870
Carry Amount paid	62,500,000							62,500,000
Percentage of working interest in the Carry Wells to be received									5.00%
Commitment capped through December 31, 2014									$ 120,000,000

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OIL AND NATURAL GAS PROPERTIES (Details) (USD $)	3 Months Ended	12 Months Ended		3 Months Ended
	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Unevaluated Oil and Gas Leaseholds	Mar. 31, 2013 Unevaluated Oil and Gas Leaseholds
Oil and Natural Gas Properties
Interest costs capitalized				$ 46,600,000	$ 52,200,000
Ceiling Limitation Disclosures
First day average of the West Texas Intermediate (WTI) spot price (in dollars per barrel)		98.46	92.63
First day average of the Henry Hub price (in dollars per Mmbtu)		3.99	2.95
Full cost ceiling impairment	61,165,000
Full cost ceiling impairment, after tax	$ 39,000,000

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ACQUISITIONS AND DIVESTITURES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended	0 Months Ended
	Sep. 30, 2013 Non-core Divestitures item	Sep. 30, 2013 Non-core Divestitures	Jul. 19, 2013 Eagle Ford Assets
Divestitures
Number of separate purchase and sale agreements	3
Total consideration from non-core properties	$ 302.0
Gain (loss) from sale of interests		0	0
Proceeds from sale of interests, before post-closing adjustments			$ 147.9

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STOCKHOLDERS' EQUITY (Details) (USD $)	3 Months Ended	12 Months Ended	1 Months Ended			0 Months Ended		0 Months Ended		3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Feb. 29, 2012 February 2012 Warrants	Aug. 30, 2012 GeoResources Warrants GeoResources	Aug. 30, 2012 August 2012 Warrants GeoResources	Aug. 13, 2013 Common Stock	Jan. 17, 2013 Common Stock	Mar. 03, 2014 5.75% Series A Convertible Perpetual Preferred Stock	Jun. 18, 2013 5.75% Series A Convertible Perpetual Preferred Stock	Mar. 31, 2014 5.75% Series A Convertible Perpetual Preferred Stock item
Preferred stock and stockholders' equity
Shares issued						43,700,000			345,000
Dividend rate (as a percent)	5.75%	5.75%								5.75%
Share price (in dollars per share)									$ 1,000
Net proceeds received									$ 335,500,000
Payment of cumulative, declared dividends								5,000,000
Number of shares issued as non-cash dividend								1,400,000
Cumulative, undeclared dividends										1,700,000
Number of shares of common stock to be issued upon conversion										162.4431
Benefit from conversion of stock (in dollars per share)										$ 6.16
Number of shares of common stock to be issued upon conversion at initial conversion rate										56,000,000
Closing sale price of common stock as minimum percentage of the conversion price to automatically convert preferred stock into common stock										150.00%
Minimum number of trading days within 30 consecutive trading days during which the closing sales price of common stock per share must exceed the conversion price for the preferred stocks to be redeemable										20
Number of consecutive trading day periods within which the closing sale price of common stock price per share must exceed the conversion price for at least 20 trading days for the preferred stocks to be redeemable										30 days
Liquidation preference per share (in dollars per share)										$ 1,000
Number of consecutive trading day periods ending on the third business day prior to settlement date										5 days
Number of shares of common stock to be issued upon conversion on fundamental change										292.3977
Threshold period of dividends in arrears and unpaid which will give holders of the Convertible Preferred Stock voting rights										18 months
Number of additional directors that can be appointed by holders of the Convertible Preferred Stock until arrearage is paid in full										2
Proceeds from the offering of common stock		222,870,000				215,200,000
Increase in shares of common stock authorized							333,300,000
Authorized shares of common stock, after amendment of certificate of incorporation	670,000,000	670,000,000					670,000,000
Number of shares of common stock that can be purchased from warrants			36,700,000		1
Exercise price (in dollars per share)			$ 4.50		$ 8.40
Proceeds from issuance of warrants			43,600,000
Payment for capital commitment			$ 600,000
Warrants outstanding				600,000	1,200,000
Cash Portion (in dollars per share)					$ 20
Cash exercise price per $1.00 received					$ 0.82

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LONG-TERM DEBT (Details) (USD $)											0 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Senior revolving credit facility	Mar. 31, 2014 9.25% Senior Notes	Dec. 31, 2013 9.25% Senior Notes	Aug. 13, 2013 9.25% Senior Notes	Mar. 31, 2014 8.875% Senior Notes	Dec. 31, 2013 8.875% Senior Notes	Jan. 14, 2013 8.875% Senior Notes	Nov. 06, 2012 8.875% Senior Notes	Dec. 19, 2013 9.75% Senior Notes	Mar. 31, 2014 9.75% Senior Notes	Dec. 31, 2013 9.75% Senior Notes	Jul. 16, 2012 9.75% Senior Notes	Mar. 31, 2014 8% convertible Note	Dec. 31, 2013 8% convertible Note	Feb. 08, 2012 8% convertible Note
Long-term debt
Long-term debt	$ 3,533,193,000	$ 3,183,823,000	$ 348,000,000	$ 400,000,000	$ 400,000,000		$ 1,371,791,000	$ 1,372,355,000				$ 1,152,029,000	$ 1,152,099,000		$ 261,373,000	$ 259,369,000
Interest rate (as a percent)				9.25%	9.25%	9.25%	8.875%	8.875%	8.875%	8.875%	9.75%	9.75%	9.75%	9.75%	8.00%	8.00%	8.00%
Deferred premiums on derivative contracts, current	1,400,000	1,400,000
Unamortized discount							5,000,000	5,100,000		5,700,000		8,600,000	8,900,000	10,200,000	28,300,000	30,300,000	43,600,000
Principal amount of debt issued											400,000,000
Unamortized premium related to debt issued							$ 26,800,000	$ 27,500,000	$ 30,000,000		$ 11,000,000	$ 10,600,000	$ 11,000,000

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LONG-TERM DEBT (Details 2) (Senior revolving credit facility, USD $)	0 Months Ended				0 Months Ended
	Oct. 31, 2013 item	Feb. 08, 2012 item	Mar. 31, 2014	Mar. 21, 2014	Mar. 21, 2014 Minimum	Feb. 08, 2012 Minimum	Oct. 31, 2013 Fiscal quarter ended December 31, 2013	Oct. 31, 2013 Fiscal quarter ended March 31, 2014	Oct. 31, 2013 Fiscal quarter ended June 30, 2014	Feb. 08, 2012 ABR-based	Feb. 08, 2012 ABR-based Minimum	Feb. 08, 2012 ABR-based Maximum	Feb. 08, 2012 Euro-dollar based	Feb. 08, 2012 Euro-dollar based Minimum	Feb. 08, 2012 Euro-dollar based Maximum
Long-term debt
Maximum borrowing capacity		$ 1,500,000,000
Current borrowing capacity				800,000,000
Number of fiscal quarters for EBITDA utilized for calculation of Interest Coverage Ratio	3
Number of interim unscheduled redeterminations of borrowing base to which the company and lender each have the right		1
Number of consecutive semi-annual redeterminations between which the company and the lenders each have the right to one interim unscheduled redetermination of borrowing base		2
Multiple applied to stated principal amount of any future notes or other long-term debt securities that the company may issue to calculate reduction in borrowing base		0.25
Credit facility term		5 years
Variable rate base										Base rate			LIBOR
Applicable margin (as a percent)											0.50%	1.50%		1.50%	2.50%
Working capital levels						1.0
Interest coverage ratio					2.0	2.0
Interest coverage ratio after December 31, 2014						2.5
Amount outstanding			348,000,000
Borrowing capacity available before indebtedness limitation in indentures			800,000,000
Letters of credit outstanding			1,200,000
Borrowing capacity available			450,800,000
Amount available under the indebtedness limitation			$ 332,000,000
EBITDA period utilized for calculation of Interest Coverage Ratio							3 months	6 months	9 months
EBITDA multiplier utilized for calculation of Interest Coverage Ratio							4	2	1.333

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ACQUISITIONS AND DIVESTITURES

3 Months Ended

Mar. 31, 2014

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES

2. ACQUISITIONS AND DIVESTITURES

Divestitures

Non-core Properties

        During the third quarter of 2013, the Company entered into three separate purchase and sale agreements with unrelated parties to divest parcels of non-core properties located in the United States for total consideration of approximately $302.0 million, all of which closed by December 31, 2013. The transactions and consideration are subject to customary closing conditions and adjustments, with an effective date of July 1, 2013. Proceeds from the sales were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

Eagle Ford Assets

        On July 19, 2013, the Company completed the sale of its interest in Eagle Ford assets located in Fayette and Gonzales Counties, Texas, previously acquired as part of the merger with GeoResources, Inc. (the Merger), to private buyers for proceeds of approximately $147.9 million, before post-closing adjustments. The transaction had an effective date of January 1, 2013. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded.

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LONG-TERM DEBT (Details 3) (USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended		0 Months Ended		3 Months Ended			0 Months Ended		3 Months Ended		3 Months Ended				0 Months Ended		3 Months Ended		0 Months Ended		3 Months Ended
	Aug. 13, 2013 9.25% Senior Notes	Mar. 31, 2014 9.25% Senior Notes item	Dec. 31, 2013 9.25% Senior Notes	Aug. 13, 2013 9.25% Senior Notes Maximum	Aug. 13, 2013 9.25% Senior Notes Minimum	Mar. 31, 2014 9.25% Senior Notes On or before August 15, 2016	Mar. 31, 2014 9.25% Senior Notes On or before August 15, 2016 Maximum	Mar. 31, 2014 9.25% Senior Notes On or before August 15, 2016 Minimum	Jan. 14, 2013 8.875% Senior Notes	Nov. 06, 2012 8.875% Senior Notes	Mar. 31, 2014 8.875% Senior Notes item	Dec. 31, 2013 8.875% Senior Notes	Mar. 31, 2014 8.875% Senior Notes On or before November 15, 2015	Mar. 31, 2014 8.875% Senior Notes On or before November 15, 2015 Maximum	Mar. 31, 2014 8.875% Senior Notes On or before November 15, 2015 Minimum	Mar. 31, 2014 8.875% Senior Notes On or before November 15, 2016	Dec. 19, 2013 9.75% Senior Notes	Jul. 16, 2012 9.75% Senior Notes	Mar. 31, 2014 9.75% Senior Notes item	Dec. 31, 2013 9.75% Senior Notes	Jun. 04, 2013 9.75% Senior Notes Maximum	Jun. 04, 2013 9.75% Senior Notes Minimum	Mar. 31, 2014 9.75% Senior Notes Minimum	Mar. 31, 2014 9.75% Senior Notes On or before July 15, 2015	Mar. 31, 2014 9.75% Senior Notes On or before July 15, 2015 Maximum	Mar. 31, 2014 9.75% Senior Notes On or before July 15, 2015 Minimum	Mar. 31, 2014 9.75% Senior Notes On or before July 15, 2016
Long-term debt
Principal amount	$ 400.0	$ 400.0	$ 400.0						$ 600.0	$ 750.0	$ 1,350.0	$ 1,350.0						$ 750.0	$ 1,150.0	$ 1,150.0
Interest rate (as a percent)	9.25%	9.25%	9.25%						8.875%	8.875%	8.875%	8.875%					9.75%	9.75%	9.75%	9.75%
Issue price as a percentage of par value									105.00%	99.247%							102.75%	98.646%
Net proceeds from issuance	392.1								619.5	725.6							406.1	723.1
Ownership percentage in subsidiaries		100.00%									100.00%								100.00%
Number of minor subsidiaries that do not have guaranteed notes		1									1								1
Period to keep registered offer open after the date notice of the exchange offer is mailed to holders					20 days																	20 days
Period to file shelf registration statement upon consummation of the exchange offer				365 days																	180 days
Number of tests to be met for incurring additional indebtedness		2									2								2
Number of trailing fiscal quarters over which the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense is to be maintained		4									4								4
Adjusted consolidated EBITDA (as defined in the indenture) to adjusted consolidated interest expense ratio		2.00									2.00												2.00
Amount over which additional indebtedness cannot exceed		750									750								750
Percentage of adjusted consolidated net tangible assets considered over which additional indebtedness cannot exceed		30.00%									30.00%								30.00%
Principal amount of debt issued																	400.0
Independent assets		0									0								0
Independent operations		0									0								0
Percentage of principal amount of debt instrument which the entity may redeem							35.00%							35.00%											35.00%
Redemption price of debt instrument, if redeemed with the proceeds of certain equity offerings (as a percent)						109.25%							108.875%											109.75%
Percentage of principal amount of debt instrument, which must remain outstanding after the entity has redeemed a portion of debt instrument with proceeds from certain equity offerings								65.00%							65.00%											65.00%
Redemption period for the entity to redeem debt instrument following the receipt of cash proceeds from certain equity offerings							180 days							180 days											180 days
Applicable margin (as a percent)						0.50%										0.50%											0.50%
Unamortized discount										5.7	5.0	5.1						10.2	8.6	8.9
Unamortized premium									$ 30.0		$ 26.8	$ 27.5					$ 11.0		$ 10.6	$ 11.0

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DERIVATIVE AND HEDGING ACTIVITIES (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative and hedging activities
Total net gain (loss) on derivative contracts	$ (33,656)	$ (18,422)
Derivatives not designated as hedging contracts | Commodity contracts | Other Income Expense
Derivative and hedging activities
Unrealized gain (loss)	(26,916)	(16,799)
Realized gain (loss)	(6,740)	(1,623)
Total net gain (loss) on derivative contracts	$ (33,656)	$ (18,422)

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Oil, natural gas and natural gas liquids sales:
Oil	$ 256,029	$ 180,827
Natural gas	9,409	5,669
Natural gas liquids	8,759	3,828
Total oil, natural gas and natural gas liquids sales	274,197	190,324
Other	952	530
Total operating revenues	275,149	190,854
Production:
Lease operating	36,638	25,304
Workover and other	2,789	1,624
Taxes other than income	24,160	17,436
Gathering and other	5,073	333
Restructuring	987	671
General and administrative	32,798	31,597
Depletion, depreciation and accretion	119,908	81,858
Full cost ceiling impairment	61,165
Total operating expenses	283,518	158,823
Income (loss) from operations	(8,369)	32,031
Other income (expenses):
Net gain (loss) on derivative contracts	(33,656)	(18,422)
Interest expense and other, net	(30,939)	(4,850)
Total other income (expenses)	(64,595)	(23,272)
Income (loss) before income taxes	(72,964)	8,759
Income tax benefit (provision)		(3,294)
Net income (loss)	(72,964)	5,465
Series A preferred dividends	(4,959)
Net income (loss) available to common stockholders	$ (77,923)	$ 5,465
Net income (loss) per share of common stock:
Basic (in dollars per share)	$ (0.19)	$ 0.02
Diluted (in dollars per share)	$ (0.19)	$ 0.01
Weighted average common shares outstanding:
Basic (in shares)	413,521	346,139
Diluted (in shares)	413,521	383,565

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STOCKHOLDERS' EQUITY (Details 2) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended						3 Months Ended						3 Months Ended
	Mar. 31, 2014 General and administrative	Mar. 31, 2013 General and administrative	Mar. 31, 2014 Performance share units (PSU)	Mar. 31, 2014 Performance share units (PSU) Common Stock	Mar. 31, 2014 Performance share units (PSU) Common Stock $4.00	Mar. 31, 2014 Performance share units (PSU) Common Stock $7.00	Mar. 31, 2014 Performance share units (PSU) Common Stock $10.00	Mar. 31, 2014 Performance share units (PSU) Common Stock $5.50	Mar. 31, 2014 Performance share units (PSU) Common Stock $8.50	Mar. 31, 2014 Performance share units (PSU) Common Stock Senior management	Mar. 31, 2014 Performance share units (PSU) Low end of range Common Stock $4.00	Mar. 31, 2014 Performance share units (PSU) High end of range Common Stock	Mar. 31, 2014 Stock options	Mar. 31, 2013 Stock options	Mar. 31, 2014 Stock options Low end of range	Mar. 31, 2013 Stock options Low end of range	Mar. 31, 2014 Stock options High end of range	Mar. 31, 2013 Stock options High end of range	Mar. 31, 2014 Restricted Stock	Mar. 31, 2013 Restricted Stock	Mar. 31, 2013 Restricted Stock Directors and employees	Mar. 31, 2014 Restricted Stock Employee	Mar. 31, 2014 Restricted Stock Non-employee director	Mar. 31, 2014 Restricted Stock Low end of range	Mar. 31, 2013 Restricted Stock Low end of range	Mar. 31, 2014 Restricted Stock High end of range	Mar. 31, 2013 Restricted Stock High end of range	Mar. 31, 2014 2006 Long-Term Incentive Plan Common Stock	Dec. 31, 2013 2006 Long-Term Incentive Plan Common Stock	May 23, 2013 2006 Long-Term Incentive Plan Common Stock	May 17, 2012 2006 Long-Term Incentive Plan Common Stock
Stock-based compensation
Shares issuable under the plan																														41,500,000	11,500,000
Maximum number of shares that remained reserved for issuance under the Plan												3,200,000																13,200,000	25,700,000
Compensation expense recorded	$ 4.3	$ 2.3
Granted (in shares)																					2,800,000
Exercise price (in dollars per share)															$ 3.67	$ 6.36	$ 4.33	$ 8.23
Weighted average exercise price (in dollars per share)													$ 3.67	$ 7.20
Vesting period													3 years	3 years					3 years	3 years		3 years	6 months
Percentage of awards vesting on the annual anniversary date of the grant													33.33%	33.33%					33.33%	33.33%		33.33%
Expiration term													10 years	10 years
Unrecognized compensation expense													20.4	14.4					19.7	20.1
Weighted average remaining vesting period			2 years 10 months 24 days										1 year 7 months 6 days						1 year 8 months 12 days	1 year 9 months 18 days
Grant date price (in dollars per share)																								$ 3.67	$ 6.36	$ 4.33	$ 7.26
Weighted average grant date price (in dollars per share)																			$ 3.67	$ 7.10
Performance Share Units
Granted (in shares)										1,600,000
Number of trading days considered to measure the average of adjusted closing price of common stock				60 days
Average market price (in dollars per share)						$ 7.00	$ 10.00	$ 5.50	$ 8.50		$ 4.00
Entitlement percentage of shares underlining awards, to be received and vested					50.00%		200.00%	75.00%	150.00%
Unrecognized compensation expense			$ 4.8
Treasury Stock
Restricted stock granted to directors and employees under the Plan																					2,800,000
Shares issued out of treasury stock																					1,200,000
Shares retired																					400,000
Treasury stock, shares																					0

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (72,964)	$ 5,465	$ (1,222,662)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	119,908	81,858
Full cost ceiling impairment	61,165
Deferred income tax provision (benefit)		(999)
Share-based compensation, net	4,332	2,335
Unrealized loss (gain) on derivative contracts	26,021	16,071
Amortization and write-off of deferred loan costs	842	265
Non-cash interest and amortization of discount and premium	554	866
Other income (expense)	354	(1,013)
Change in assets and liabilities, net of acquisitions:
Accounts receivable	12,062	(50,746)
Inventory	280	(1,033)
Prepaids and other	4,662	3,924
Accounts payable and accrued liabilities	2,284	(11,283)
Net cash provided by (used in) operating activities	159,500	45,710
Cash flows from investing activities:
Oil and natural gas capital expenditures	(432,783)	(380,117)
Acquisition of Williston Basin Assets		(29,895)
Other operating property and equipment capital expenditures	(16,036)	(36,340)
Advance on carried interest	(62,500)
Funds held in escrow and other	1,821	1,328
Net cash provided by (used in) investing activities	(509,498)	(445,024)
Cash flows from financing activities:
Proceeds from borrowings	614,000	844,000
Repayments of borrowings	(266,000)	(434,476)
Debt issuance costs	(126)	(11,483)
Offering costs and other	(344)	(431)
Net cash provided by (used in) financing activities	347,530	397,610
Net increase (decrease) in cash	(2,468)	(1,704)
Cash at beginning of period	2,834	2,506	2,506
Cash at end of period	366	802	2,834
Disclosure of non-cash investing and financing activities:
Accrued capitalized interest	(4,763)	9,569
Asset retirement obligations	(730)	1,512
Series A preferred dividends paid in common stock	$ 4,959

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LONG-TERM DEBT (Details 6) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Debt Issuance Costs
Costs associated with the issuance of debt capitalized	$ 126	$ 11,483
Debt issuance costs, net of amortization	$ 62,350		$ 64,308

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DERIVATIVE AND HEDGING ACTIVITIES (Tables)

3 Months Ended

Mar. 31, 2014

DERIVATIVE AND HEDGING ACTIVITIES

Summary of location and fair value of derivative contracts

		Asset derivative contracts					Liability derivative contracts
Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	March 31, 2014		December 31, 2013		Balance sheet location	March 31, 2014			December 31, 2013
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	1,214	$	2,028	Current liabilities—liabilities from derivative contracts	$	(32,890	)	$	(17,859	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		14,243		22,734	Other noncurrent liabilities—liabilities from derivative contracts		(21,018	)		(19,333	)
Total derivatives not designated as hedging contracts under ASC 815		$	15,457	$	24,762		$	(53,908	)	$	(37,192	)

Summary of the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts

		Amount of gain or (loss) recognized in income on derivative contracts for the Three Months Ended March 31,
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2014			2013
		(In thousands)
Commodity contracts:
Unrealized gain (loss) oncommodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(26,916	)	$	(16,799	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		(6,740	)		(1,623	)
Total net gain (loss) on derivative contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(33,656	)	$	(18,422	)

Schedule of open derivative contracts

			March 31, 2014
					Floors				Ceilings				Put Options Sold
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
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500	$	95.00	$	95.00	$	98.20 - 101.00	$	99.13	$	70.00	$	70.00
April 2014 - June 2014	Collars	Crude Oil		364,000		90.00		90.00		96.50 - 99.50		98.00
April 2014 - December 2014	Collars	Crude Oil		5,706,250		85.00 - 95.00		88.67		93.60 - 108.45		96.27
April 2014 - December 2014	Collars	Natural Gas		8,937,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015(1)	Collars	Crude Oil		5,475,000		82.50 - 90.00		86.00		90.00 - 100.25		94.34
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015(2)	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
July 2015 - December 2015	Collars	Crude Oil		644,000		85.00		85.00		90.00 - 90.50		90.16
January 2016 - December 2016	Collars	Natural Gas		732,000		4.00		4.00		4.22		4.22
January 2016 - December 2016(3)	Swaps	Crude Oil		2,196,000		88.00 - 88.87		88.30

⁽¹⁾

Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 732,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 366,000 Bbls for the year ended December 31, 2016.

⁽²⁾

Includes an outstanding crude oil swap of which may be extended at a price of $91.25 per Bbl for 732,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 366,000 Bbls for the year ended December 31, 2016.

⁽³⁾

Includes an outstanding crude oil swap which may be extended at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

			December 31, 2013
					Floors				Ceilings				Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
January 2014 - March 2014	Three-Way Collars	Crude Oil		144,000	$	95.00	$	95.00	$	98.60 - 109.50	$	100.03	$	70.00	$	70.00
January 2014 - June 2014	Collars	Crude Oil		724,000		90.00		90.00		96.50 - 99.50		98.00
January 2014 - December 2014	Collars	Crude Oil		7,573,750		85.00 - 95.00		88.67		93.60 - 108.45		96.22
January 2014 - December 2014	Collars	Natural Gas		11,862,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500		95.00		95.00		98.20 - 101.00		99.13		70.00		70.00
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015(1)	Collars	Crude Oil		5,110,000		82.50 - 90.00		86.07		90.00 - 100.25		94.65
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015(2)	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
January 2016 - December 2016(3)	Swaps	Crude Oil		2,190,000		88.00 - 88.87		88.30

⁽¹⁾

Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2016.

⁽²⁾

Includes an outstanding crude oil swap which may be extended at a price of $91.25 per Bbl for 730,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 365,000 Bbls for the year ended December 31, 2016.

⁽³⁾

Includes an outstanding crude oil swap which may be extended at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

Schedule of potential effects of master netting arrangements on the fair value of derivative contracts

	Derivative Assets						Derivative Liabilities
Offsetting of Derivative Assets and Liabilities	March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
	(In thousands)						(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	15,457		$	24,762		$	(53,908	)	$	(37,192	)
Amounts Not Offset in the Consolidated Balance Sheet		(14,625	)		(20,036	)		14,235			19,507
Net Amount	$	832		$	4,726		$	(39,673	)	$	(17,685	)

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FAIR VALUE MEASUREMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Recurring Level 2	Dec. 31, 2013 Recurring Level 2	Mar. 31, 2014 Recurring Level 3	Dec. 31, 2013 Recurring Level 3	Mar. 31, 2014 Recurring Total	Dec. 31, 2013 Recurring Total
FAIR VALUE MEASUREMENTS
Asset transfers between levels	$ 0
Liability transfers between levels	0
Assets
Receivables from derivative contracts		15,457	24,762			15,457	24,762
Liabilities
Liabilities from derivative contracts		$ 51,124	$ 34,376	$ 2,784	$ 2,816	$ 53,908	$ 37,192

XML

EARNINGS PER COMMON SHARE (Tables)

3 Months Ended

Mar. 31, 2014

EARNINGS PER COMMON SHARE

Schedule of calculation of earnings (loss) per share

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

	Three Months Ended March 31,
	2014			2013
	(In thousands, except per share amounts)
Basic:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465
Weighted average basic number of common shares outstanding		413,521			346,139
Basic net income (loss) per share of common stock	$	(0.19	)	$	0.02
Diluted:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465
Weighted average basic number of common shares outstanding		413,521			346,139
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			14,411
Exercise of August 2012 Warrants		—			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			1,255
Vesting of performance share units		—			—
Conversion of 2017 Notes		Anti-dilutive			Anti-dilutive
Conversion of preferred stock		—			21,760
Conversion of Series A Preferred Stock		Anti-dilutive			—
Weighted average diluted number of common shares outstanding		413,521			383,565
Diluted net income (loss) per share of common stock	$	(0.19	)	$	0.01

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FINANCIAL STATEMENT PRESENTATION

3 Months Ended

Mar. 31, 2014

FINANCIAL STATEMENT PRESENTATION

FINANCIAL STATEMENT PRESENTATION

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 assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries and an equity method investment. 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 2013 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC). Please refer to the notes in the 2013 Annual Report on Form 10-K when reviewing interim financial results.

        During the year ended 2013, the Company determined that "Net cash provided by operating activities" and "Net cash used in investing activities" for the three month period ended March 31, 2013 were both overstated by $9.6 million as a result of the inclusion of capitalized non-cash interest in the change in "Accounts payable and accrued liabilities" line item in operating cash flows and "Oil and natural gas capital expenditures" and "Other operating property and equipment capital expenditures" in investing cash flows. The Company has corrected the error, which had no impact to the net cash flows for the period, and provided related supplemental non-cash information in the accompanying unaudited condensed consolidated statements of cash flows for the three month period ended March 31, 2013.

Use of Estimates

        The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived 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 allowances for doubtful accounts as of March 31, 2014 or December 31, 2013.

Other Operating Property and Equipment

        Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year estimated useful life. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company capitalized $101.2 million and $92.0 million as of March 31, 2014 and December 31, 2013, respectively, related to the construction of its gas gathering systems.

        Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years; trailers, seven years; heavy equipment, ten years; an airplane and 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.

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

Recently Issued Accounting Pronouncements

        In February 2013, the FASB issued ASU No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU 2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements, such as debt arrangements, other contractual obligations and settled litigation and judicial rulings. This pronouncement must be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of ASU 2013-04 did not have an impact to the Company's operating results, financial position and disclosures.

        In February 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU 2013-11). ASU 2013-11 provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This pronouncement should be applied prospectively to all unrecognized tax benefits that exist at the effective date and retrospective application is permitted. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this pronouncement did not have an impact to the Company's operating results and financial position.

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current assets:
Cash	$ 366	$ 2,834
Accounts receivable	309,304	312,518
Receivables from derivative contracts	1,214	2,028
Inventory	4,868	5,148
Prepaids and other	11,436	16,098
Total current assets	327,188	338,626
Oil and natural gas properties (full cost method):
Evaluated	5,382,235	4,960,467
Unevaluated	2,110,612	2,028,044
Gross oil and natural gas properties	7,492,847	6,988,511
Less - accumulated depletion	(2,367,926)	(2,189,515)
Net oil and natural gas properties	5,124,921	4,798,996
Other operating property and equipment:
Gas gathering and other operating assets	137,849	125,837
Less - accumulated depreciation	(10,441)	(8,461)
Net other operating property and equipment	127,408	117,376
Other noncurrent assets:
Receivables from derivative contracts	14,243	22,734
Debt issuance costs, net	62,350	64,308
Deferred income taxes	4,505	8,474
Equity in oil and natural gas partnership	5,294	4,463
Funds in escrow and other	10,225	1,514
Total assets	5,676,134	5,356,491
Current liabilities:
Accounts payable and accrued liabilities	652,203	636,589
Liabilities from derivative contracts	32,890	17,859
Asset retirement obligations	141	71
Current portion of deferred income taxes	4,505	8,474
Current portion of long-term debt	1,389	1,389
Total current liabilities	691,128	664,382
Long -term debt	3,533,193	3,183,823
Other noncurrent liabilities:
Liabilities from derivative contracts	21,018	19,333
Asset retirement obligations	38,834	39,186
Other	11,157	2,157
Commitments and contingencies (Note 8)
Stockholders' equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 345,000 and none shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding as of March 31, 2014 and December 31, 2013, respectively
Common stock: 670,000,000 shares of $0.0001 par value authorized; 420,521,463 and 415,729,962 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively	41	41
Additional paid-in capital	2,964,903	2,953,786
Accumulated deficit	(1,584,140)	(1,506,217)
Total stockholders' equity	1,380,804	1,447,610
Total liabilities and stockholders' equity	$ 5,676,134	$ 5,356,491

XML

EARNINGS PER COMMON SHARE

3 Months Ended

Mar. 31, 2014

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE

11. EARNINGS PER COMMON SHARE

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

	Three Months Ended March 31,
	2014			2013
	(In thousands, except per share amounts)
Basic:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465
Weighted average basic number of common shares outstanding		413,521			346,139
Basic net income (loss) per share of common stock	$	(0.19	)	$	0.02
Diluted:
Net income (loss) available to common stockholders	$	(77,923	)	$	5,465
Weighted average basic number of common shares outstanding		413,521			346,139
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive			Anti-dilutive
Exercise of February 2012 Warrants		Anti-dilutive			14,411
Exercise of August 2012 Warrants		—			Anti-dilutive
Vesting of restricted shares		Anti-dilutive			1,255
Vesting of performance share units		—			—
Conversion of 2017 Notes		Anti-dilutive			Anti-dilutive
Conversion of preferred stock		—			21,760
Conversion of Series A Preferred Stock		Anti-dilutive			—
Weighted average diluted number of common shares outstanding		413,521			383,565
Diluted net income (loss) per share of common stock	$	(0.19	)	$	0.01

        Common stock equivalents, including stock options, warrants, restricted shares, convertible debt, and preferred stock, totaling 173.2 million shares for the three months ended March 31, 2014 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. Common stock equivalents, including stock options, warrants, and convertible debt, totaling 70.6 million shares were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive for the three months ended March 31, 2013.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2014	May 05, 2014
Document and Entity Information
Entity Registrant Name	HALCON RESOURCES CORP
Entity Central Index Key	0001282648
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		420,476,893
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1

XML

ADDITIONAL FINANCIAL STATEMENT INFORMATION

3 Months Ended

Mar. 31, 2014

ADDITIONAL FINANCIAL STATEMENT INFORMATION

ADDITIONAL FINANCIAL STATEMENT INFORMATION

12. ADDITIONAL FINANCIAL STATEMENT INFORMATION

        Certain balance sheet amounts are comprised of the following:

	March 31, 2014		December 31, 2013
	(In thousands)
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$	169,640	$	129,355
Joint interest accounts		137,957		170,907
Affiliated partnership		302		500
Other		1,405		11,756
	$	309,304	$	312,518
Prepaids and other:
Prepaids	$	5,974	$	5,636
Income tax receivable		5,404		10,404
Other		58		58
	$	11,436	$	16,098
Accounts payable and accrued liabilities:
Trade payables	$	86,708	$	87,661
Accrued oil and natural gas capital costs		314,094		292,472
Revenues and royalties payable		128,598		124,222
Accrued interest expense		75,177		82,570
Accrued employee compensation		4,960		2,272
Accrued lease operating expenses		24,980		21,469
Drilling advances from partners		16,314		24,882
Accounts payable to affiliated partnership		939		679
Other		433		362
	$	652,203	$	636,589

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Stockholders' equity:
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Preferred stock, shares issued	345,000	345,000
Preferred stock, shares outstanding	345,000	345,000
Preferred stock, dividend rate of Cumulative Perpetual Convertible Series A (as a percent)	5.75%	5.75%
Common stock, shares authorized	670,000,000	670,000,000
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares issued	420,521,463	415,729,962
Common stock, shares outstanding	420,521,463	415,729,962

XML

DERIVATIVE AND HEDGING ACTIVITIES

3 Months Ended

Mar. 31, 2014

DERIVATIVE AND HEDGING ACTIVITIES

DERIVATIVE AND HEDGING ACTIVITIES

6. DERIVATIVE AND HEDGING ACTIVITIES

        The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to economically hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company 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. Historically, the Company has also entered into interest rate swaps to mitigate exposure to market rate fluctuations. The Company does not enter into derivative contracts for speculative trading purposes.

        It is the Company's policy to enter into derivative contracts, including interest rate derivatives, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in its Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Company's Senior Credit Agreement.

        At March 31, 2014 and December 31, 2013, the Company's crude oil and natural gas derivative positions consisted of swaps, swaptions, costless put/call "collars," extendable costless collars and put options. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. Extendable collars are costless put/call contracts that may be extended annually at the option of the counterparty on a designated date. A sold put option limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. The Company has elected to not 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 all payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the unaudited condensed consolidated statements of operations.

        At March 31, 2014, the Company had 90 open commodity derivative contracts summarized in the following tables: 11 natural gas collar arrangements, 58 crude oil collar arrangements, two crude oil three-way collars, one crude oil put option, and eight crude oil swaps, eight crude oil swaptions and two crude oil extendable collars.

        At December 31, 2013, the Company had 86 open commodity derivative contracts summarized in the following tables: 10 natural gas collar arrangements, 52 crude oil collar arrangements, five crude oil three-way collars, one crude oil put option, eight crude oil swaps, eight crude oil swaptions and two crude oil extendable collars.

        All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013:

		Asset derivative contracts					Liability derivative contracts
Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	March 31, 2014		December 31, 2013		Balance sheet location	March 31, 2014			December 31, 2013
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	1,214	$	2,028	Current liabilities—liabilities from derivative contracts	$	(32,890	)	$	(17,859	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		14,243		22,734	Other noncurrent liabilities—liabilities from derivative contracts		(21,018	)		(19,333	)
Total derivatives not designated as hedging contracts under ASC 815		$	15,457	$	24,762		$	(53,908	)	$	(37,192	)

        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:

		Amount of gain or (loss) recognized in income on derivative contracts for the Three Months Ended March 31,
	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2014			2013
		(In thousands)
Commodity contracts:
Unrealized gain (loss) oncommodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(26,916	)	$	(16,799	)
Realized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		(6,740	)		(1,623	)
Total net gain (loss) on derivative contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	(33,656	)	$	(18,422	)

        At March 31, 2014 and December 31, 2013, the Company had the following open crude oil and natural gas derivative contracts:

			March 31, 2014
					Floors				Ceilings				Put Options Sold
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
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500	$	95.00	$	95.00	$	98.20 - 101.00	$	99.13	$	70.00	$	70.00
April 2014 - June 2014	Collars	Crude Oil		364,000		90.00		90.00		96.50 - 99.50		98.00
April 2014 - December 2014	Collars	Crude Oil		5,706,250		85.00 - 95.00		88.67		93.60 - 108.45		96.27
April 2014 - December 2014	Collars	Natural Gas		8,937,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015(1)	Collars	Crude Oil		5,475,000		82.50 - 90.00		86.00		90.00 - 100.25		94.34
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015(2)	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
July 2015 - December 2015	Collars	Crude Oil		644,000		85.00		85.00		90.00 - 90.50		90.16
January 2016 - December 2016	Collars	Natural Gas		732,000		4.00		4.00		4.22		4.22
January 2016 - December 2016(3)	Swaps	Crude Oil		2,196,000		88.00 - 88.87		88.30

⁽¹⁾

Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 732,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 366,000 Bbls for the year ended December 31, 2016.

⁽²⁾

Includes an outstanding crude oil swap of which may be extended at a price of $91.25 per Bbl for 732,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 366,000 Bbls for the year ended December 31, 2016.

⁽³⁾

Includes an outstanding crude oil swap which may be extended at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

			December 31, 2013
					Floors				Ceilings				Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price		Price / Price Range		Weighted Average Price
January 2014 - March 2014	Three-Way Collars	Crude Oil		144,000	$	95.00	$	95.00	$	98.60 - 109.50	$	100.03	$	70.00	$	70.00
January 2014 - June 2014	Collars	Crude Oil		724,000		90.00		90.00		96.50 - 99.50		98.00
January 2014 - December 2014	Collars	Crude Oil		7,573,750		85.00 - 95.00		88.67		93.60 - 108.45		96.22
January 2014 - December 2014	Collars	Natural Gas		11,862,500		3.75 - 4.00		3.85		4.26 - 4.55		4.35
April 2014 - June 2014	Three-Way Collars	Crude Oil		136,500		95.00		95.00		98.20 - 101.00		99.13		70.00		70.00
July 2014 - December 2014	Collars	Crude Oil		920,000		87.50 - 90.00		89.50		92.50 - 100.25		97.87
July 2014 - December 2014	Collars	Natural Gas		920,000		4.00		4.00		4.42		4.42
July 2014 - December 2014	Put	Crude Oil		184,000										90.00		90.00
January 2015 - June 2015	Collars	Crude Oil		1,583,750		85.00 - 90.00		86.29		91.00 - 98.50		93.14
January 2015 - December 2015(1)	Collars	Crude Oil		5,110,000		82.50 - 90.00		86.07		90.00 - 100.25		94.65
January 2015 - December 2015	Collars	Natural Gas		6,387,500		4.00		4.00		4.55 - 4.85		4.68
January 2015 - December 2015(2)	Swaps	Crude Oil		1,095,000		91.00 - 91.25		91.17
January 2016 - December 2016(3)	Swaps	Crude Oil		2,190,000		88.00 - 88.87		88.30

⁽¹⁾

Includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.20 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2016. Also includes an outstanding crude oil collar which may be extended at a floor of $85.00 per Bbl and a ceiling of $96.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2016.

⁽²⁾

Includes an outstanding crude oil swap which may be extended at a price of $91.25 per Bbl for 730,000 Bbls for the year ended December 31, 2016. Also includes certain outstanding crude oil swaps which may be extended at a price of $91.00 per Bbl totaling 365,000 Bbls for the year ended December 31, 2016.

⁽³⁾

Includes an outstanding crude oil swap which may be extended at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

        The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at March 31, 2014 and December 31, 2013 in accordance with ASU 2011-11 and ASU 2013-01:

	Derivative Assets						Derivative Liabilities
Offsetting of Derivative Assets and Liabilities	March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
	(In thousands)						(In thousands)
Gross Amounts Presented in the Consolidated Balance Sheet	$	15,457		$	24,762		$	(53,908	)	$	(37,192	)
Amounts Not Offset in the Consolidated Balance Sheet		(14,625	)		(20,036	)		14,235			19,507
Net Amount	$	832		$	4,726		$	(39,673	)	$	(17,685	)

        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.

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2014

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

5. FAIR VALUE MEASUREMENTS

        Pursuant to 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.

        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 March 31, 2014 and December 31, 2013. 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 the three months ended March 31, 2014.

	March 31, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	15,457	$	—	$	15,457
Liabilities
Liabilities from derivative contracts	$	—	$	51,124	$	2,784	$	53,908

	December 31, 2013
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	24,762	$	—	$	24,762
Liabilities
Liabilities from derivative contracts	$	—	$	34,376	$	2,816	$	37,192

        Derivative contracts listed above as Level 2 include collars, swaps and put options that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" in the Company's unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 6, "Derivative and Hedging Activities" for additional discussion of derivatives.

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

	Significant Unobservable Inputs (Level 3)
	March 31, 2014			December 31, 2013
Beginning Balance	$	(2,816	)	$	—
Net gain (loss) on derivative contracts		32			(2,816	)
Settlements		—			—
Purchase of derivative contracts		—			—
Buy out of derivative contracts		—			—
Ending Balance	$	(2,784	)	$	(2,816	)
Change in unrealized gains (losses) included in earnings related to derivatives still held at March 31, 2014 and December 31, 2013	$	32		$	(2,816	)

        As of March 31, 2014 and December 31, 2013, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a 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. Each of the counterparties to the Company's current derivative contracts is a lender or an affiliate of a lender in the Company's Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

        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 receivable and accounts payable approximates 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, long-term debt instruments as of March 31, 2014 and December 31, 2013 (excluding discounts, premiums and deferred premiums on derivative contracts):

	March 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
9.25% $400 million senior notes	$	400,000	$	416,924	$	400,000	$	407,432
8.875% $1.35 billion senior notes		1,350,000		1,401,975		1,350,000		1,390,500
9.75% $1.15 billion senior notes		1,150,000		1,242,000		1,150,000		1,197,438
8.0% $289.7 million convertible note		289,669		393,423		289,669		368,418
	$	3,189,669	$	3,454,322	$	3,189,669	$	3,363,788

        The fair value of the Company's fixed interest debt instruments was calculated using Level 2 criteria at March 31, 2014 and December 31, 2013. The fair value of the Company's senior notes is based on quoted market prices from trades of such debt. The fair value of the Company's convertible note is based on published market prices and risk-free rates.

        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; and therefore, the Company has designated these liabilities as Level 3. See Note 7, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.

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ASSET RETIREMENT OBLIGATIONS (Tables)

3 Months Ended

Mar. 31, 2014

ASSET RETIREMENT OBLIGATIONS

Schedule of activity related to ARO liability

The Company recorded the following activity related to its ARO liability for the three months ended March 31, 2014 (in thousands, inclusive of the current portion):

Liability for asset retirement obligations as of December 31, 2013	$	39,257
Liabilities settled and divested		(2,019	)
Additions		1,104
Accretion expense		479
Revisions in estimated cash flows		154
Liability for asset retirement obligations as of March 31, 2014	$	38,975

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FINANCIAL STATEMENT PRESENTATION (Policies)

3 Months Ended

Mar. 31, 2014

FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

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 assets in the United States. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries and an equity method investment. 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 2013 Annual Report on Form 10-K, as filed with the United States Securities and Exchange Commission (SEC). Please refer to the notes in the 2013 Annual Report on Form 10-K when reviewing interim financial results.

        During the year ended 2013, the Company determined that "Net cash provided by operating activities" and "Net cash used in investing activities" for the three month period ended March 31, 2013 were both overstated by $9.6 million as a result of the inclusion of capitalized non-cash interest in the change in "Accounts payable and accrued liabilities" line item in operating cash flows and "Oil and natural gas capital expenditures" and "Other operating property and equipment capital expenditures" in investing cash flows. The Company has corrected the error, which had no impact to the net cash flows for the period, and provided related supplemental non-cash information in the accompanying unaudited condensed consolidated statements of cash flows for the three month period ended March 31, 2013.

Use of Estimates

Use of Estimates

        The preparation of the Company's unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived 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

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 allowances for doubtful accounts as of March 31, 2014 or December 31, 2013.

Other Operating Property and Equipment

Other Operating Property and Equipment

        Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year estimated useful life. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company capitalized $101.2 million and $92.0 million as of March 31, 2014 and December 31, 2013, respectively, related to the construction of its gas gathering systems.

        Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years; trailers, seven years; heavy equipment, ten years; an airplane and 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.

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

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

        In February 2013, the FASB issued ASU No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for which the Total Amount of the Obligation is Fixed at the Reporting Date (ASU 2013-04). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements, such as debt arrangements, other contractual obligations and settled litigation and judicial rulings. This pronouncement must be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of ASU 2013-04 did not have an impact to the Company's operating results, financial position and disclosures.

        In February 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU 2013-11). ASU 2013-11 provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This pronouncement should be applied prospectively to all unrecognized tax benefits that exist at the effective date and retrospective application is permitted. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this pronouncement did not have an impact to the Company's operating results and financial position.

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STOCKHOLDERS' EQUITY

3 Months Ended

Mar. 31, 2014

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

9. STOCKHOLDERS' EQUITY

5.75% Series A Convertible Perpetual Preferred Stock

        On June 18, 2013, the Company completed its offering of 345,000 shares of its 5.75% Series A Convertible Perpetual Preferred Stock (the Series A Preferred Stock) at a public offering price of $1,000 per share (the Liquidation Preference). The net proceeds to the Company from the offering of the Series A Preferred Stock were approximately $335.5 million, after deducting the underwriting discount and offering expenses. The Company used the net proceeds from the offering to repay a portion of the outstanding borrowings under its Senior Credit Agreement.

        Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Company's Board of Directors, cumulative dividends at the rate of 5.75% per annum (the dividend rate) on the Liquidation Preference per share of the Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, in common stock of the Company or a combination thereof, and are payable on March 1, June 1, September 1 and December 1 of each year. On March 3, 2014, the Company paid cumulative, declared dividends of $5.0 million by issuing approximately 1.4 million shares of common stock reflected as a non-cash dividend. As of March 31, 2014, cumulative, undeclared dividends on the Series A Preferred Stock amounted to approximately $1.7 million.

        The Series A Preferred Stock has no maturity date, is not redeemable by the Company at any time, and will remain outstanding unless converted by the holders or mandatorily converted by the Company as described below.

        Each share of Series A Preferred Stock is convertible, at the holder's option at any time, initially into approximately 162.4431 shares of common stock of the Company (which is equivalent to an initial conversion price of approximately $6.16 per share), subject to specified adjustments as set forth in the Series A Designation. Based on the initial conversion rate, approximately 56.0 million shares of common stock of the Company would be issuable upon conversion of all the shares of Series A Preferred Stock.

        On or after June 6, 2018, the Company may, at its option, give notice of its election to cause all outstanding shares of the Series A Preferred Stock to be automatically converted into shares of common stock of the Company at the conversion rate (as defined in the Series A Designation), if the closing sale price of the Company's common stock equals or exceeds 150% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days.

        If the Company undergoes a fundamental change (as defined in the Series A Designation) and a holder converts its shares of the Series A Preferred Stock at any time beginning at the opening of business on the trading day immediately following the effective date of such fundamental change and ending at the close of business on the 30th trading day immediately following such effective date, the holder will receive, for each share of the Series A Preferred Stock surrendered for conversion, a number of shares of common stock of the Company equal to the greater of: (1) the sum of (i) the conversion rate and (ii) the make-whole premium, if any, as described in the Series A Designation; and (2) the conversion rate which will be increased to equal (i) the sum of the $1,000 liquidation preference plus all accumulated and unpaid dividends to, but excluding, the settlement date for such conversion, divided by (ii) the average of the closing sale prices of the Company's common stock for the five consecutive trading days ending on the third business day prior to such settlement date; provided that the prevailing conversion rate as adjusted pursuant to this will not exceed 292.3977 shares of common stock of the Company per share of the Series A Preferred Stock (subject to adjustment in the same manner as the conversion rate).

        Except as required by Delaware law, holders of the Series A Preferred Stock will have no voting rights unless dividends are in arrears and unpaid for six or more quarterly periods. Until such arrearage is paid in full, the holders (voting as a single class with the holders of any other preferred shares having similar voting rights) will be entitled to elect two additional directors and the number of directors on the Company's Board of Directors will increase by that same number.

Common Stock

        On August 13, 2013, the Company completed the issuance and sale of 43.7 million shares of its common stock in an underwritten public offering. The shares of common stock sold have been registered under the Securities Act pursuant to a Registration Statement on Form S-3 (No. 333-188640), which was filed with the SEC and became automatically effective on May 16, 2013. The net proceeds to the Company from the offering of common stock were approximately $215.2 million, after deducting the underwriting discount and estimated offering expenses. The Company used the net proceeds from the offering to repay a portion of the then outstanding borrowings under its Senior Credit Agreement.

        On January 17, 2013, with stockholder approval, the Company filed a Certificate of Amendment of the Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to increase its authorized common stock by approximately 333.3 million shares for a total of 670.0 million authorized shares of common stock.

Warrants

        In February 2012, in conjunction with the issuance of the 2017 Notes, the Company issued warrants to purchase 36.7 million shares of the Company's common stock at an exercise price of $4.50 per share of common stock, which the Company refers to as the February 2012 Warrants. The Company allocated $43.6 million to the February 2012 Warrants which is reflected in additional paid-in capital in stockholders' equity, net of $0.6 million in issuance costs. The February 2012 Warrants entitle the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

        In August 2012, as part of the Company's acquisition of GeoResources by merger, the Company assumed outstanding GeoResources common stock warrants. At the date of the merger 0.6 million GeoResources warrants were outstanding and were converted to 1.2 million Halcón warrants (the August 2012 Warrants). Each GeoResources warrant was converted into an August 2012 Warrant to acquire one share of Halcón common stock (Share Portion) at an exercise price of $8.40 per share of common stock and the right to receive $20 in cash per equivalent assumed share (Cash Portion) at an exercise price of $0.82 per $1.00 received. The August 2012 Warrants contained substantially the same terms of the original GeoResources warrants with adjustments to the exercise price and addition of the Cash Portion to reflect the impact of the consideration per share in the merger. The August 2012 Warrants expired on June 9, 2013. The August 2012 Warrants were reflected as a current liability in the unaudited condensed consolidated balance sheets at March 31, 2013 and were recorded at fair value. Changes in fair value were recognized in "Interest expense and other, net" in the unaudited condensed consolidated statements of operations.

Incentive Plan

        On May 8, 2006, the Company's stockholders first approved its 2006 Long-Term Incentive Plan (the Plan). On May 23, 2013, shareholders last approved an increase in authorized shares under the Plan from 11.5 million to 41.5 million. As of March 31, 2014 and December 31, 2013, a maximum of 13.2 million and 25.7 million shares of common stock, respectively, remained reserved for issuance under the Plan.

        The Company accounts for share-based payment accruals under authoritative guidance on stock compensation, as set forth in ASC Topic 718. The guidance requires all share-based payments to employees and directors, including grants of performance units, stock options, and restricted stock, to be recognized in the financial statements based on their fair values.

        For the three months ended March 31, 2014 and 2013, the Company recognized $4.3 million and $2.3 million, respectively, of share-based compensation expense as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

Performance Share Units

        During the three months ended March 31, 2014, the Company granted performance share units (PSU) under the Plan covering 1.6 million shares of common stock to senior management of the Company. The PSU provide that the number of shares of common stock received upon vesting will vary if the market price of the Company's common stock exceeds certain pre-established target thresholds as measured by the average of the adjusted closing price of a share of the Company's common stock during the sixty trading days preceding the third anniversary of issuance, or the measurement date. The PSU utilize $4.00 as the floor price, below which the PSU will not vest and will expire. If the average market price at the measurement date is equal to $4.00, the PSU will vest and represent the right to receive 50% of the number of shares of common stock underlying the PSU. At $7.00, the PSU will vest and represent the right to receive the full number of shares of common stock underlying the PSU; and at $10.00, the PSU will vest and represent the right to receive 200% of the number of shares of common stock underlying the PSU. All stock price targets are subject to customary adjustments based upon changes in the Company's capital structure. In the event the average market price falls between targeted price thresholds, the PSU will vest and represent the right to receive a proportionate number of shares, e.g., 75% of the number of shares of common stock underlying the PSU if the average market price at such time is $5.50, 150% of the number of shares of common stock underlying the PSU if the average market price at such time is $8.50, and so forth. The Company has reserved for issuance under the Plan the maximum right to receive upon vest of the PSU, or 3.2 million shares of common stock. At March 31, 2014, the Company had $4.8 million of unrecognized compensation expense related to non-vested PSU to be recognized over a weighted-average period of 2.9 years.

Stock Options

        During the three months ended March 31, 2014, the Company granted stock options under the Plan covering 6.1 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $3.67 to $4.33 with a weighted average exercise price of $3.67. 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. At March 31, 2014, the Company had $20.4 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.6 years.

        During the three months ended March 31, 2013, the Company granted stock options under the Plan covering 1.5 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $6.36 to $8.23 with a weighted average exercise price of $7.20. 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. At March 31, 2013, the unrecognized compensation expense related to stock options totaled $14.4 million and will be recognized on the graded-vesting method over the requisite service periods.

        During the three months ended March 31, 2013, the Company's Board of Directors approved an increase in authorized shares under the Plan from 11.5 million to 41.5 million, subject to stockholder approval. As a result, stock options granted to executive officers and certain other participants covering 4.4 million shares during the three months ended March 31, 2013 were pending stockholder approval on May 23, 2013 because these grants would have caused the Company to exceed the limit of shares available under the Plan. These awards were subject to forfeiture in the event that stockholder approval was not obtained and therefore the Company did not record any expense associated with the amortization of these awards in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2013.

Restricted Stock

        During the three months ended March 31, 2014, the Company granted 3.6 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $3.67 to $4.33 with a weighted average price of $3.67. Employee shares vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six-months from the date of grant. At March 31, 2014, the Company had $19.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.7 years.

        During the three months ended March 31, 2013, the Company granted 2.8 million shares of restricted stock under the Plan to directors and employees of the Company. These restricted shares were granted at prices ranging from $6.36 to $7.26 with a weighted average price of $7.10. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant. At March 31, 2013, the Company had $20.1 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.8 years.

Treasury Stock

        During the three months ended March 31, 2013, the Company granted 2.8 million shares of restricted stock under the Plan to directors and employees of the Company of which 1.2 million shares were issued out of treasury stock. In addition, the Company retired 0.4 million shares from treasury stock representing shares that were repurchased for taxes tendered upon vesting of stock based compensation awards in prior years. As of March 31, 2013, the Company had no issued shares held in treasury.

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ASSET RETIREMENT OBLIGATIONS

3 Months Ended

Mar. 31, 2014

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

7. ASSET RETIREMENT OBLIGATIONS

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

        The Company recorded the following activity related to its ARO liability for the three months ended March 31, 2014 (in thousands, inclusive of the current portion):

Liability for asset retirement obligations as of December 31, 2013	$	39,257
Liabilities settled and divested		(2,019	)
Additions		1,104
Accretion expense		479
Revisions in estimated cash flows		154
Liability for asset retirement obligations as of March 31, 2014	$	38,975

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2014

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

8. COMMITMENTS AND CONTINGENCIES

Commitments

        The Company leases corporate office space in Houston, Texas; Tulsa, Oklahoma; and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $1.9 million and $2.5 million for the three months ended March 31, 2014 and 2013, respectively. In addition, the Company has commitments for certain equipment under long-term operating lease agreements, namely drilling rigs as well as pipeline and well equipment, with various expiration dates through 2017. Early termination of the drilling rig commitments would result in termination penalties approximating $42.3 million, which would be in lieu of the remaining $79.7 million of drilling rig commitments as of March 31, 2014. As of March 31, 2014, the amount of commitments under office and equipment lease agreements is consistent with the levels at December 31, 2013, as disclosed in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013, approximating $66.6 million in the aggregate, and containing various expiration dates through 2024.

        The Company has entered into various long-term gathering, transportation and sales contracts in its Bakken / Three Forks formations in North Dakota. As of March 31, 2014, the Company had in place nine long-term crude oil contracts and two long-term natural gas contracts in this area. Under the terms of these contracts, the Company has committed a substantial portion of its Bakken / Three Forks production for periods ranging from five to ten years from the date of first production. The sales prices under these contracts are based on posted market rates. The Company believes that there are sufficient available reserves and supplies in the Bakken / Three Forks formations to meet its commitments.

        Additionally, as of March 31, 2014, the Company had one long-term natural gas transportation contract and one long-term natural gas gathering contract in the Woodbine formation in East Texas. The rate under the transportation contract was negotiated based on market rates and the contract term is five years from the date of first production. Under the gathering contract, the Company has committed substantially all of its natural gas production from specific wells in the area, until a contracted volume amount is reached, in exchange for the construction of a gathering system. The contract term is five years from the date of first production.

        Historically, the Company has been able to meet its delivery commitments.

        On December 20, 2013, the Company entered into a carry and earning agreement, as amended (the Agreement), with an independent third party (the Seller) associated with the acquisition of certain properties prospective for the Tuscaloosa Marine Shale, primarily in Wilkinson County, Mississippi and in West Feliciana and East Feliciana Parishes, Louisiana. The Agreement requires the Company to fund up to $189.4 million (the Carry Amount) in exchange for approximately 117,870 net acres. The Company paid $62.5 million of the Carry Amount at closing on February 28, 2014. The Carry Amount is to be used by the Seller to fund wells prospective for the Tuscaloosa Marine Shale to be drilled by the Seller (the Carry Wells) on the Seller's retained acreage. As part of the transaction, the Company will also receive a 5% working interest in the Carry Wells. The commitment period is from January 1, 2014 through August 31, 2017, and is capped at $120.0 million through December 31, 2014 and up to the full $189.4 million through August 31, 2017. Any amount of the commitment not spent or subject to an approval for expenditure by the Seller on or before August 31, 2017 shall be forfeited.

Contingencies

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

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INCOME TAXES

3 Months Ended

Mar. 31, 2014

INCOME TAXES

INCOME TAXES

10. INCOME TAXES

        Under guidance contained in Topic 740 of the ASC, deferred taxes are determined by applying the provisions of enacted tax laws and rates for the jurisdictions in which the Company operates to the estimated future tax effects of the differences between the tax basis of assets and liabilities and their reported amounts in the Company's financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

        In assessing the need for a valuation allowance on our deferred tax assets, the Company considers possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. A significant item of objective negative evidence considered was the cumulative three-year book loss driven primarily by ceiling test write-downs in 2013. Based upon the evaluation of the available evidence the Company continued to record a full valuation allowance against its net deferred tax assets as of March 31, 2014.

        The Company recorded no income tax expense or benefit on a pre-tax loss of $73.0 million for the three months ended March 31, 2014 due to the valuation allowance. For the three months ended March 31, 2013, the Company recorded a tax provision of $3.3 million on pre-tax income of $8.8 million. The effective tax rate for the three months ended March 31, 2014 was 0.0% compared to 37.6% for the three months ended March 31, 2013. The significant difference in the effective tax rate is due to the full valuation allowance that was established during the fourth quarter of 2013.

        During the first quarter of 2014, the Internal Revenue Service commenced an audit of GeoResources, Inc.'s tax returns for the tax years ending December 31, 2010 through August 1, 2012. The audit is ongoing as of the date of this filing.

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LONG-TERM DEBT (Details 5) (USD $)	0 Months Ended	3 Months Ended
	Dec. 28, 2012	Mar. 31, 2013
Long-term debt
Cash consideration		$ 29,895,000
Acquisition of certain oil and natural gas properties in Brazos Country, Texas
Long-term debt
Purchase price	83,700,000
Cash consideration	8,400,000
Notice given to sellers for assertion of title and environmental defects for remaining properties		12,900,000
Promissory Notes | Acquisition of certain oil and natural gas properties in Brazos Country, Texas
Long-term debt
Promissory notes as consideration for acquisition	75,300,000
Amount paid to relieve a portion of the outstanding promissory notes		62,400,000
Unamortized discount	$ 600,000

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2014

FAIR VALUE MEASUREMENTS

Schedule of fair value of the Company's financial assets and liabilities

	March 31, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	15,457	$	—	$	15,457
Liabilities
Liabilities from derivative contracts	$	—	$	51,124	$	2,784	$	53,908

	December 31, 2013
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	24,762	$	—	$	24,762
Liabilities
Liabilities from derivative contracts	$	—	$	34,376	$	2,816	$	37,192

Schedule of reconciliation of changes in the fair value of the Company's oil derivative instruments classified as Level 3 in the fair value hierarchy

The following table sets forth a reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy (in thousands):

	Significant Unobservable Inputs (Level 3)
	March 31, 2014			December 31, 2013
Beginning Balance	$	(2,816	)	$	—
Net gain (loss) on derivative contracts		32			(2,816	)
Settlements		—			—
Purchase of derivative contracts		—			—
Buy out of derivative contracts		—			—
Ending Balance	$	(2,784	)	$	(2,816	)
Change in unrealized gains (losses) included in earnings related to derivatives still held at March 31, 2014 and December 31, 2013	$	32		$	(2,816	)

Schedule of the estimated fair values of the Company's fixed interest rate, long-term debt instruments

	March 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
9.25% $400 million senior notes	$	400,000	$	416,924	$	400,000	$	407,432
8.875% $1.35 billion senior notes		1,350,000		1,401,975		1,350,000		1,390,500
9.75% $1.15 billion senior notes		1,150,000		1,242,000		1,150,000		1,197,438
8.0% $289.7 million convertible note		289,669		393,423		289,669		368,418
	$	3,189,669	$	3,454,322	$	3,189,669	$	3,363,788

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FINANCIAL STATEMENT PRESENTATION (Details) (USD $)	3 Months Ended
	Mar. 31, 2014 item	Mar. 31, 2013
Basis of Presentation and Principles of Consolidation
Number of operating segments	1
Allowance for doubtful accounts receivable	$ 0
Corrections of errors
Net cash provided by operating activities	(159,500,000)	(45,710,000)
Net cash used in investing activities	(509,498,000)	(445,024,000)
Correction of errors related to capitalized non-cash interest
Corrections of errors
Net cash provided by operating activities		(9,600,000)
Net cash used in investing activities		$ 9,600,000

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DERIVATIVE AND HEDGING ACTIVITIES (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivative Assets
Gross amounts presented in the consolidated balance sheets	$ 15,457	$ 24,762
Amounts not offset in the consolidated balance sheets	(14,625)	(20,036)
Net amount	832	4,726
Derivative Liabilities
Gross amounts presented in the consolidated balance sheet	(53,908)	(37,192)
Amounts not offset in the consolidated balance sheet	14,235	19,507
Net amount	$ (39,673)	$ (17,685)
January 2014 - March 2014 | Three- Way Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		144,000
Floors (in dollars per Mmbtu's/Bbl's)		95.00
Put Options Sold (in dollars per Mmbtu's/Bbl's)		70.00
January 2014 - March 2014 | Three- Way Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)		98.60
January 2014 - March 2014 | Three- Way Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)		109.50
January 2014 - March 2014 | Three- Way Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		95.00
Ceilings (in dollars per Mmbtu's/Bbl's)		100.03
Put Options Sold (in dollars per Mmbtu's/Bbl's)		70.00
January 2014 - June 2014 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		724,000
Floors (in dollars per Mmbtu's/Bbl's)		90.00
January 2014 - June 2014 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)		96.50
January 2014 - June 2014 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)		99.50
January 2014 - June 2014 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		90.00
Ceilings (in dollars per Mmbtu's/Bbl's)		98.00
January 2014 - December 2014 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		7,573,750
January 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		85.00
Ceilings (in dollars per Mmbtu's/Bbl's)		93.60
January 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		95.00
Ceilings (in dollars per Mmbtu's/Bbl's)		108.45
January 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		88.67
Ceilings (in dollars per Mmbtu's/Bbl's)		96.22
January 2014 - December 2014 | Collars | Commodity contracts | Natural Gas
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		11,862,500
January 2014 - December 2014 | Collars | Commodity contracts | Natural Gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		3.75
Ceilings (in dollars per Mmbtu's/Bbl's)		4.26
January 2014 - December 2014 | Collars | Commodity contracts | Natural Gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		4.00
Ceilings (in dollars per Mmbtu's/Bbl's)		4.55
January 2014 - December 2014 | Collars | Commodity contracts | Natural Gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		3.85
Ceilings (in dollars per Mmbtu's/Bbl's)		4.35
April 2014 - June 2014 | Three- Way Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	136,500	136,500
Floors (in dollars per Mmbtu's/Bbl's)	95.00	95.00
Put Options Sold (in dollars per Mmbtu's/Bbl's)	70.00	70.00
April 2014 - June 2014 | Three- Way Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	98.20	98.20
April 2014 - June 2014 | Three- Way Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	101.00	101.00
April 2014 - June 2014 | Three- Way Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	95.00	95.00
Ceilings (in dollars per Mmbtu's/Bbl's)	99.13	99.13
Put Options Sold (in dollars per Mmbtu's/Bbl's)	70.00	70.00
April 2014 - June 2014 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	364,000
Floors (in dollars per Mmbtu's/Bbl's)	90.00
April 2014 - June 2014 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	96.50
April 2014 - June 2014 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	99.50
April 2014 - June 2014 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	90.00
Ceilings (in dollars per Mmbtu's/Bbl's)	98.00
April 2014 - December 2014 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	5,706,250
April 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	85.00
Ceilings (in dollars per Mmbtu's/Bbl's)	93.60
April 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	95.00
Ceilings (in dollars per Mmbtu's/Bbl's)	108.45
April 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	88.67
Ceilings (in dollars per Mmbtu's/Bbl's)	96.27
April 2014 - December 2014 | Collars | Commodity contracts | Natural Gas
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	8,937,500
April 2014 - December 2014 | Collars | Commodity contracts | Natural Gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	3.75
Ceilings (in dollars per Mmbtu's/Bbl's)	4.26
April 2014 - December 2014 | Collars | Commodity contracts | Natural Gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	4.00
Ceilings (in dollars per Mmbtu's/Bbl's)	4.55
April 2014 - December 2014 | Collars | Commodity contracts | Natural Gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	3.85
Ceilings (in dollars per Mmbtu's/Bbl's)	4.35
July 2014 - December 2014 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	920,000	920,000
July 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	87.50	87.50
Ceilings (in dollars per Mmbtu's/Bbl's)	92.50	92.50
July 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	90.00	90.00
Ceilings (in dollars per Mmbtu's/Bbl's)	100.25	100.25
July 2014 - December 2014 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	89.50	89.50
Ceilings (in dollars per Mmbtu's/Bbl's)	97.87	97.87
July 2014 - December 2014 | Collars | Commodity contracts | Natural Gas
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	920,000	920,000
Floors (in dollars per Mmbtu's/Bbl's)	4.00	4.00
Ceilings (in dollars per Mmbtu's/Bbl's)	4.42	4.42
July 2014 - December 2014 | Collars | Commodity contracts | Natural Gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	4.00	4.00
Ceilings (in dollars per Mmbtu's/Bbl's)	4.42	4.42
July 2014 - December 2014 | Put options | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	184,000	184,000
Put Options Sold (in dollars per Mmbtu's/Bbl's)	90.00	90.00
July 2014 - December 2014 | Put options | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Put Options Sold (in dollars per Mmbtu's/Bbl's)	90.00	90.00
January 2015 - June 2015 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	1,583,750	1,583,750
January 2015 - June 2015 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	85.00	85.00
Ceilings (in dollars per Mmbtu's/Bbl's)	91.00	91.00
January 2015 - June 2015 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	90.00	90.00
Ceilings (in dollars per Mmbtu's/Bbl's)	98.50	98.50
January 2015 - June 2015 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	86.29	86.29
Ceilings (in dollars per Mmbtu's/Bbl's)	93.14	93.14
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	5,475,000	5,110,000
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | 730,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		730,000
Floors (in dollars per Mmbtu's/Bbl's)		85.00
Ceilings (in dollars per Mmbtu's/Bbl's)		96.20
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | 365,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		365,000
Floors (in dollars per Mmbtu's/Bbl's)		85.00
Ceilings (in dollars per Mmbtu's/Bbl's)		96.00
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | 732,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	732,000
Floors (in dollars per Mmbtu's/Bbl's)	85.00
Ceilings (in dollars per Mmbtu's/Bbl's)	96.20
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | 366,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	366,000
Floors (in dollars per Mmbtu's/Bbl's)	85.00
Ceilings (in dollars per Mmbtu's/Bbl's)	96.00
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	82.50	82.50
Ceilings (in dollars per Mmbtu's/Bbl's)	90.00	90.00
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	90.00	90.00
Ceilings (in dollars per Mmbtu's/Bbl's)	100.25	100.25
January 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	86.00	86.07
Ceilings (in dollars per Mmbtu's/Bbl's)	94.34	94.65
January 2015 - December 2015 | Collars | Commodity contracts | Natural Gas
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	6,387,500	6,387,500
Floors (in dollars per Mmbtu's/Bbl's)	4.00	4.00
January 2015 - December 2015 | Collars | Commodity contracts | Natural Gas | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	4.55	4.55
January 2015 - December 2015 | Collars | Commodity contracts | Natural Gas | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	4.85	4.85
January 2015 - December 2015 | Collars | Commodity contracts | Natural Gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	4.00	4.00
Ceilings (in dollars per Mmbtu's/Bbl's)	4.68	4.68
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	1,095,000	1,095,000
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil | 730,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		730,000
Floors (in dollars per Mmbtu's/Bbl's)		91.25
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil | 365,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's		365,000
Floors (in dollars per Mmbtu's/Bbl's)		91.00
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil | 732,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	732,000
Floors (in dollars per Mmbtu's/Bbl's)	91.25
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil | 366,000 Bbls | Extendable period through December 31, 2016
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	366,000
Floors (in dollars per Mmbtu's/Bbl's)	91.00
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	91.00	91.00
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	91.25	91.25
January 2015 - December 2015 | Swaps | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	91.17	91.17
July 2015 - December 2015 | Collars | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	644,000
Floors (in dollars per Mmbtu's/Bbl's)	85.00
July 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	90.00
July 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	90.50
July 2015 - December 2015 | Collars | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	85.00
Ceilings (in dollars per Mmbtu's/Bbl's)	90.16
January 2016 - December 2016 | Collars | Commodity contracts | Natural Gas
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	732,000
Floors (in dollars per Mmbtu's/Bbl's)	4.00
Ceilings (in dollars per Mmbtu's/Bbl's)	4.22
January 2016 - December 2016 | Collars | Commodity contracts | Natural Gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	4.00
Ceilings (in dollars per Mmbtu's/Bbl's)	4.22
January 2016 - December 2016 | Swaps | Commodity contracts | Crude Oil
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	2,196,000	2,190,000
January 2016 - December 2016 | Swaps | Commodity contracts | Crude Oil | 730,000 Bbls | Extendable period through December 31, 2017
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	730,000	730,000
Floors (in dollars per Mmbtu's/Bbl's)	88.25	88.25
January 2016 - December 2016 | Swaps | Commodity contracts | Crude Oil | 912,500 Bbls | Extendable period through December 31, 2017
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	912,500	912,500
Floors (in dollars per Mmbtu's/Bbl's)	88.00	88.00
January 2016 - December 2016 | Swaps | Commodity contracts | Crude Oil | 547,500 Bbls | Extendable period through December 31, 2017
Derivative and hedging activities
Volume in Mmbtu's/Bbl's	547,500	547,500
Floors (in dollars per Mmbtu's/Bbl's)	88.87	88.87
January 2016 - December 2016 | Swaps | Commodity contracts | Crude Oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	88.00	88.00
January 2016 - December 2016 | Swaps | Commodity contracts | Crude Oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	88.87	88.87
January 2016 - December 2016 | Swaps | Commodity contracts | Crude Oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	88.30	88.30

XML

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total USD ($)	Preferred Stock	Common Stock USD ($)	Additional Paid-In Capital USD ($)	Treasury Stock USD ($)	Accumulated Deficit USD ($)
Balances at Dec. 31, 2012					$ (9,298)
Balances at Dec. 31, 2012	1,397,982		26	1,681,717		(274,463)
Balances (in shares) at Dec. 31, 2012					1,650,000
Balances (in shares) at Dec. 31, 2012			259,802,000
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(1,222,662)					(1,222,662)
Dividends on Series A preferred stock				9,092		(9,092)
Dividends on Series A preferred stock (in shares)			2,045,000
Preferred stock conversion	695,238		11	695,227
Preferred stock conversion (in shares)			108,801,000
Sale of Series A preferred stock	345,000			345,000
Sale of Series A preferred stock (in shares)		345,000
Common stock issuance	222,870		4	222,866
Common stock issuance (in shares)			43,700,000
Offering costs	(17,346)			(17,346)
Long-term incentive plan grants (in shares)			3,267,000
Long-term incentive plan forfeitures (in shares)			(205,000)
Reduction in shares to cover individuals' tax withholding	(148)			(148)
Reduction in shares to cover individuals' tax withholding (in shares)			(30,000)
Retirement of shares in treasury				(2,492)	2,492
Retirement of shares in treasury (in shares)			(442,000)		(442,000)
Long-term incentive plan grants issued out of treasury				(6,806)	6,806
Long-term incentive plan grants issued out of treasury (in shares)			(1,208,000)		(1,208,000)
Share-based compensation	26,676			26,676
Balances at Dec. 31, 2013	1,447,610		41	2,953,786		(1,506,217)
Balances (in shares) at Dec. 31, 2013		345,000	415,730,000
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(72,964)					(72,964)
Dividends on Series A preferred stock	(4,959)			4,959		(4,959)
Dividends on Series A preferred stock (in shares)			1,394,000
Offering costs	45			45
Long-term incentive plan grants (in shares)			3,568,000
Long-term incentive plan forfeitures (in shares)			(68,000)
Reduction in shares to cover individuals' tax withholding	(389)			(389)
Reduction in shares to cover individuals' tax withholding (in shares)			(103,000)
Share-based compensation	6,502			6,502
Balances at Mar. 31, 2014	$ 1,380,804		$ 41	$ 2,964,903		$ (1,584,140)
Balances (in shares) at Mar. 31, 2014		345,000	420,521,000

XML

LONG-TERM DEBT

3 Months Ended

Mar. 31, 2014

LONG-TERM DEBT.

LONG-TERM DEBT

4. LONG-TERM DEBT

        Long-term debt as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014(1)		December 31, 2013(1)
	(In thousands)
Senior revolving credit facility	$	348,000	$	—
9.25% senior notes due 2022		400,000		400,000
8.875% senior notes due 2021(2)		1,371,791		1,372,355
9.75% senior notes due 2020(3)		1,152,029		1,152,099
8.0% convertible note due 2017(4)		261,373		259,369
	$	3,533,193	$	3,183,823

⁽¹⁾

Table excludes $1.4 million of deferred premiums on derivative contracts which were classified as current at March 31, 2014 and December 31, 2013.

⁽²⁾

Amounts are net of a $5.0 million and a $5.1 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $26.8 million and $27.5 million at March 31, 2014 and December 31, 2013, respectively. See "8.875% Senior Notes" below for more details.

⁽³⁾

Amounts are net of a $8.6 million and a $8.9 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2020 Notes. On December 19, 2013, the Company completed the issuance of an additional $400 million principal amount of these notes. The unamortized premium related to these additional 2020 Notes was approximately $10.6 million and $11.0 million at March 31, 2014 and December 31, 2013, respectively. See "9.75% Senior Notes" below for more details.

⁽⁴⁾

Amount is net of a $28.3 million and a $30.3 million unamortized discount at March 31, 2014 and December 31, 2013, respectively. See "8.0% Convertible Note" below for more details.

Senior Revolving Credit Facility

        On February 8, 2012, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Senior Credit Agreement provides for a $1.5 billion facility with a current borrowing base of $800.0 million. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that the Company may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the five-year term of the facility. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's properties and assets. The Senior Credit Agreement contains customary representations, warranties and covenants including, among others, restrictions on the payment of dividends on the Company's capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses of i) not less than 2.0 to 1.0 through December 31, 2014 (pursuant to the Seventh Amendment, discussed below) and ii) not less than 2.5 to 1.0 for subsequent periods.

        At March 31, 2014, under the borrowing base of $800.0 million, the Company had $348.0 million of indebtedness outstanding, $1.2 million of letters of credit outstanding and $450.8 million of borrowing capacity available under the Senior Credit Agreement, of which approximately $332 million was available under the indebtedness limitation in the Company's indentures.

        On October 31, 2013, the Company entered into the Sixth Amendment to the Senior Credit Agreement , which, amount other things, provides for EBITDA (as defined in the Senior Credit Agreement) to be annualized for the next three fiscal quarters for purposes of measuring compliance with the interest coverage test. Specifically, (i) for the fiscal quarter ended December 31, 2013, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the three month period then ended multiplied by 4; (ii) for the fiscal quarter ended March 31, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the six month period then ended multiplied by 2; and (iii) for the fiscal quarter ended June 30, 2014, the Interest Coverage Ratio shall be calculated by utilizing EBITDA for the nine month period then ended multiplied by 1.333.

        On March 21, 2014, the Company entered into the Seventh Amendment to its Senior Credit Agreement (the Seventh Amendment). The Seventh Amendment increased the borrowing base to $800.0 million in connection with the Company's annual spring redetermination and also provided the Company additional flexibility under the interest coverage test by modifying the minimum Interest Coverage Ratio to be 2.0 to 1.0 for any fiscal quarter ending on or before December 31, 2014.

        At March 31, 2014, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

9.25% Senior Notes

        On August 13, 2013, the Company issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering of approximately $392.1 million (after deducting commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Company's Senior Credit Agreement.

        The 2022 Notes bear interest at a rate of 9.25% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on February 15, 2014. The 2022 Notes will mature on February 15, 2022. The 2022 Notes are senior unsecured obligations of the Company, rank equally with all of its current and future senior indebtedness and are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for one minor subsidiary. Halcón, the issuer of the 2022 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        In connection with the sales of the 2022 Notes, the Company entered into registration rights agreements, pursuant to which the Company agreed to conduct a registered exchange offer for the 2022 Notes or cause to become effective a shelf registration statement providing for the resale of the 2022 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement and use its reasonable best efforts to cause such registration statement for the 2022 Notes to become effective, (b) promptly following the effectiveness of such registration statement, offer to exchange new registered notes having terms substantially identical to the 2022 Notes for outstanding 2022 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2022 Notes. If the exchange offer is not consummated within 365 days after August 13, 2013, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2022 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the registration rights agreements it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2022 Notes. On March 14, 2014, the Company filed a registration statement on Form S-4 with the SEC relating to the offer to exchange registered 9.25% senior notes due 2022 for any and all of its 2022 Notes and, on April 18, 2014, the Company commenced such offer to exchange.

        On or before August 15, 2016, the Company may redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.250% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2022 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the related equity offering. In addition, at any time prior to August 15, 2017, the Company may redeem some or all of the 2022 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at August 15, 2017, plus (ii) any required interest payments due on the notes through August 15, 2017 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

        The indenture governing the 2022 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes 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. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

8.875% Senior Notes

        On November 6, 2012, the Company issued $750.0 million aggregate principal amount of its 8.875% senior notes due 2021 (the 2021 Notes), at a price to the initial purchasers of 99.247% of par. The net proceeds from the offering of approximately $725.6 million (after deducting the initial purchasers' discounts, commissions and offering expenses) were used to fund a portion of the cash consideration paid in the acquisition of two wholly-owned subsidiaries of Petro-Hunt Holdings, LLC and Pillar Holdings, LLC, which owned acreage prospective for the Bakken / Three Forks formations located in North Dakota, in Williams, Mountrail, McKenzie and Dunn Counties.

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

        The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2021 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for one minor subsidiary. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        On June 4, 2013, the Company completed a registered exchange offer of outstanding 2021 Notes for new registered notes having terms substantially identical to the 2021 Notes.

        On or before November 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds of certain equity offerings at a redemption price of 108.875% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2021 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the date of closing of the related equity offering. In addition, at any time prior to November 15, 2016, the Company may redeem some or all of the 2021 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at November 15, 2016, plus (ii) any required interest payments due on the notes through November 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

        In conjunction with the issuance of the 2021 Notes, the Company recorded a discount of approximately $5.7 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $5.0 million at March 31, 2014. In conjunction with the issuance of the additional 2021 Notes, the Company recorded a premium of approximately $30.0 million to be amortized over the remaining life of the additional 2021 Notes using the effective interest method. The remaining unamortized premium was $26.8 million at March 31, 2014.

        The indenture governing the 2021 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes 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. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

9.75% Senior Notes

        On July 16, 2012, the Company issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Merger and the acquisition of certain oil and gas leaseholds located in East Texas.

        On December 19, 2013, the Company issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes of approximately $406.1 million (after the initial purchasers' fees, commissions and offering expenses) were used to repay a portion of the then outstanding borrowings under the Senior Credit Agreement. These notes were issued as "additional notes" under the indenture governing the 2020 Notes and under the indenture are treated as a single series with substantially identical terms as the 2020 Notes previously issued.

        The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2020 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing 100% owned subsidiaries, except for one minor subsidiary. Halcón, the issuer of the 2020 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

        On June 4, 2013, the Company completed a registered exchange offer of the outstanding 2020 Notes originally issued, for new registered notes having terms substantially identical to the original 2020 Notes. In connection with the sales of the additional 2020 Notes, the Company entered into registration rights agreements, pursuant to which the Company agreed to conduct a registered exchange offer for the 2020 Notes or cause to become effective a shelf registration statement providing for the resale of the 2020 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement and use its reasonable best efforts to cause such registration statement for the 2020 Notes to become effective, (b) promptly following the effectiveness of such registration statement, offer to exchange new registered notes having terms substantially identical to the 2020 Notes for outstanding 2020 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2020 Notes. If the exchange offer is not consummated within 180 days after December 19, 2013, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2020 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the registration rights agreements it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2020 Notes. On March 14, 2014, the Company filed a registration statement on Form S-4 with the SEC relating to the offer to exchange registered 9.75% senior notes due 2020 for any and all of its 2020 Notes and, on April 18, 2014, the Company commenced such offer to exchange.

        On or before July 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.750% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2020 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the equity offering. In addition, at any time prior to July 15, 2016, the Company may redeem some or all of the 2020 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess , if any of (a) the present value at such time of (i) the redemption price of such note at July 15, 2016, plus (ii) any required interest payments due on the notes through July 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

        In conjunction with the issuance of the 2020 Notes, the Company recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $8.6 million at March 31, 2014. In conjunction with the issuance of the additional 2020 Notes, the Company recorded a premium of approximately $11.0 million to be amortized over the remaining life of the additional 2020 Notes using the effective interest method. The remaining unamortized premium was approximately $10.6 million at March 31, 2014.

        The indenture governing the 2020 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and its subsidiaries that guarantee notes 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. With respect to indebtedness, the indenture limits the Company's ability to incur additional indebtedness, including borrowings under its Senior Credit Agreement, unless the Company meets one of two tests: the fixed charge coverage ratio test, which requires that after giving effect to the incurrence of additional debt the ratio of the Company's adjusted consolidated EBITDA (as defined in the indenture) to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0; or, in the alternative, the Company may incur additional debt under Credit Facilities (as defined in the indenture) if the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of the Company's adjusted consolidated net tangible assets (as defined in the indenture), which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves as of the date of such determination.

8.0% Convertible Note

        On February 8, 2012, the Company issued the 2017 Note in the principal amount of $275.0 million together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. The 2017 Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year and matures on February 8, 2017. Through the March 31, 2014 interest payment date, the Company was permitted to elect to pay the interest in kind, by adding to the principal of the 2017 Note, all or any portion of the interest due on the 2017 Note. The Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and added $3.2 million, $5.7 million and $5.8 million of interest incurred during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. The Company did not elect to pay-in-kind interest for the quarterly payments due subsequent to September 30, 2012. As of February 8, 2014, holders of the 2017 Note became entitled to convert at their election each $4.50 of principal and accrued but unpaid interest into one share of the Company's common stock. The 2017 Note is a senior unsecured obligation of the Company.

        The Company allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, the Company recorded a discount of $43.6 million to be amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $28.3 million at March 31, 2014.

Promissory Notes

        On December 28, 2012, the Company completed the acquisition of certain oil and natural gas properties in Brazos County, Texas for approximately $83.7 million, before and subject to, customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. During the three months ended March 31, 2013, the Company completed its review of the properties and paid approximately $62.4 million during the period for properties deemed to have clear title and no defects. In addition, notice was given to the sellers of the Company's assertion of title and environmental defects amounting to $12.9 million for the remaining properties. During the three months ended September 30, 2013, the title and environmental defects were cured by the sellers and the Company paid the remaining portion of the purchase price.

        In conjunction with the issuance of the promissory notes in December 2012, the Company recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. The Company expensed the discount during the first quarter of 2013.

Debt Issuance Costs

        The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. During the first three months of 2014, the Company capitalized approximately $0.1 million in costs associated with the issuance of the additional 2020 Notes. At March 31, 2014 and December 31, 2013, the Company had approximately $62.4 million and $64.3 million, respectively, of unamortized debt issuance costs.

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FINANCIAL STATEMENT PRESENTATION (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Gas gathering systems and equipment
Other operating property and equipment
Estimated useful life	30 years
Cost capitalized	$ 101.2	$ 92.0
Automobiles
Other operating property and equipment
Estimated useful life	3 years
Computers
Other operating property and equipment
Estimated useful life	3 years
Computer software | Maximum
Other operating property and equipment
Estimated useful life	5 years
Fixtures, furniture and equipment | Maximum
Other operating property and equipment
Estimated useful life	5 years
Trailers
Other operating property and equipment
Estimated useful life	7 years
Heavy equipment
Other operating property and equipment
Estimated useful life	10 years
Airplane and buildings
Other operating property and equipment
Estimated useful life	20 years

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FAIR VALUE MEASUREMENTS (Details 3) (USD $)	Mar. 31, 2014 9.25% senior notes	Dec. 31, 2013 9.25% senior notes	Aug. 13, 2013 9.25% senior notes	Mar. 31, 2014 8.875% senior notes	Dec. 31, 2013 8.875% senior notes	Jan. 14, 2013 8.875% senior notes	Nov. 06, 2012 8.875% senior notes	Mar. 31, 2014 9.75% senior notes	Dec. 31, 2013 9.75% senior notes	Dec. 19, 2013 9.75% senior notes	Jul. 16, 2012 9.75% senior notes	Mar. 31, 2014 8% convertible note	Dec. 31, 2013 8% convertible note	Feb. 08, 2012 8% convertible note	Mar. 31, 2014 Carrying Amount	Dec. 31, 2013 Carrying Amount	Mar. 31, 2014 Carrying Amount 9.25% senior notes	Dec. 31, 2013 Carrying Amount 9.25% senior notes	Mar. 31, 2014 Carrying Amount 8.875% senior notes	Dec. 31, 2013 Carrying Amount 8.875% senior notes	Mar. 31, 2014 Carrying Amount 9.75% senior notes	Dec. 31, 2013 Carrying Amount 9.75% senior notes	Mar. 31, 2014 Carrying Amount 8% convertible note	Dec. 31, 2013 Carrying Amount 8% convertible note	Mar. 31, 2014 Estimated Fair Value	Dec. 31, 2013 Estimated Fair Value	Mar. 31, 2014 Estimated Fair Value 9.25% senior notes	Dec. 31, 2013 Estimated Fair Value 9.25% senior notes	Mar. 31, 2014 Estimated Fair Value 8.875% senior notes	Dec. 31, 2013 Estimated Fair Value 8.875% senior notes	Mar. 31, 2014 Estimated Fair Value 9.75% senior notes	Dec. 31, 2013 Estimated Fair Value 9.75% senior notes	Mar. 31, 2014 Estimated Fair Value 8% convertible note	Dec. 31, 2013 Estimated Fair Value 8% convertible note
Fair value measurements
Interest rate (as a percent)	9.25%	9.25%	9.25%	8.875%	8.875%	8.875%	8.875%	9.75%	9.75%	9.75%	9.75%	8.00%	8.00%	8.00%
Principal amount	$ 400,000,000	$ 400,000,000	$ 400,000,000	$ 1,350,000,000	$ 1,350,000,000	$ 600,000,000	$ 750,000,000	$ 1,150,000,000	$ 1,150,000,000		$ 750,000,000	$ 289,700,000	$ 289,700,000	$ 275,000,000
Estimated fair value of debt															$ 3,189,669,000	$ 3,189,669,000	$ 400,000,000	$ 400,000,000	$ 1,350,000,000	$ 1,350,000,000	$ 1,150,000,000	$ 1,150,000,000	$ 289,669,000	$ 289,669,000	$ 3,454,322,000	$ 3,363,788,000	$ 416,924,000	$ 407,432,000	$ 1,401,975,000	$ 1,390,500,000	$ 1,242,000,000	$ 1,197,438,000	$ 393,423,000	$ 368,418,000

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LONG-TERM DEBT (Tables)

3 Months Ended

Mar. 31, 2014

LONG-TERM DEBT.

Schedule of long-term debt

	March 31, 2014(1)		December 31, 2013(1)
	(In thousands)
Senior revolving credit facility	$	348,000	$	—
9.25% senior notes due 2022		400,000		400,000
8.875% senior notes due 2021(2)		1,371,791		1,372,355
9.75% senior notes due 2020(3)		1,152,029		1,152,099
8.0% convertible note due 2017(4)		261,373		259,369
	$	3,533,193	$	3,183,823

⁽¹⁾

Table excludes $1.4 million of deferred premiums on derivative contracts which were classified as current at March 31, 2014 and December 31, 2013.

⁽²⁾

Amounts are net of a $5.0 million and a $5.1 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $26.8 million and $27.5 million at March 31, 2014 and December 31, 2013, respectively. See "8.875% Senior Notes" below for more details.

⁽³⁾

Amounts are net of a $8.6 million and a $8.9 million unamortized discount at March 31, 2014 and December 31, 2013, respectively, related to the issuance of the original 2020 Notes. On December 19, 2013, the Company completed the issuance of an additional $400 million principal amount of these notes. The unamortized premium related to these additional 2020 Notes was approximately $10.6 million and $11.0 million at March 31, 2014 and December 31, 2013, respectively. See "9.75% Senior Notes" below for more details.

⁽⁴⁾

Amount is net of a $28.3 million and a $30.3 million unamortized discount at March 31, 2014 and December 31, 2013, respectively. See "8.0% Convertible Note" below for more details.