Edgar Filing: HALCON RESOURCES CORP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

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

1311

20-0700684

(State or other jurisdiction of

incorporation or organization)

(Primary Standard Industrial
Classification Code Number)

(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 x 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 x No o

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

Large Accelerated Filer o		Accelerated Filer x

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

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

At August 1, 2012, 211,836,319 shares of the Registrant’s Common Stock were outstanding.

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Second Quarter 2012 Form 10-Q Report

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	Page
PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (unaudited)

Condensed Consolidated Statements of Operations — Three and Six Months Ended June 30, 2012 and 2011	5

Condensed Consolidated Balance Sheets —June 30, 2012 and December 31, 2011	6

Condensed Consolidated Statements of Stockholders’ Equity — Six Months Ended June 30, 2012 and Year Ended December 31, 2011	7

Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2012 and 2011	8

Notes to Condensed Consolidated Financial Statements	10

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35

ITEM 4. CONTROLS AND PROCEDURES	35

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	36

ITEM 1A. RISK FACTORS	36

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	40

ITEM 3. DEFAULTS UPON SENIOR SECURITIES	40

ITEM 4. MINE SAFETY DISCLOSURES	40

ITEM 5. OTHER INFORMATION	40

ITEM 6. EXHIBITS	40

SIGNATURES	43

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Special note regarding forward-looking statements

This Quarterly Report on Form 10-Q contains, and we may from time to time otherwise make in other public filings, press releases and presentations, 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,” “believe,” “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. One should consider carefully the statements under the “Risk Factors” section of the previously filed Annual Report on Form 10-K for the year ended December 31, 2011, 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:

· volatility in commodity prices for oil and natural gas;

· our ability to successfully identify and acquire oil and natural gas properties, prospects and leaseholds, including undeveloped acreage in new and emerging resource plays;

· our ability to successfully integrate acquired oil and natural gas businesses and operations, including our recently closed acquisition of GeoResources, Inc. (“GeoResources”) and the East Texas Assets;

· our ability to profitably deploy our capital;

· the possibility that our industry may be subject to future regulatory or legislative actions (including any additional taxes and changes in environmental regulation);

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

· the potential for production decline rates on our wells to be greater than we expect;

· our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to develop our undeveloped acreage positions;

· our ability to economically replace oil and natural gas reserves;

· environmental risks;

· drilling and operating risks;

· exploration and development risks;

· competition, including competition for acreage in resource play areas;

· management’s ability to execute our plans to meet our goals;

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

· the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars;

· access to and availability of water and other treatment materials to carry out planned fracture stimulations of our wells;

· access to adequate gathering systems and transportation take-away capacity to handle our expected production;

· our ability to secure firm transportation and other marketing outlets for the natural gas, natural gas liquids and crude oil and condensate we produce and to sell these products at market prices;

· 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 the 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/or make it difficult to access financial markets;

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· our merger with GeoResources not achieving its intended results or benefits, such as cost savings and operating efficiencies, or failure of effective integration resulting in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s financial position, results of operations or cash flows;

· difficulty attracting, motivating and retaining key employees in light of the GeoResources merger, as employees may feel uncertain about their future roles with the combined company, and resulting potential departure of certain employees could reduce the anticipated benefits of the merger;

· our stockholders were diluted by the merger with GeoResources as we have incurred substantial transaction and merger-related costs in connection with the merger, and the net benefit of the elimination of certain duplicative costs, as well as the realization of efficiencies related to the integration of the two businesses offsetting the incremental merger-related costs over time, may not be achieved in the near-term or at all;

· social unrest, political instability, armed conflict, or acts of terrorism or sabotage in oil and natural gas producing regions, such as the Middle East and Africa, or our markets; and

· other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

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

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Operating revenues:
Oil and natural gas sales
Oil	$	20,383		$	22,783		$	43,380		$	43,195
Natural gas	1,240			2,812			2,908			5,704
NGLs	1,623			2,523			3,792			4,938
Total oil and natural gas sales	23,246			28,118			50,080			53,837
Other	35			34			71			85
Total operating revenues	23,281			28,152			50,151			53,922

Operating expenses:
Production:
Lease operating	8,663			7,812			16,610			15,653
Workover	540			362			1,261			896
Taxes	1,352			1,478			2,922			2,889
Restructuring	903			—			1,007			—
General and administrative	13,087			4,621			33,421			9,168
Depletion, depreciation and accretion	5,956			5,608			11,935			11,283
Total operating expenses	30,501			19,881			67,156			39,889
Income (loss) from operations	(7,220		)	8,271			(17,005		)	14,033

Other income (expenses):
Net gain (loss) on derivative contracts	13,671			8,268			8,726			(5,982		)
Interest expense and other, net	(4,179		)	(4,361		)	(17,176		)	(10,863		)
Total other income (expenses)	9,492			3,907			(8,450		)	(16,845		)
Income (loss) before income taxes	2,272			12,178			(25,455		)	(2,812		)
Income tax provision (benefit)	(5,387		)	3,242			208			(1,837		)
Net income (loss)	7,659			8,936			(25,663		)	(975		)
Non-cash preferred dividend	(87,343		)	—			(88,445		)	—
Net income (loss) available to common stockholders	$	(79,684	)	$	8,936		$	(114,108	)	$	(975	)
Net income (loss) per common share:
Basic	$	(0.59	)	$	0.34		$	(1.11	)	$	(0.04	)
Diluted	$	(0.59	)	$	0.34		$	(1.11	)	$	(0.04	)
Weighted average common shares outstanding:
Basic	136,066			26,278			102,441			26,199
Diluted	136,066			26,278			102,441			26,199

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	June 30,			December 31,
	2012			2011
Current assets:
Cash	$	219,208		$	49
Accounts receivable	9,340			10,288
Receivables from derivative contracts	4,507			260
Deferred income taxes	2,161			2,601
Inventory	4,477			4,310
Prepaids and other	2,513			2,729
Total current assets	242,206			20,237
Oil and natural gas properties (full cost method):
Evaluated	734,551			715,666
Unevaluated	461,620			—
Gross oil and natural gas properties	1,196,171			715,666
Less - accumulated depletion and impairment	(512,538		)	(501,993		)
Net oil and natural gas properties	683,633			213,673
Other operating property and equipment:
Other operating assets and equipment	12,825			9,979
Less - accumulated depreciation	(6,963		)	(7,133		)
Net other operating property and equipment	5,862			2,846
Other noncurrent assets:
Receivables from derivative contracts	2,719			—
Debt issuance costs, net of amortization	5,525			5,966
Deferred income taxes	24,405			24,102
Funds in escrow	29,945			560
Other	491			418
Total assets	$	994,786		$	267,802

Current liabilities:
Accounts payable and accrued liabilities	$	36,774		$	25,061
Liabilities from derivative contracts	—			265
Asset retirement obligations	1,446			1,010
Total current liabilities	38,220			26,336
Long-term debt	242,579			202,000
Other noncurrent liabilities:
Liabilities from derivative contracts	—			805
Asset retirement obligations	33,088			32,703
Other	10			10
Commitments and contingencies
Stockholders’ equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized; no shares issued or outstanding	—			—
Common stock: 336,666,666 and 33,333,333 shares of $0.0001 par value authorized; 145,681,457 and 27,694,583 shares issued; 144,031,546 and 26,244,452 outstanding at June 30, 2012 and December 31, 2011, respectively	15			3
Additional paid-in capital	932,145			229,414
Treasury stock: 1,649,911 and 1,450,131 shares at June 30, 2012 and December 31, 2011, respectively, at cost	(9,298		)	(7,159		)
Accumulated deficit	(241,973		)	(216,310		)
Total stockholders’ equity	680,889			5,948
Total liabilities and stockholders’ equity	$	994,786		$	267,802

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)

	Year Ended December 31, 2011 and
	Six Months Ended June 30, 2012
										Additional
	Preferred Stock					Common Stock				Paid-In			Treasury Stock				Accumulated			Stockholders’
	Shares		Amount			Shares		Amount		Capital			Shares	Amount			Deficit			Equity

BALANCE, December 31, 2010	—		$	—		27,533		$	3	$	226,047		1,404	$	(6,976	)	$	(214,907	)	$	4,167

Long term incentive plan grants	—		—			280		—		—			—	—			—			—

Long term incentive plan forefeitures	—		—			(118	)	—		—			—	—			—			—

Net loss	—		—			—		—		—			—	—			(1,403		)	(1,403		)

Repurchase of stock	—		—			—		—		—			46	(183		)	—			(183		)

Share-based compensation	—		—			—		—		3,367			—	—			—			3,367

BALANCE, December 31, 2011	—		—			27,695		3		229,414			1,450	(7,159		)	(216,310		)	5,948

Warrants issued	—		—			—		—		43,590			—	—			—			43,590

Sale of common stock	—		—			73,333		7		274,993			—	—			—			275,000

Reverse-stock-split rounding	—		—			4		—		—			—	—			—			—

Sale of preferred stock	4		311,556			—		—		—			—	—			—			311,556

Preferred stock conversion	(4	)	(385,476		)	44,445		5		385,471			—	—			—			—

Offering costs	—		(14,525		)	—		—		(4,592		)	—	—			—			(19,117		)

Net loss	—		—			—		—		—			—	—			(25,663		)	(25,663		)

Preferred beneficial conversion feature	—		—			—		—		88,445			—	—			—			88,445

Non-cash preferred dividend	—		88,445			—		—		(88,445		)	—	—			—			—

Long-term incentive plan grants	—		—			204		—		—			—	—			—			—

Repurchase of stock	—		—			—		—		—			200	(2,139		)	—			(2,139		)

Share-based compensation	—		—			—		—		3,269			—	—			—			3,269

BALANCE, June 30, 2012	—		$	—		145,681		$	15	$	932,145		1,650	$	(9,298	)	$	(241,973	)	$	680,889

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Six Months Ended
	June 30,
	2012			2011
Cash flows from operating activities:
Net loss	$	(25,663	)	$	(975	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depletion, depreciation and accretion	11,935			11,283
Deferred income tax provision (benefit)	136			(1,953		)
Share-based compensation	2,465			1,355
Unrealized (gain) loss on derivatives contracts	(8,036		)	5,892
Amortization and write-off of deferred loan costs	6,299			2,990
Non-cash interest and amortization of discount	7,733			362
Other income	(17		)	(22		)
Changes in assets and liabilities:
Accounts receivable	948			49
Inventory	(167		)	(430		)
Prepaid expenses and other	(1,646		)	222
Accounts payable and accrued liabilities	3,500			(5,012		)
Other	(195		)	(718		)
Net cash (used in) provided by operating activities	(2,708		)	13,043
Cash flows from investing activities:
Evaluated oil and natural gas capital expenditures	(14,996		)	(13,500		)
Unevaluated oil and natural gas capital expenditures	(453,201		)	—
Other operating property and equipment capital expenditures	(3,573		)	(469		)
Proceeds received from sales of property and equipment	346			473
Funds held in escrow	(29,385		)	—
Net cash used in investing activities	(500,809		)	(13,496		)
Cash flows from financing activities:
Proceeds from borrowings	237,410			231,166
Repayments of borrowings	(208,000		)	(223,185		)
Debt issuance costs	(5,053		)	(7,003		)
Offering costs	(18,133		)	—
Common stock repurchased	(2,139		)	(108		)
Preferred stock issued	311,556			—
Preferred beneficial conversion feature	88,445			—
Common stock issued	275,000			—
Warrants issued	43,590			—
Net cash provided by financing activities	722,676			870
Net increase in cash	219,159			417
Cash at beginning of period	49			37
Cash at end of period	$	219,208		$	454

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

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HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Continued

(In thousands)

	Six Months Ended
	June 30,
	2012		2011
Supplemental cash flow information:
Cash paid for income taxes	$	199	$	481
Cash paid for interest	3,445		8,706
Disclosure of non-cash investing and financing activities:
Asset retirement obligations	46		(129		)
Preferred dividend	88,445		—
Payment-in-kind interest	8,865		362

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

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HALCÓN RESOURCES CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Halcón Resources Corporation (“Halcón” or the “Company”) is an independent energy company engaged in the exploration, development and production of crude oil and natural gas properties located in the United States. The unaudited condensed consolidated financial statements include the accounts of all subsidiaries. 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 only 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 2011 Annual Report on Form 10-K, filed with the United States Securities and Exchange Commission (“SEC”). Please refer to the notes in the 2011 Annual Report on Form 10-K, when reviewing interim financial results.

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 reserves, amortization relating to oil and natural gas properties, asset retirement obligations, fair value estimates, beneficial conversion feature 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.

Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in the U.S. Generally Accepted Accounting Principles (“GAAP”) and International Financial Accounting Reporting Standards (“IFRS”)”. This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011. The adoption of ASU 2011-04 on January 1, 2012 did not have a material impact on the Company’s financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income”. ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This update is effective for fiscal years, and interim periods within those years beginning after December 15, 2011. In December 2011, the FASB issued ASU No. 2011-12, which becomes effective at the same time as ASU 2011-05, to defer the effective date of provisions of ASU 2011-05 that relate to the presentation of reclassification adjustments. Adoption of ASU 2011-05 and ASU 2011-12 did not have an impact on the Company’s financial position or results of operations.

In December 2011, the FASB issued ASU No. 2011-11 which will enhance disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position. This pronouncement was issued to facilitate comparison between financial statements prepared on the basis of GAAP and IFRS. This update is effective for annual and interim reporting periods

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beginning on or after January 1, 2013 and is to be applied retroactively for all comparative periods presented. The adoption of ASU 2011-11 is not expected to have a significant impact on the Company’s financial position or results of operations.

2. RECAPITALIZATION

On December 21, 2011, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with HALRES LLC (formerly, Halcón Resources, LLC). Pursuant to the Purchase Agreement, (i) HALRES LLC purchased and the Company sold 73,333,333 shares of the Company’s common stock (the “Shares”) for a purchase price of $275,000,000 and (ii) HALRES LLC purchased and the Company issued a senior convertible promissory note in the principal amount of $275,000,000 (the “8% Note”), together with five year warrants (the “Warrants”) to purchase 36,666,666 shares of the Company’s common stock at an exercise price of $4.50 per share, subject to adjustment under certain circumstances. The 8% Note is convertible after February 8, 2014 into 61,111,111 shares of common stock at a conversion price of $4.50 per share, subject to adjustment under certain circumstances. The Company and HALRES LLC closed the transaction contemplated by the Purchase Agreement on February 8, 2012 (the “Closing”).

During January 2012, shareholders holding a majority of the Company’s outstanding shares of common stock approved the issuance of the Shares, the 8% Note and the Warrants pursuant to the terms of the Purchase Agreement. Additionally, the Board of Directors approved, effective upon the Closing (i) the amendment of the Company’s certificate of incorporation to (A) increase the Company’s authorized shares of common stock from 100,000,000 shares to 1,010,000,000 shares, both of which are before the one-for-three reverse stock split; (B) a one-for-three reverse stock split of the Company’s common stock (which reduced the Company’s authorized shares of common stock from 1,010,000,000 to 336,666,666 shares); and (C) a name change from RAM Energy Resources, Inc. to Halcón Resources Corporation; (ii) the amendment of the Company’s 2006 Long-Term Incentive Plan (the “Plan”) to increase the number of shares that may be issued under the Plan from 2,466,666 to 3,700,000 shares; and (iii) on an advisory (non-binding) basis, the payments made to the Company’s named executive officers in connection with the transactions contemplated by the Purchase Agreement.

The Closing of the transaction resulted in a change in control of the Company. Material events and items resulting from the transaction include the following:

· completion of transactions contemplated by the Purchase Agreement and shareholder approval as discussed above;

· the resignation and termination of the Company’s four executive officers and the resignation of certain other officers;

· change in control payments of $4.6 million to the officers of the Company recorded in general and administrative expense;

· change in control payment of $0.8 million pursuant to a retainer agreement with the Company’s outside law firm recorded in general and administrative expense;

· accelerated vesting of all unvested employee restricted stock shares and accelerated vesting and exercise of all unvested stock appreciation rights resulting in $4.3 million of share-based compensation expense recorded in general and administrative expense;

· payoff and termination of the Company’s revolving credit facility of $133.0 million plus accrued interest, as well as the expensing of the related unamortized debt issue costs of $2.9 million;

· payoff and termination of the Company’s second lien term facility of $75.0 million plus accrued interest and a prepayment fee of $1.5 million, as well as the expensing of the related unamortized debt issue costs of $2.9 million; and

· closing costs of $11.2 million related to engagement fees and various professional fees including $2.5 million recorded in general and administrative expense related to a termination fee pursuant to a previous engagement.

During January 2012, the Company approved a one-for-three reverse stock split, which was implemented on February 10, 2012. Retroactive application of the reverse stock split is required and all share and per share information included for all periods presented in these financial statements reflects the reverse stock split.

During February 2012, the transaction with HALRES LLC resulted in an “ownership change” as defined under Section 382 of the Internal Revenue Code. As a consequence, the Company will have additional limitations on its ability to use the net operating losses it accrued before the change-in-control as a deduction against any taxable income the Company realizes after the change-in-control.

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3. RESTRUCTURING

During March 2012, the Company announced its intention to close the Plano, Texas office and begin the process of relocating key administrative functions to Houston, Texas (the “Restructuring”). As part of the Restructuring, the Company offered certain severance and retention benefits (collectively, the “Severance Program”) to the affected employees. The estimated total expense of the Severance Program is approximately $3.2 million and related costs will be recognized as restructuring expense over the requisite service periods through May 2013, as applicable. The Company recorded a restructuring liability of $0.1 million as of March 31, 2012. During the three months ended June 30, 2012, the Company increased the restructuring liability by an additional $0.9 million to reflect the accrual of expense over the requisite period and decreased the liability by $0.2 million for actual expenditures, resulting in a liability of $0.8 million at June 30, 2012.

4. ACQUISITIONS

Unevaluated Properties

On June 28, 2012, the Company completed the acquisition of acreage in Eastern Ohio, prospective for the Utica/Point Pleasant formations. Pursuant to the terms of an Agreement of Sale and Purchase dated May 8, 2012 with NCL Appalachian Partners, L.P. (“NCL”), the Company acquired a working interest in approximately 27,000 net acres for an adjusted purchase price of approximately $164.0 million. The Company funded the acquisition with cash on hand. No oil or natural gas production or proved reserves are currently attributable to the acquired assets.

In addition to the NCL acquisition, during 2012 the Company incurred approximately $274.5 million in capital expenditures on unevaluated oil and gas leaseholds through numerous leasing and acquisition transactions. No oil or natural gas production or proved reserves are currently attributable to the leasehold assets which were primarily located in Texas, Louisiana, Ohio and Pennsylvania.

Other Acquisitions and Merger

See Note 15, “Subsequent Events — Acquisitions” for discussion of the recently closed acquisition of producing and nonproducing acreage in east Texas (the “East Texas Assets”) and the GeoResources, Inc. (“GeoResources”) merger.

5. OIL AND NATURAL GAS PROPERTIES

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

The Company assesses all items 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 an 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 amortization.

Investments in unevaluated oil and 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 our condensed consolidated balance sheet. 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 and six months ended June 30, 2012, the Company capitalized interest costs of $3.3 million and $3.4 million, respectively.

At June 30, 2012 the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended June 30, 2012 of the West Texas Intermediate (“WTI”) spot price of $95.67 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 June 30, 2012 of the Henry Hub price of $3.15 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 June 30, 2012, did not exceed the ceiling amount. Changes in production rates, levels of reserves, future development costs, and other factors will determine the Company’s actual ceiling test calculation and impairment analyses in future periods.

At June 30, 2011 the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended June 30, 2011 of the WTI posted price of $90.09 per barrel, adjusted by lease or field for quality,

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transportation fees, and regional price differentials, and the first day average of the 12-months ended June 30, 2011 of the Henry Hub price of $4.21 per Mmbtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2011, did not exceed the ceiling amount.

6. LONG-TERM DEBT

Long-term debt as of June 30, 2012 and December 31, 2011 consisted of the following (in thousands):

	June 30,		December 31,
	2012		2011
8% senior convertible note (1)	$	242,579	$	—
Revolving credit facility	—		127,000
Term loan facility	—		75,000
	$	242,579	$	202,000

(1) Amount is net of a $41.3 million unamortized discount at June 30, 2012. See “8% Senior Convertible Note” below for more details.

8% Senior Convertible Note

On February 8, 2012, the Company issued a $275.0 million principal amount 8% Note together with Warrants for an aggregate purchase price of $275.0 million. The 8% 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. Through the March 31, 2014 interest payment date, the Company may elect to borrow and add to principal of the 8% Note, all or any portion of the interest due on the 8% Note. At June 30, 2012 and March 31, 2012, the Company elected to pay in-kind $5.7 and $3.2 million, respectively, of interest incurred during the first six months of 2012 by increasing the 8% Note. The 8% Note matures on February 8, 2017. At any time after February 8, 2014, the noteholder may elect to convert all or any portion of the principal amount and accrued but unpaid interest into common stock. Each $4.50 of principal and accrued but unpaid interest is convertible into one share of the Company’s common stock. The 8% Note is a senior unsecured obligation of the Company and ranks equally with all of its future senior unsubordinated indebtedness.

The Company allocated the proceeds received for the 8% Note and 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 8% Note utilizing the effective interest rate method. The remaining unamortized discount was $41.3 million at June 30, 2012.

Senior Unsecured Notes

See Note 15, “Subsequent Events — 9.75% Senior Notes” for discussion on debt issuance subsequent to June 30, 2012.

February 2012 Credit Facility

On February 8, 2012, the Company entered into a $500.0 million, five-year, senior secured revolving credit agreement with JPMorgan Chase Bank, N.A. (“JPMorgan”) as the administrative agent and lead arranger, which replaces the Company’s March 2011 credit facility. The agreement increased the revolving borrowing base to $225.0 million and matures on February 8, 2017. The borrowing base will be redetermined semi-annually, with the Company and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. 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 revolving credit agreement may be paid down and re-borrowed during the five-year term of the revolver. The pricing on the agreement is LIBOR plus a margin ranging from 1.5% to 2.5% based on a percentage of usage. Advances under the revolving credit agreement are secured by liens on substantially all properties and assets of the Company and its subsidiaries. The revolving credit agreement contains representations, warranties and covenants customary in transactions of this nature including restrictions on the payment of dividends on the Company’s capital stock and financial covenants relating to current ratio and minimum interest coverage ratio. The Company maintains commodity hedges of not more than 100% of its projected production for the first 24 months, 75% of its projected production for the next 25 to 36 months and 50% of projected production for the next 37 to 48 months. At June 30, 2012, the Company is in compliance with the financial debt covenants under this agreement. At June 30, 2012, the Company had no indebtedness outstanding under the $500.0 million senior revolving credit agreement, $1.3 million of letters of credit outstanding and $223.7 million of borrowing

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capacity available. See Note 15, “Subsequent Events — Credit Facility Amendment” for discussion on the amendment of the February 2012 credit facility subsequent to June 30, 2012.

March 2011 Credit Facilities

The Company’s March 2011 facilities included a $250.0 million first lien revolving credit facility and a $75.0 million second lien term loan facility, replacing the November 2007 facility. SunTrust Bank was the administrative agent for the revolving facility, and Guggenheim Corporate Funding, LLC was the administrative agent for the term loan facility. The initial borrowing base under the revolving credit facility was $150.0 million. This revolving credit facility allowed for funds advanced to be paid down and re-borrowed during the five-year term of the revolver, and bore interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The term loan credit facility provided for payments of interest only during its 5.5-year term, with the interest rate being LIBOR plus 9.0% with a 2.0% LIBOR floor, or if any period the Company elected to pay a portion of the interest under its term loan “in kind”, then the interest rate would have been LIBOR plus 10.0% with a 2.0% LIBOR floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid in kind by being added to principal. At December 31, 2011, $127.0 million was outstanding under the revolving credit facility and $75.0 million was outstanding under the term loan credit facility. On February 8, 2012, the Company paid in full the outstanding balances under the revolving credit facility and the term loan facility and both facilities were terminated, with a resulting $1.5 million charge to interest expense related to an early termination penalty.

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 quarter of 2012, the Company capitalized approximately $3.3 million and $2.0 million in costs associated with the issuance of the 8% Note and February 2012 credit facility, respectively. During February 2012, the Company expensed $5.8 million of debt issuance costs as a result of the pay off and termination of the March 2011 revolving credit and term loan facilities. The Company expensed the remaining debt issuance cost associated with the November 2007 facility totaling approximately $2.7 million in the first quarter 2011. At June 30, 2012 and December 31, 2011, the Company had approximately $5.5 million and $6.0 million, respectively, of unamortized debt issuance costs. See Note 15, “Subsequent Events — 9.75% Senior Notes” for discussion of the debt issuance costs related to the issuance of the 9.75% senior unsecured notes.

7. INCOME TAXES

Under guidance contained in Topic 740 of the Accounting Standard Codification TM (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.

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. During the three and six months ended June 30, 2012 and 2011, the Company analyzed and made no adjustment to the valuation allowance.

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The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before provision for income taxes. The significant differences between pre-tax book income and taxable book income relate to non-deductible expenses, state income taxes, change in valuation allowances, Section 382 net operating loss limitations and other adjustments to deferred tax balances. The sources and tax rates of the differences for the six months ended June 30 are as follows:

	2012		2011
Income tax at the federal statutory rate	34.0	%	34.0	%

State income tax benefit (expense), net of federal benefit	(0.7	)	20.0
Non-deductible dues and entertainment	(0.3	)	8.5
Non-deductible interest and expense on Note	(18.7	)	—
Reduction in deferred tax asset	(5.2	)	—
Share-based compensation	(0.4	)	2.8
Non-deductible compensation	(4.3	)	—
Non-deductible basis in other operating property and equipment	(0.9	)	—
Merger costs	(4.3	)	—
	(0.8	)%	65.3	%

The Company has calculated an estimated effective annual tax rate for the current annual reporting period, excluding any discrete items, of 4.4% as of June 30, 2012. Additionally, the Company recorded a discrete item of $1.3 million related to the reduction in net operating losses due to additional limitations created by a change in control prior to the recapitalization of the Company in February 2012. The recapitalization created an “ownership change” and as a result the net operating losses of the Company will be subject to additional limitations. The discrete item of $1.3 million decreases the effective tax rate to a negative tax rate of 0.8%. The estimated annual effective tax rate differs from the statutory rate primarily due to non-deductible interest expense on the 8% Note issued as part of the recapitalization of the Company. Based on the estimated effective annual tax rate, the Company has recorded a tax provision of $0.2 million on a pre-tax loss of $25.5 million for the six months ended June 30, 2012. For the six months ended June 30, 2011, the Company recorded income tax benefit of $1.8 million on a pre-tax loss of $2.8 million, resulting in an effective tax rate of 65.3%.

For the six months ended June 30, 2012 the Company has net operating losses of $56.4 million that are not expected to be limited due to the limitations created by the “ownership change” on February 8, 2012.

8. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820, Fair Value Measurements and Disclosures (“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.

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The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of June 30, 2012 and December 31, 2011 (in thousands). 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 six months ended June 30, 2012 and for the year ended December 31, 2011.

	June 30, 2012
	Level 1		Level 2		Level 3		Total
Assets:
Receivables from derivative contracts	$	—	$	7,226	$	—	$	7,226
Liabilities:
Liabilities from derivative contracts	$	—	$	—	$	—	$	—

	December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Receivables from derivative contracts	$	—	$	260	$	—	$	260
Liabilities:
Liabilities from derivative contracts	$	—	$	1,070	$	—	$	1,070

Derivatives listed above consist of put/call “collars” and sold put options on crude oil and natural gas and interest rate swaps that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” 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.

As of June 30, 2012 and December 31, 2011, 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 discussed above; however, the Company does not anticipate such nonperformance. The counterparty to the Company’s current derivative contracts is a lender in the Company’s senior revolving credit agreement. The Company did not post current collateral under any of these contracts as they are secured under the senior revolving 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 revolving credit agreement approximates carrying value because the facility’s interest rate approximates current market rates. The estimated fair value of the Company’s fixed interest rate 8% Note as of June 30, 2012, is $773.1 million and exceeded the carrying value of $242.6 million by $530.5 million. The fair value of the 8% Note at June 30, 2012 was calculated using Level 2 criteria.

9. ASSET RETIREMENT OBLIGATIONS

For wells drilled, the Company records an asset retirement obligation (“ARO”) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” 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.

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The Company recorded the following activity related to its ARO liability for the six months ended June 30, 2012 (in thousands):

Liability for asset retirement obligations as of December 31, 2011	$	33,713
Liabilities settled	(68		)
Additions	60
Accretion expense	829
Liability for asset retirement obligations as of June 30, 2012	34,534
Less: current asset retirement obligations	1,446
Long-term asset retirement obligations	$	33,088

10. COMMITMENTS AND CONTINGENCIES

Commitments

The Company leases corporate office space in Houston and Plano, Texas and Tulsa, Oklahoma as well as a number of other field office locations. In addition, the Company has lease commitments for certain equipment under long-term operating lease agreements. The office and equipment operating lease agreements expire on various dates through 2020. Rent expense was approximately $1.2 million and $0.7 million for the six months ended June 30, 2012 and 2011, respectively. Approximate future minimum lease payments for the remainder of 2012 and subsequent annual periods for all non-cancelable operating leases at June 30, 2012 are as follows (in thousands):

2012	$	2,337
2013	5,706
2014	4,766
2015	4,779
2016 and thereafter	23,062
	$	40,650

Contingencies

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

11. DERIVATIVES

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, natural gas and natural gas liquids production. The Company generally hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. Currently the Company has hedges in place for periods through June 2014. During 2010, 2011 and 2012, the Company entered into numerous derivative contracts and did not designate these transactions as hedges for accounting purposes. 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.

During February 2012, pursuant to the February 2012 senior secured revolving credit agreement, the Company novated its oil and natural gas derivative instruments to counterparties that are lenders within the new senior secured revolving credit agreement resulting in a realized loss of $0.4 million for novation fees and terminated the interest rate derivatives resulting in a $0.6 million realized loss.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The counterparty to the Company’s current

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derivative contracts is a lender in the Company’s senior revolving credit agreement. The Company did not post collateral under any of these contracts as they are secured under the Company’s senior secured revolving credit agreement.

The Company’s crude oil and natural gas derivative positions at June 30, 2012 consist of put/call “collars” and sold put options. A 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. 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. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011 (in thousands):

		Asset derivative contracts				Liability derivative contracts						Netted derivative contracts
Derivatives not designated as hedging contracts	Balance sheet location	June 30, 2012		December 31, 2011		June 30, 2012			December 31, 2011			June 30, 2012		December 31, 2011
Commodity contracts	Current assets - receivables from derivative contracts	$	4,915	$	1,850	$	(408	)	$	(1,590	)	$	4,507	$	260
Commodity contracts	Other noncurrent assets - receivables from derivative contracts	3,207		—		(488		)	—			2,719		—
Commodity contracts	Other noncurrent liabilities - liabilities from derivative contracts	—		2,050		—			(2,602		)	—		(552		)
Interest rate swaps	Current liabilities - liabilities from derivative contracts	—		—		—			(265		)	—		(265		)
Interest rate swaps	Other noncurrent liabilities - liabilities from derivative contracts	—		—		—			(253		)	—		(253		)
Total derivatives not designated as hedging contracts		$	8,122	$	3,900	$	(896	)	$	(4,710	)	$	7,226	$	(810	)

The types of derivative contracts and related realized and unrealized gains and losses illustrated in the following table are located in “Other income (expenses) — Net gain (loss) on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations (in thousands):

	Amount of gain (loss) recognized on derivative contracts for the:
	Three months ended June 30,					Six months ended June 30,
Derivatives not designated as hedging contracts	2012		2011			2012			2011
Unrealized gain (loss) on commodity contracts	$	12,638	$	10,728		$	7,176		$	(4,225	)
Realized gain (loss) on commodity contracts	1,033		(2,098		)	1,608			(1,262		)
Unrealized gain (loss) on interest rate swaps	—		(296		)	518			(418		)
Realized gain (loss) on interest rate swaps	—		(66		)	(576		)	(77		)
Total net gain (loss) on derivative contracts	$	13,671	$	8,268		$	8,726		$	(5,982	)

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At June 30, 2012, the Company had the following open derivative contracts:

			June 30, 2012
				Floors			Ceilings			Put Options Sold
					Weighted			Weighted				Weighted
			Volume in	Price/Price	Average		Price/Price	Average		Price/Price		Average
Period	Instrument	Commodity	Mmbtu’s/Bbl’s	Range	Price		Range	Price		Range		Price
July 2012 - December 2012	3 Way-collars	Crude oil	218,500	$90.00 - $100.00	$	93.11	$101.70 - $113.25	$	104.81	$	70.00	$	70.00
July 2012 - December 2012	Collars	Crude oil	117,300	90.00 - 95.00	91.08		102.40 - 107.00	106.11
July 2012 - September 2012	Collars	Natural gas	460,000	4.00	4.00		6.00	6.00
January 2013 - June 2013	3 Way-collars	Crude oil	251,075	95.00 - 100.00	95.18		99.50 - 109.50	100.60		70.00		70.00
January 2013 - December 2013	Collars	Crude oil	1,080,875	80.00 - 95.00	84.87		92.70 - 101.50	95.08
January 2014 - June 2014	3 Way-collars	Crude oil	280,500	95.00	95.00		98.20 - 109.50	99.59		70.00		70.00

At December 31, 2011, the Company had the following open derivative contracts (including interest rate swaps):

			December 31, 2011
				Floors			Ceilings			Put Options Sold
					Weighted			Weighted				Weighted
			Volume in	Price/Price	Average		Price/Price	Average		Price/Price		Average
Period	Instrument	Commodity	Mmbtu’s/Bbl’s	Range	Price		Range	Price		Range		Price
January 2012 - December 2012	3 Way-collars	Crude oil	400,500	$80.00 - $100.00	$	87.15	$101.70 - $113.25	$	104.89	$	70.00	$	70.00
January 2012 - December 2012	Collars	Crude oil	299,300	80.00 - 95.00	84.34		102.40 - 107.00	105.43
January 2012 - March 2012	Put options	Natural gas	609,700	4.00 - 4.50	4.35
April 2012 - September 2012	Collars	Natural gas	915,000	4.00	4.00		6.00	6.00
January 2013 - June 2013	3 Way-collars	Crude oil	251,075	95.00 - 100.00	95.18		99.50 - 109.50	100.60		70.00		70.00
January 2013 - December 2013	Collars	Crude oil	350,875	95.00	95.00		99.00 - 101.50	100.04
January 2014 - June 2014	3 Way-collars	Crude oil	280,500	95.00	95.00		98.20 - 109.50	99.59		70.00		70.00

Interest Rate Swaps (1) (3)
Year	Notional Amount (in thousands)		Fixed Rate		Counterparty Floating Rate (2)	Months Covered
2013	$	50,000	2.51	%	3—Month LIBOR	January — December
2014	$	50,000	2.51	%	3—Month LIBOR	January — March

(1) Settlement is paid to the Company if the counterparty floating rate exceeds the fixed rate and settlement is paid by the Company if the counterparty floating rate is below the fixed rate. Settlement is calculated as the difference in the fixed rate and the counterparty rate.

(2) Subject to a minimum rate of 2%.

(3) All outstanding interest rate swaps were terminated in connection with the recapitalization during February 2012.

12. STOCKHOLDERS’ EQUITY

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 stock options and restricted stock, to be recognized in the financial statements based on their fair values.

On May 8, 2006, the Company’s stockholders first approved its 2006 Long-Term Incentive Plan (as amended, the “Plan”). The Company reserved a maximum of 800,000 shares of its common stock for issuances under the Plan. On May 8, 2008, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 800,000 to 2,000,000. On May 3, 2010, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 2,000,000 to 2,466,666. On February 8, 2012, as part of the recapitalization described in Note 2, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 2,466,666 to 3,700,000. On May 17, 2012, shareholders approved an amendment and restatement of the Plan to (i) increase the maximum number of shares to be issued under the Plan from 3,700,000 to 11,500,000; (ii) extend the effectiveness of the Plan for ten years from the date of approval; and (iii) amend various other provisions of the Plan. As of June 30, 2012 and December 31, 2011, a maximum of 8,046,719 and 491,450 shares of common stock, respectively remained reserved for issuance under the Plan.

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Stock Options

During the six months ended June 30, 2012, the Company granted stock options under the Plan covering 1,272,833 shares of common stock to employees of the Company. The stock options have exercise prices ranging from $8.73 to $11.55 with a weighted average exercise price of $10.11. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. During the three and six months ended June 30, 2012, $0.4 million and $0.5 million, respectively, was recognized as compensation expense as a component of general and administrative expense. At June 30, 2012, the unrecognized compensation expense related to stock options totaled $4.8 million and will be recognized on the graded-vesting method over the requisite service periods.

Stock Appreciation Rights

During February 2012, the Company accelerated vesting and exercise of all unvested stock appreciation rights under the Plan (“SARs”) that were granted in May 2011, due to the change in control of the Company resulting from the recapitalization described in Note 2. The Company settled the SARs in cash, resulting in $2.2 million of share-based compensation expense recognized for the six months ended June 30, 2012. The realized compensation expense was partially offset by the reversal of $0.8 million of unrealized losses recorded at December 31, 2011.

Restricted Stock

During the six months ended June 30, 2012, the Company granted 204,000 shares of restricted stock under the Plan to directors and employees of the Company. During the three and six months ended June 30, 2012, the Company realized compensation expense of $0.1 million related to the restricted stock issued in 2012. At June 30, 2012, the Company had $2.0 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of two years. Additionally, during the six months ended June 30, 2012, the Company realized compensation expense of $2.6 million primarily from the accelerated vesting of all unvested employee restricted stock shares due to the change in control in the Company resulting from the recapitalization as described in Note 2.

At June 30, 2011, the Company had $4.8 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of two years. The related compensation expense recognized during the three and six months ended June 30, 2011 was $0.8 million and $1.6 million, respectively. During the three and six months ended June 30, 2011, the Company recorded $0.7 million and $1.4 million, respectively, as compensation expense and $0.1 million and $0.2 million, respectively, as capitalized internal costs.

Warrants

During February 2012, the Company issued for proceeds of $43.6 million, five year Warrants to purchase 36,666,666 shares of the Company’s common stock at an exercise price of $4.50 per share pursuant to the recapitalization described in Note 2. Proceeds are reflected in additional paid-in capital in stockholders’ equity, net of $0.6 million in issuance costs. The 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.

Common Stock

On February 8, 2012 pursuant to the closing of the recapitalization described in Note 2, the Company issued 73,333,333 shares of the Company’s common stock for a purchase price of $275.0 million. Costs incurred of $4.0 million were netted against the proceeds of the common stock and recorded accordingly. In addition, the Company amended its certificate of incorporation to increase the Company’s authorized shares of common stock from 33,333,333 shares to 336,666,666 shares.

Preferred Stock and Non-Cash Preferred Stock Dividend

On February 29, 2012 (the “Commitment Date”), the Company entered into definitive agreements with a group of certain institutional and selected other accredited investors (collectively, the “investors”) to sell, in a private offering, 4,444.4511 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the “Preferred Stock”), each share of which was convertible into 10,000 shares of common stock. Also on February, 29, 2012, the Company received an executed written consent (the “Consent”) in lieu of stockholders’ meeting authorizing and approving the conversion of the Preferred Stock into common stock. On March 2, 2012, the Company filed a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the “Certificate of Designation”) with the Delaware Secretary of State which stated the

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conversion was to occur on the twentieth day after the mailing of a definitive information statement to stockholders. On March 5, 2012, the Company issued the Preferred Stock to the investors at $90,000 per share. Gross proceeds from the offering were approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. The Company incurred placement agent fees of $14.0 million and associated expenses of approximately $0.5 million in connection with this offering. On March 28, 2012, the Company mailed a definitive information statement to its common stockholders notifying them that Halcón’s majority stockholder had consented to the issuance of common stock, par value $0.0001, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 44,444,511 shares of common stock on April 17, 2012 in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to May 31, 2012.

The Preferred Stock conversion feature was not considered a derivative instrument under ASC Topic 815— Derivatives and Hedging as it met the scope exception because the conversion feature is both indexed to the Company’s own stock and classified in stockholders’ equity in the Company’s balance sheet. However, in accordance with ASC 470 - Debt (“ASC 470”), the Company determined that the conversion feature in the Preferred Stock did represent a beneficial conversion feature. The fair value of the common stock of $10.99 on the Commitment Date was greater than the conversion price of $9.00 per common share, representing a beneficial conversion feature of $1.99 per common share, or $88.4 million in aggregate. Under ASC 470, $88.4 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to additional paid-in capital, creating a discount on the Preferred Stock (the “Discount”). The Discount resulting from the allocation of value to the beneficial conversion feature was required to be amortized on a non-cash basis over the approximate 71 month period between the issuance date and the required redemption date of February 9, 2018, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. As a result, approximately $1.1 million of the Discount was amortized in the first quarter of 2012 and due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of Discount amortization was accelerated to the conversion date and was fully amortized in the second quarter of 2012 as per the guidance of ASC 470. The Discount amortization is reflected as a non-cash preferred dividend in the Condensed Consolidated Statement of Operations. In accordance with the guidance in ASC 480, the preferred dividend was charged against additional paid-in capital since no retained earnings were available.

13. EARNINGS PER COMMON SHARE

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

	Three months ended June 30,					Six months ended June 30,
	2012			2011		2012			2011
Basic
Net income (loss) available to common stockholders	$	(79,684	)	$	8,936	$	(114,108	)	$	(975	)
Weighted average basic number of common shares outstanding	136,066			26,278		102,441			26,199
Basic net income (loss) per common share	$	(0.59	)	$	0.34	$	(1.11	)	$	(0.04	)
Diluted
Net income (loss) available to common stockholders	$	(79,684	)	$	8,936	$	(114,108	)	$	(975	)
Weighted average basic number of common shares outstanding	136,066			26,278		102,441			26,199
Common stock equivalent shares representing shares issued upon exercise or conversion	Anti-dilutive			—		Anti-dilutive			—
Weighted average diluted number of common shares outstanding	136,066			26,278		102,441			26,199
Diluted income (loss) per common share	$	(0.59	)	$	0.34	$	(1.11	)	$	(0.04	)

Common stock equivalents of stock options, Preferred Stock, Warrants and the 8% Note totaling 89.4 million and 75.4 million shares were not included in the computations of diluted earnings per share of common stock for the three and six months ended June 30, 2012, respectively, as the effect would have been anti-dilutive due to the net loss.

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14. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

	June 30,		December 31,
	2012		2011
Accounts receivable:
Oil and natural gas revenues	$	7,281	$	9,519
Joint interest accounts	1,700		597
Other	359		172
	$	9,340	$	10,288
Prepaids and other:
Prepaid expenses	$	2,502	$	936
Other	11		1,793
	$	2,513	$	2,729
Accounts payable and accrued liabilities:
Trade payables	$	19,004	$	12,890
Revenues and royalties payable	8,053		8,564
Accrued interest expense	216		464
Accrued income taxes payable	279		406
Accrued employee compensation	6,712		1,600
Other	2,510		1,137
	$	36,774	$	25,061

	Three months ended June 30,					Six months ended June 30,
	2012			2011		2012			2011
General and administrative:
Share-based compensation	$	529		$	686	$	4,632		$	1,355
General and administrative, overhead and other	12,558			3,935		28,789			7,813
	$	13,087		$	4,621	$	33,421		$	9,168
Depletion, depreciation and accretion:
Depletion and amortization	$	5,528		$	5,196	$	11,106		$	10,469
Accretion	428			412		829			814
	$	5,956		$	5,608	$	11,935		$	11,283
Interest expense and other, net:
Interest expense	$	4,192		$	3,563	$	17,230		$	10,113
Other expense (income)	(13		)	798		(54		)	750
	$	4,179		$	4,361	$	17,176		$	10,863

15. SUBSEQUENT EVENTS

Acquisitions

On July 31, 2012, the stockholders of the Company and GeoResources, a Colorado corporation approved the merger of GeoResources into a subsidiary of the Company. The closing of the transaction occurred on August 1, 2012 and GeoResources’ stockholders received a combination of $20 in cash and 1.932 shares of the Company’s common stock for each share of GeoResources’ common stock. The cash consideration aggregated approximately $525.0 million and the Company issued approximately 51.0 million shares of the Company’s common stock to the stockholders of GeoResources. In addition, the Company assumed outstanding warrants of GeoResources providing for the issuance of 1,184,966 shares of common stock of the Company upon exercise.

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supplemental disclosures regarding the merger and to provide additional disclosures to their stockholders, which disclosures were included in a Form 8-K filed with the U.S. Securities and Exchange Commission on July 18, 2012. Objections to the settlement agreement are scheduled to be submitted on August 15, 2012 to the federal court in Colorado and a hearing on the settlement agreement is expected to be scheduled at a later date.

In early August 2012, the Company completed the acquisition of an operated interest in approximately 20,000 net acres of oil and gas leasehold in east Texas from several private oil and gas companies. The properties, which the Company refers to as the East Texas Assets, consist of producing and nonproducing acreage. The purchase consideration consisted of approximately 20.7 million shares of the Company’s common stock and approximately $300.0 million in cash.

The purchase of both GeoResources and the East Texas Assets will be accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the Company is required to allocate the purchase price to tangible and identifiable intangible assets acquired and liabilities assumed based on their fair values at the respective Closing Dates. The excess of the purchase price over those fair values is recorded as goodwill. The Company is in the process of valuing the assets acquired and liabilities assumed. Disclosures required by ASC 805, Business Combinations, will be provided once the initial accounting for the merger is complete.

9.75% Senior Notes

On July 16, 2012, the Company completed a private offering of $750.0 million aggregate principal amount of 9.75% senior unsecured notes due 2020 (the “9.75% Notes”), issued at 98.646% of par. The net proceeds from the offering approximated $724.8 million after deducting the initial purchasers’ discounts, commissions and offering expenses and were used to fund the cash consideration portion of the GeoResources merger and a portion of the cash component of the East Texas Assets acquisition.

In connection with the issuance of the 9.75% Notes, approximately $15.5 million will be recorded as debt issuance costs and $10.2 million as a discount. The debt amortization costs and the discount will be amortized over the life of the 9.75% Notes using the effective interest method.

Credit Facility Amendment

The Company requested, and was granted, a redetermination of the aggregate amount and borrowing base of the February 2012 credit facility in anticipation of, and contingent upon, the successful completion of the GeoResources and East Texas Assets acquisitions. On August 1, 2012, in connection with the closing of the GeoResources and East Texas Assets transactions, the Company entered into the First Amendment to the senior revolving credit agreement (the “First Amendment”). The First Amendment increased the commitments under the revolving credit facility to an aggregate amount up to $1.5 billion and the borrowing base from $225.0 million to $525.0 million. The First Amendment also modified the requirements for commodity hedging to not more than 85% of production for 66 months from the date of the commodity hedging agreement.

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

The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 2012 and 2011 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis included in our Annual Report on Form 10-K for the year ended December 31, 2011.

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.

Overview

We are an independent energy company engaged in the acquisition, production, exploration and development of onshore oil and natural gas properties in the United States. Our producing properties are located in basins with long histories of oil and natural gas operations.

Our oil and natural gas assets consist of a combination of developing and mature liquids-weighted reserves and properties. We have mature oil and natural gas reserves located primarily in Wichita, Wilbarger and Starr Counties, Texas, Pontotoc County, Oklahoma, and in several parishes in Louisiana. We have acquired acreage and may acquire more acreage in the Utica Shale/Point Pleasant formations in Ohio and Pennsylvania, the Woodbine/Eagle Ford formations in Texas, the Tuscaloosa Marine Shale formation in Louisiana, the Wilcox formation in Texas and Louisiana and the Mississippi Lime formation in Oklahoma, as well as several other undisclosed locations.

Our average daily oil and natural gas production decreased 6% in the first six months of 2012 compared to the same period in the prior year. During the first six months of 2012, we averaged 3,984 barrels of oil equivalent (“Boe”) per day compared to average daily production of 4,238 Boe per day during the first six months of 2011. The decrease in production compared to the prior year period was driven primarily by natural production declines and pipeline operational issues in South Texas. During the first six months of 2012, we drilled or participated in the drilling of 15 gross (14.2 net) wells of which 14 gross (13.3 net) wells were completed as wells capable of production and one gross (0.9 net) well was a dry hole, resulting in a success rate of 93%.

Recent Acquisitions

Merger with GeoResources, Inc.

On August 1, 2012, we acquired GeoResources, Inc., by merger. As consideration, we paid a combination of $20 in cash and issued 1.932 shares of the Company’s common stock for each share of GeoResources’ common stock that was issued and outstanding on the closing date and also assumed GeoResources’ outstanding warrants. GeoResources’ oil and natural gas properties include acreage in the Bakken shale and Three Forks formations in North Dakota and Montana, and the Austin Chalk trend and Eagle Ford shale in Texas. As of January 1, 2012, GeoResources reported estimated proved reserves of approximately 29.2 million barrels of oil equivalent (“MMBoe”), of which approximately 67% was oil and 70% was developed. GeoResources’ production for the year ended December 31, 2011 was 1.9 MMBoe. Prior to the merger, we and GeoResources operated as separate companies. Accordingly, the discussion and analysis of results of operations and financial condition set forth below relate solely to us. GeoResources’ results of operations will be reflected in the Company’s results from and after August 1, 2012. Additional details regarding the merger are discussed in Note 15 to the Condensed Consolidated Financial Statements, “Subsequent Events - Acquisitions.”

East Texas Assets Acquisition

In early August 2012, the Company acquired an operated interest in approximately 20,000 net acres of oil and gas leasehold in east Texas from several private oil and gas companies for cash of approximately $300.0 million and 20.7 million shares of the Company’s common stock. The properties, which the Company refers to as the East Texas Assets, consist of producing and nonproducing acreage prospective for the Woodbine, Eagle Ford and other formations. Net daily production from the acreage was approximately 2,800 Boe per day as of June 1, 2012.

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Acquisition of Unevaluated Acreage

On June 28, 2012, we completed the acquisition of acreage in Eastern Ohio that we believe is prospective for the Utica Shale/Point Pleasant formations. Pursuant to the terms of an Agreement of Sale and Purchase dated May 8, 2012 with NCL Appalachian Partners, L.P. (“NCL”), we acquired a working interest in approximately 27,000 net acres for an adjusted purchase price of approximately $164.0 million. We funded the acquisition with cash on hand. No oil or natural gas production or proved reserves are currently attributable to the acquired assets. The effective date of the transaction is June 1, 2012.

In addition to the NCL acquisition, during the first six months of 2012 we incurred approximately $274.5 million in capital expenditures on unevaluated oil and gas leaseholds through numerous leasing and acquisition transactions. No oil or natural gas production or proved reserves are currently attributable to the leasehold assets which were primarily located in Texas, Louisiana, Ohio and Pennsylvania.

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

Other Recent Developments

Recapitalization

On February 8, 2012, HALRES LLC (formerly, Halcón Resources, LLC), a newly-formed limited liability company led by Floyd C. Wilson, former Chairman and Chief Executive Officer of Petrohawk Energy Corporation, recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8% convertible note and warrants for the purchase of an additional 36,666,666 million shares of our common stock at an exercise price of $4.50 per share. Information as to our recapitalization is set forth under Note 2 to the Condensed Consolidated Financial Statements.

February 2012 Credit Facility

In connection with the closing of the recapitalization, we entered into a senior revolving credit agreement (the “February 2012 Credit Agreement”) with JPMorgan Chase Bank, N.A. (“JPMorgan”), as administrative agent, and other lenders on February 8, 2012. Initially, the February 2012 Credit Agreement provided for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the February 2012 Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and 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 we may issue. Funds advanced under the February 2012 Credit Agreement may be paid down and re-borrowed during the five-year term of the revolver. The initial pricing on the February 2012 Credit Agreement was LIBOR plus a margin ranging from 1.5% to 2.5% based on a percentage of usage. Advances under the February 2012 Credit Agreement are secured by liens on substantially all of our properties and assets. The February 2012 Credit Agreement contains representations, warranties and covenants customary in transactions of this nature including restrictions on the payment of dividends on the capital stock and financial covenants relating to current ratio and minimum interest coverage ratio. Initially, we were required to maintain commodity hedges on a monthly basis of not more than 100% of our projected production for the first 24 months, 75% of our projected production for the next 25 to 36 months and 50% of our projected production for the next 37 to 48 months. At June 30, 2012 and as of the date of this filing, we are in compliance with the financial debt covenants under the February 2012 Credit Agreement. At June 30, 2012, we had no indebtedness outstanding under the $500.0 million credit agreement, $1.3 million of letters of credit outstanding and $223.7 million of borrowing capacity available.

We requested, and were granted, a redetermination of the aggregate amount and borrowing base of the February 2012 Credit Agreement in anticipation of, and contingent upon, the successful completion of the GeoResources and East Texas Assets acquisitions, which in the aggregate are expected to increase our current Boe per day production volumes from approximately 4,000 Boe per day to 14,000 Boe per day. On August 1, 2012, in connection with the closing of the GeoResources, Inc. merger and East Texas Assets acquisition, we entered into the First Amendment to the February 2012 Credit Agreement (the “First Amendment”). The First Amendment increased the commitments under the revolving credit facility to an aggregate amount up to $1.5 billion and the borrowing base from $225.0 million to $525.0 million. The First

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Amendment also modified the requirements for commodity hedging to not more than 85% of our current and anticipated production for 66 months from the date such hedge agreement is created.

Preferred Stock Offering

On March 5, 2012, we sold in a private placement to certain institutional accredited investors 4,444.4511 shares of 8% automatically convertible preferred stock (“Preferred Stock”), par value $0.0001 per share, each share of which automatically converted into 10,000 shares of our common stock on April 17, 2012. We received gross proceeds of approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. No cash dividends were paid on the convertible Preferred Stock as it converted into common stock on or before May 31, 2012. The Preferred Stock was considered to have a beneficial conversion feature because the proceeds per share, approximately $9.00 per share of common stock, were less than the fair value of our common stock of $10.99 per common share on the commitment date. The estimated fair value allocated to the beneficial conversion feature was $88.4 million and was recorded to additional paid-in capital, creating a discount on the Preferred Stock (the “Discount”). The Discount resulting from the allocation of value to the beneficial conversion feature was required to be amortized over the 71 month contractual period from issuance to required redemption, or fully amortized upon an accelerated date of redemption or conversion, by increasing Preferred Stock and recording the offsetting amount as a deemed non-cash Preferred Stock dividend. During the three months ended March 31, 2012, we recorded a non-cash preferred dividend of $1.1 million. Due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of Discount amortization was accelerated to the conversion date and reflected as a non-cash preferred dividend for the three month period ended June 30, 2012.

9.75 % Senior Notes

On July 16, 2012, we completed a private offering of $750.0 million aggregate principal amount of 9.75% senior unsecured notes due 2020 (the “9.75% Notes”), issued at 98.646% of par. The net proceeds from the offering approximated $724.8 million after deducting the initial purchasers’ discounts, commissions and offering expenses and were used to fund the cash consideration portion of the GeoResources merger and a portion of the cash component of the East Texas Assets acquisition.

Capital Resources and Liquidity

The proceeds provided by our recent financing activities has enabled us to increase our focus on expanding our leasehold position in liquids-rich resource areas. In addition to the assets acquired through the merger with GeoResources, we have acquired and/or identified several target resource plays for additional leasing, including the Utica Shale/Point Pleasant formations in Ohio and Pennsylvania, the Mississippi Lime formation in Northern Oklahoma and Southern Kansas, the Wilcox formation in Southwest Louisiana, the Woodbine/Eagle Ford formations in East Texas and the Tuscaloosa Marine Shale formation in Louisiana. In addition to our ongoing lease acquisition efforts in our targeted resource plays, we have identified several new exploratory areas we believe are prospective for oil and liquids-rich hydrocarbons. We have made significant progress in all of our target resources style plays. For the six months ended June 30, 2012, we invested $453.2 million on unevaluated properties for oil and natural gas leaseholds, exploration activities and seismic. The majority of these expenditures were for acreage in the Utica Shale/Point Pleasant and, to a lesser extent, Woodbine/Eagle Ford formations.

Our near-term capital spending requirements are expected to be funded with cash flows from operations, proceeds from potential asset dispositions and borrowings under our February 2012 Credit Agreement, for which the borrowing base has been increased from $225.0 million to $525.0 million due to the completed GeoResources merger and the acquisition of the East Texas Assets. As of August 1, approximately $220.0 million was drawn on the borrowing base. We strive to maintain financial flexibility while continuing our aggressive 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 February 2012 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. If oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

Our 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.

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Cash Flow

Our primary source of cash for the six months ended June 30, 2012 was from financing activities. Our primary source of cash for the six months ended June 30, 2011 was from operating activities. Proceeds from our recent convertible Preferred Stock offering and recapitalization, as well as borrowings under our 8% convertible note, were partially offset by repayments of our previous credit facilities and cash used in investing activities to fund our unevaluated leasehold activities and our drilling program. Operating cash flow fluctuations were substantially driven by the increase in general and administrative expenses in the six months ended June 30, 2012 as a result of the recapitalization and related change in control matters. Prices for oil and natural gas have historically been subject to seasonal influences typically 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 revenues.

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

	Six Months Ended
	June 30,
	2012			2011
Cash flows provided by (used in) operating activities	$	(2,708	)	$	13,043
Cash flows used in investing activities	(500,809		)	(13,496		)
Cash flows provided by financing activities	722,676			870
Net increase in cash	$	219,159		$	417

Operating Activities. Net cash used in operating activities for the six months ended June 30, 2012 was $2.7 million as compared to cash provided by operating activities for the six months ended June 30, 2011 of $13.0 million.

Net loss for the six months ended June 30, 2012 was a $25.7 million. Non-cash items including depreciation, depletion and accretion of $11.9 million, $7.7 million of non-cash interest and amortization as well as $6.3 million of amortization and write-off of deferred loan costs offset this net loss. The recapitalization, change in control and related activities which occurred during February 2012, coupled with the impact of additional personnel and facilities in support of the rapidly expanding business base, drove a significant increase in general and administrative, which adversely affected operating cash flows.

Investing Activities. The primary driver of cash used in investing activities is capital spending, specifically the acquisition of unevaluated leaseholds in our targeted areas. Cash used in investing activities was $500.8 million and $13.5 million for the six months ended June 30, 2012 and 2011, respectively.

During the first six months of 2012, we spent $468.2 million on oil and natural gas capital expenditures, primarily on the acquisition of unevaluated leasehold. We participated in the drilling of 15 gross (14.2 net) wells of which 14 gross (13.3 net) wells were completed as wells capable of production and one gross (0.9 net) well was a dry hole, and spent an additional $3.5 million on other operating property and equipment capital expenditures, primarily on leasehold improvements, computers and software in our new corporate office in Houston, Texas. Proceeds from sales of oil and gas properties were $0.3 million. We also had funds held in escrow of approximately $29.4 million related to pending acquisitions.

During the first six months of 2011, we spent $13.5 million on oil and natural gas capital expenditures. During the six months ended June 30, 2011, we participated in the drilling of 30 gross (26.5 net) wells, of which 21 gross (19.2 net) wells were capable of production. Nine gross (7.3 net) wells were drilling, testing or waiting on completion as of June 30, 2011. We spent an additional $0.5 million on other operating property and equipment capital expenditures. Proceeds from sales of oil and gas properties were $0.5 million for the six months ended June 30, 2011.

Financing Activities. Net cash flows provided by financing activities were $722.7 million and $0.9 million for the six months ended June 30, 2012 and 2011, respectively.

On February 8, 2012, HALRES LLC recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8% convertible note and warrants for the purchase of an additional 36,666,666 million shares of our common stock at an exercise price of $4.50 per share. The convertible note provided $231.4 million cash flow from borrowings and $43.6 million cash flow from warrants issued.

In connection with the closing of the recapitalization, we entered into the February 2012 Credit Agreement. The February 2012 Credit Agreement provided for a $500.0 million facility with an initial borrowing base of $225.0 million until it was amended in connection with the closing of the GeoResources and East Texas Assets transactions to increase the facility up to

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$1.5 billion and borrowing base from $225.0 million to $525.0 million. Amounts borrowed under the February 2012 Credit Agreement will mature on February 8, 2017. We did not utilize any of the funds available under the credit facility during the first six months of 2012; however, we incurred $2.0 million of debt issuance costs in conjunction with the issuance of the February 2012 Credit Agreement, and $2.5 million of debt issuance costs in connection with the 8% Note. We also incurred approximately $0.6 million of debt issuance costs in connection with the private offering of the 9.75% Notes discussed under “Recent Developments — 9.75% Senior Notes” in Item 2.

On March 5, 2012, we received $400.0 million, subject to certain adjustments, from the private placement sale of the convertible Preferred Stock. See “Recent Developments — Preferred Stock Offering” in Item 2 for a more detailed discussion.

In connection with the closing of the recapitalization transactions and the Preferred Stock private placement, we incurred a total of $18.1 million in equity issuance costs during the six months ended June 30, 2012.

Capital financing was used to repay borrowings under our previous credit facilities. During the first six months of 2012, we borrowed $6.0 million and paid down the $208.0 million balance of the previous credit facilities in connection with the recapitalization. During the first six months of 2011, we refinanced our previous credit facilities, which resulted in $8.0 million in net borrowings on long-term debt offset by $7.0 million in payments for deferred loan costs.

All restricted stock awards were vested as a result of the change in control in February 2012. For the six months ended June 30, 2012 and 2011, we repurchased $2.1 million and $0.1 million, respectively, in common stock from participants under our 2006 Long-Term Incentive Plan to net settle the related withholding tax liability.

On June 29, 2012, we priced $750.0 million aggregate principal amount of 9.75% senior unsecured notes due 2020 in a private offering. Net proceeds from these notes of approximately $724.8 million were funded into escrow on July 16, 2012 and subsequently released from escrow on August 1, 2012 and utilized to fund portions of the GeoResources and East Texas Assets transactions. See “Recent Developments — 9.75% Senior Notes” in Item 2 for a more detailed discussion.

Contractual Obligations

We have no significant long-term commitments associated with our capital expenditure plans. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, development and exploration activities, oil and natural gas price conditions and other related economic factors. We may enter into commitments related to drilling, non-cancelable operating leases or various other contracts in the future. At June 30, 2012, we have non-cancelable operating leases of $40.7 million, primarily related to our corporate office lease in Houston, Texas, which expire on various dates through 2020. Currently, no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

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 year ended December 31, 2011.

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Results of Operations

Three Months Ended June 30, 2012 and 2011

We reported net income of $7.7 million and $8.9 million for the three months ended June 30, 2012 and 2011, respectively, resulting in a decline in the net income of $1.2 million. The following tables summarize key items of comparison and their related change for the periods indicated (in thousands, except per unit and Boe amounts).

	Three Months Ended
	June 30,
	2012			2011			Change
Net income	$	7,659		$	8,936		$	(1,277	)
Operating revenues:
Oil	20,383			22,783			(2,400		)
Natural gas	1,240			2,812			(1,572		)
NGLs	1,623			2,523			(900		)
Other revenue	35			34			1
Operating expenses:
Production:
Lease operating	8,663			7,812			851
Workover	540			362			178
Taxes	1,352			1,478			(126		)
General and administrative:
General and administrative	12,558			3,935			8,623
Share-based compensation	529			686			(157		)
Restructuring	903			—			903
Depletion, depreciation and accretion:
Depletion - full cost	5,183			4,945			238
Depreciation - other	345			251			94
Accretion	428			412			16
Other income (expenses):
Net gain on derivative contracts	13,671			8,268			5,403
Interest expense	(4,192		)	(3,563		)	(629		)
Other income (expense)	13			(798		)	811
Income before income taxes	2,272			12,178			(9,906		)
Income tax provision (benefit)	(5,387		)	3,242			(8,629		)

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	Three Months Ended
	June 30,
	2012		2011		Change
Production:
Oil (MBbls)	221		226		(5		)
Natural gas (MMcf)	584		660		(76		)
NGLs (MBbls)	38		44		(6		)
Total MBoe	356		380		(24		)
Average daily production (Boe)	3,912		4,176		(264		)

Average price per unit:
Oil (Bbl)	$	92.23	$	100.81	$	(8.58	)
Natural gas (Mcf)	2.12		4.26		(2.14		)
NGLs (Bbl)	42.71		57.34		(14.63		)
Total per Boe	65.30		73.99		(8.69		)

Average cost per Boe:
Production:
Lease operating	$	24.33	$	20.56	$	3.77
Workover	1.52		0.95		0.57
Taxes	3.80		3.89		(0.09		)
General and administrative:
General and administrative	35.28		10.36		24.92
Share-based compensation	1.49		1.81		(0.32		)
Restructuring costs	2.54		—		2.54
Depletion	14.56		13.01		1.55

For the three months ended June 30, 2012, oil and natural gas revenues decreased $4.9 million from the same period in 2011. The decrease was primarily due to a decline in realized average prices and production volumes during the 2012 period. Decreases in realized average prices of $8.69 (approximately 12%) per Boe contributed approximately $3.1 million of the decline in revenues for the three months ended June 30, 2012. Production volumes also decreased by 24 MBoe or 6%, contributing $1.8 million to the decline in oil and natural gas revenues.

Lease operating expenses increased $0.9 million for the three months ended June 30, 2012 primarily due to higher service costs and repairs in our Electra/Burkburnett fields and increased employee costs during the 2012 period. This increase in lease operating expense combined with decreased production resulted in increased lease operating expense on a per unit basis. Lease operating expenses were $24.33 per Boe in 2012 compared to $20.56 per Boe in 2011, reflecting the impact of lower production volumes coupled with higher lease operating expense.

Workover expenses increased $0.2 million for the three months ended June 30, 2012 compared to the same period in 2011. The increase resulted primarily from increased activity in our Electra/Burkburnett fields.

Oil and natural gas production taxes decreased $0.1 million for the three months ended June 30, 2012 as compared to the same period in 2011. Most production taxes are based on realized prices at the wellhead, while Louisiana production taxes are based on volumes for natural gas and values for oil. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease directly. The decrease is primarily due to a decline in oil and natural gas sales for the quarter ended June 30, 2012 compared to the same period in 2011. As a percentage of revenue, oil and natural gas production tax was 6% for the three months ended June 30, 2012 and 5% for the three months ended June 30, 2011.

General and administrative expense for the three months ended June 30, 2012 increased $8.6 million to $12.6 million as compared to the same period in 2011. The increase in general and administrative expenses is primarily attributable to an approximately $4.0 million increase in payroll and related employee costs as well as an increase of approximately $1.1 million in professional fees, both of which are in support of the expanding business base and increased corporate activities subsequent

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to the recapitalization. Transaction costs for business acquisitions and mergers drove approximately $3.6 million of the increase.

Share-based compensation expense for the quarter ended June 30, 2012 was $0.5 million, a decrease of $0.2 million compared to the same period in 2011. The decrease is primarily due to a smaller number of awards outstanding in the 2012 period. The awards outstanding in the 2011 period were all fully vested in connection with the recapitalization in February 2012.

We incurred $0.9 million in restructuring costs for the three months ended June 30, 2012 related to the 2012 restructuring to close the Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas. There were no restructuring costs incurred for the three months ended June 30, 2011.

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 for the evaluated properties. Depletion expense increased $0.2 million for the three months ended June 30, 2012 compared to the same period in 2011, to $5.2 million primarily due to a higher depletion rate per Boe, partially offset by a decline in production. On a per unit basis, depletion expense was $14.56 per Boe for the quarter ended June 30, 2012 compared to $13.01 per Boe for the quarter ended June 30, 2011. The increase in the depletion rate per Boe is primarily due to a decline in reserves between the comparable periods. The decline in reserves was caused by revisions of previous reserve estimates, slightly offset by price increases.

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 statement of operations. At June 30, 2012, we had a $7.2 million net derivative receivable, $4.5 million of which was classified as current, and $2.7 million of which was classified as noncurrent. We recorded a net derivative gain of $13.7 million ($12.7 million net unrealized gain and $1.0 million net realized gain for cash received on settled contracts and premium costs) for the three months ended June 30, 2012 compared to a net derivative gain of $8.3 million ($10.4 million net unrealized gain and $2.1 million net realized loss for cash received on settled contracts and premium costs) in the same period in 2011. The increase in net gain on derivative contracts is primarily due to declines in market prices for crude oil and natural gas.

Interest expense of $7.5 million, partially offset by capitalized interest expense on unevaluated properties of $3.3 million, increased $0.6 million for the three months ended June 30, 2012 compared to the same period in 2011. The increase is primarily due to higher average outstanding borrowings in the 2012 period. We had no capitalized interest during 2011.

For the three months ended June 30, 2011, we were party to a lawsuit and incurred approximately $0.8 million in litigation expenses which were reported in other expense.

Based on the estimated effective annual tax rate, we recorded an income tax benefit of $5.4 million on pre-tax income of $2.3 million for the three months ended June 30, 2012 resulting in a negative effective tax rate of 237% as of June 30, 2012. The high negative effective tax rate is a result of a change in the pre-tax book loss for the three months ended March 31, 2012 of $27.7 million to pretax book income for the three months ended June 30, 2012 of $2.3 million. The change in pretax book income increases the percentage by which the nondeductible items for tax purposes, primarily interest expense and related discount on the convertible note, impact the effective tax rate. For the three months ended June 30, 2011 we recorded income tax provision of $3.2 million on pretax book income of $12.2 million, resulting in an effective tax rate of 27%.

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Six Months Ended June 30, 2012 and 2011

We reported a net loss of $25.7 million for the six months ended June 30, 2012 compared to a net loss of $1.0 million for the same period in 2011, resulting in an increase in the net loss of $24.7 million. The following tables summarize key items of comparison and their related change for the periods indicated (in thousands, except per unit and per Boe amounts).

	Six Months Ended
	June 30,
	2012			2011			Change
Net loss	$	(25,663	)	$	(975	)	$	(24,688	)
Operating revenues:
Oil	43,380			43,195			185
Natural gas	2,908			5,704			(2,796		)
NGLs	3,792			4,938			(1,146		)
Other revenue	71			85			(14		)
Operating expenses:
Production:
Lease operating	16,610			15,653			957
Workover	1,261			896			365
Taxes	2,922			2,889			33
General and administrative:
General and administrative	28,789			7,813			20,976
Share-based compensation	4,632			1,355			3,277
Restructuring	1,007			—			1,007
Depletion, depreciation and accretion:
Depletion - full cost	10,545			9,969			576
Depreciation - other	561			500			61
Accretion	829			814			15
Other income (expenses):
Net gain (loss) on derivative contracts	8,726			(5,982		)	14,708
Interest expense	(17,230		)	(10,113		)	(7,117		)
Other income (expense)	54			(750		)	804
Loss before income taxes	(25,455		)	(2,812		)	(22,643		)
Income tax provision (benefit)	208			(1,837		)	2,045

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	Six Months Ended
	June 30,
	2012		2011		Change
Production:
Oil (MBbls)	447		448		(1		)
Natural gas (MMcf)	1,199		1,370		(171		)
NGLs (MBbls)	78		91		(13		)
Total MBoe	725		767		(42		)
Average daily production (Boe)	3,984		4,238		(254		)

Average price per unit:
Oil (Bbl)	$	97.05	$	96.42	$	0.63
Natural gas (Mcf)	2.43		4.16		(1.73		)
NGLs (Bbl)	48.62		54.26		(5.64		)
Total per Boe	69.08		70.19		(1.11		)

Average cost per Boe:
Production:
Lease operating	$	22.91	$	20.41	$	2.50
Workover	1.74		1.17		0.57
Taxes	4.03		3.77		0.26
General and administrative:
General and administrative	39.71		10.19		29.52
Share-based compensation	6.39		1.77		4.62
Restructuring costs	1.39		—		1.39
Depletion	14.54		13.00		1.54

For the six months ended June 30, 2012, oil and natural gas revenues decreased $3.8 million from the same period in 2011. The decrease was primarily due to lower realized average prices and production during the 2012 period. The realized average price decline of $1.11 per Boe contributed approximately $0.9 million to the revenue decrease for the six months ended June 30, 2012. Production volumes also decreased by 42 MBoe or 5%, resulting in a $2.9 million decline in oil and natural gas revenues.

Lease operating expenses increased $1.0 million for the six months ended June 30, 2012 primarily due to higher service costs and repairs in our Electra/Burkburnett fields and increased employee costs during the 2012 period. Lease operating expenses were $22.91 per Boe in 2012 compared to $20.41 per Boe in 2011, reflecting the impact of lower production volumes coupled with higher lease operating expense.

Workover expenses increased $0.4 million for the six months ended June 30, 2012 compared to the same period in 2011. The increase resulted primarily from increased activity in one of our Louisiana properties and our Electra/Burkburnett fields.

Oil and natural gas production taxes were $2.9 million for the six months ended June 30, 2012 and 2011. Most production taxes are based on realized prices at the wellhead, while Louisiana production taxes are based on volumes for natural gas and values for oil. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease directly. During the six months ended June 30, 2011, we received severance tax credits that decreased production taxes. As a result, production taxes for the six months ended June 30, 2012 did not fluctuate much from the comparable period in 2011. As a percentage of revenue, oil and natural gas production tax was 6% for the first six months of 2012 compared to 5% for the first six months of 2011.

General and administrative expense for the six months ended June 30, 2012 increased $21.0 million to $28.8 million as compared to the same period in 2011, largely reflecting the impact of the recapitalization and transaction costs related to acquisitions and mergers related transaction costs. The increase includes charges of approximately $6.7 million in employee related costs in support of the expanding business base, $5.4 million for change in control payments in connection with the recapitalization, $2.5 million in professional fees resulting from an increase in corporate activities subsequent to the

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recapitalization and $2.5 million for engagement termination fees. Acquisition and merger transaction costs resulted in approximately $3.6 million in increased general and administrative expense.

Share-based compensation expense for the six months ended June 30, 2012 was $4.6 million, an increase of $3.3 million compared to the same period in 2011. The increase is primarily due to $4.3 million for the accelerated vesting of restricted stock awards and stock appreciation rights resulting from the change in control that occurred due to our recapitalization in February 2012. Excluding the effect of the recapitalization, share-based compensation expense was $1.0 million lower in the six months ended June 30, 2012, as a result of a lower number of outstanding awards in the 2012 period.

We incurred $1.0 million in restructuring costs for the six months ended June 30, 2012 related to the 2012 restructuring to close the Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas. There were no restructuring costs incurred for the six months ended June 30, 2011.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs associated with evaluated properties plus future development costs based on the ratio of production volumes for the current period to total remaining reserve volumes for the evaluated properties. Depletion expense increased $0.6 million for the six months ended June 30, 2012 from the same period in 2011, to $10.5 million primarily due to a higher depletion rate per Boe, partially offset by a decline in production. On a per unit basis, depletion expense was $14.54 per Boe for the six months ended June 30, 2012 compared to $13.00 per Boe for the six months ended June 30, 2011. The increase in the depletion rate per Boe is primarily due to a decline in reserves between the comparable periods. The decline in reserves was caused by revisions of previous reserve estimates, slightly offset by price increases.

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 statement of operations. At June 30, 2012, we had a $7.2 million net derivative receivable, $4.5 million which was classified as current, and $2.7 million of which was classified as noncurrent. We recorded a net derivative gain of $8.7 million ($7.7 million net unrealized gain and $1.0 million net realized gain for cash received on settled contracts and premium costs) for the six months ended June 30, 2012 compared to a net derivative loss of $6.0 million ($4.7 million net unrealized loss and $1.3 million net realized loss for cash received on settled contracts and premium costs) in the same period in 2011. The increase in net gain on derivative contracts is primarily due to declines in market prices for crude oil and natural gas.

Interest expense and other, net of $17.2 million, net of capitalized interest on unevaluated properties of $3.4 million, increased $9.7 million for the six months ended June 30, 2012 compared to the same period in 2011. The increase is primarily due to the expensing of $7.3 million in unamortized debt issuance costs and prepayment fees in connection with the payoff of the March 2011 credit facilities in connection with the recapitalization in addition to higher average outstanding borrowings in the 2012 period. We had no capitalized interest during 2011.

For the six months ended June 30, 2011, we were party to a lawsuit and incurred approximately $0.8 million in litigation expenses which were reported in other expense.

Based on the estimated effective annual tax rate, we recorded a tax provision of $0.2 million on pre-tax loss of $25.5 million for the six months ended June 30, 2012. We calculated an estimated effective annual tax rate for the current annual reporting period, excluding any discrete items, of 4.4% as of June 30, 2012. The effective tax rate is lower than the statutory rate primarily due to interest expense on our convertible note, which is nondeductible for tax purposes. For the six months ended June 30, 2011, we recorded income tax benefit of $1.8 million on a pre-tax loss of $2.8 million.

Recently Issued Accounting Pronouncements

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

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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 and natural gas prices decline significantly, our ability to finance our capital budget and operations could be adversely impacted. We currently sell most of our oil, natural gas and NGL production under market price contracts. For the three and six months ended June 30, 2012, two of our purchasers accounted for $17.3 million and $36.9 million, respectively, or approximately 74%, of our revenue from the sales of oil, natural gas and NGLs. No other purchaser accounted for 10% or more of our oil and natural gas revenue for the three or the six months ended June 30, 2012.

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 effect it could have on our operations. The types of derivative instruments that we typically utilize include collars, three-way collars and puts. The total volumes which we hedge through the use of derivative instruments varies from period to period; however, generally our objective is to hedge 80% of our current and anticipated production for the next 24 months. At June 30, 2012, our commodity hedging ranged from 39% to 98% calculated on a monthly basis of our current and anticipated production through June 30, 2014. Our hedging policies and objectives may change significantly as commodities prices or price futures change. The First Amendment to our February 2012 Credit Agreement, which was effective August 1, 2012, allows us to hedge up to 85% of our current and anticipated production.

We are exposed to market risk on our open derivative contracts of non-performance by our counterparty. We do not expect such non-performance because our contracts are with a major financial institution with investment grade credit ratings. The counterparty to our derivative contracts is a lender in our credit agreement. We did not post collateral under these contracts as they are secured under our credit agreement. Please refer to Item 1. Financial Statements (Unaudited) — Note 11, “Derivatives” for additional information.

Based on June 30, 2012 NYMEX forward curves of natural gas and crude oil futures prices, adjusted for our counterparty credit risk, we would expect to receive future cash payments of $7.2 million under our natural gas and crude oil derivative arrangements as they mature. If future prices of natural gas and crude oil were to decline by 10%, we would expect to receive future cash payments under our natural gas and crude oil derivative arrangements of $20.5 million, and if future prices were to increase by 10%, we would expect to pay future cash payments of $6.5 million.

We account for our derivative activities under the provisions of Topic 815 of the Codification, 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. Financial Statements (Unaudited) — Note 11, “Derivatives” for additional information.

Interest Sensitivity

We are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in variable rates, which are LIBOR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our borrowings.

At June 30, 2012, we had no borrowings under our February 2012 Credit Agreement, which bears interest at LIBOR plus 150 to 250 basis points. We had $242.6 million in long-term debt net of $41.3 million of unamortized discount related to the 8% Note. Fluctuations in market interest rates will cause our annual interest costs on borrowings under our February 2012 Credit Agreement to fluctuate proportionately. Fluctuations in market interest rates will not affect our annual interest costs on our 8% convertible note.

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 June 30, 2012. 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

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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 effect any change in our internal controls over financial reporting during the quarter ended June 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Reference is made to Part I, Item 3, “Legal Proceeding,” in our annual report on Form 10-K for the year ended December 31, 2011 and Part II, Item 1, “Legal Proceedings,” in our quarterly report on Form 10-Q for the quarter ended March 31, 2012, for a discussion of pending legal proceedings to which we are a party.

On July 16, 2012, a settlement agreement was entered into, subject to the court’s approval, regarding the settlement of the action styled Yost v. GeoResources, Inc. et al., Case No. 1:12-CV-01307-MSK-KMT, pending in the United States District Court for the District of Colorado (the “Federal Action”), which was filed on behalf of a putative class of GeoResources stockholders against GeoResources, the GeoResources board of directors and, in certain instances, Halcón and certain subsidiaries of Halcón as aiders and abettors. Pursuant to such settlement, Halcón and GeoResources agreed to make certain supplemental disclosures regarding the merger and to provide additional disclosures to their stockholders, which disclosures were included in a Form 8-K filed with the U.S. Securities and Exchange Commission on July 18, 2012. Objections to the settlement agreement are scheduled to be submitted on August 15, 2012 to the federal court in Colorado and a hearing on the settlement agreement is expected to be scheduled at a later date.

Item 1A. Risk Factors

Reference is made to Part I, Item 1A, “Risk Factors,” in our annual report on Form 10-K for the year ended December 31, 2011 for a discussion of additional risk factors which could materially affect our business, financial condition or future results.

Restrictive covenants in the indenture governing our senior notes and in our revolving credit facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

The indenture governing our senior notes due 2020, which we refer to as “the 9.75% Notes,” imposes significant operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:

· pay dividends on or make distributions in respect of our capital stock or make other restricted payments;

· incur additional indebtedness;

· create liens;

· engage in mergers or consolidations or sell or otherwise dispose of all or substantially all of our assets;

· make certain dispositions and transfers of assets; and

· engage in transactions with affiliates.

In addition, our revolving credit facility contains a number of significant covenants that, among other things, restrict our ability to:

· dispose of assets;

· incur or guarantee additional indebtedness and issue certain types of preferred stock;

· pay dividends on our capital stock;

· create liens on our assets;

· enter into sale or leaseback transactions;

· enter into specified investments or acquisitions;

· repurchase, redeem or retire our capital stock or subordinated debt;

· merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;

· engage in specified transactions with subsidiaries and affiliates; or

· pursue other corporate activities.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the indenture governing the 9.75% Notes and our revolving credit facility. Also, our revolving credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as

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a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. A decline in oil, NGL and natural gas prices, or a prolonged period of oil, NGL and natural gas prices at lower levels, could eventually result in our failing to meet one or more of the financial covenants under our credit agreement, which could require us to finance or amend the credit agreement resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit agreement. A default under our credit agreement or the indenture governing the 9.75% Notes, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder. The accelerated debt would become immediately due and payable. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. Moreover, any new indebtedness we incur may impose financial restrictions and other covenants on us that may be more restrictive than the revolving credit facility or the indenture governing the 9.75% Notes.

Our debt level in the future and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business.

Our level of indebtedness in the future, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including by:

· making it more difficult for us to satisfy our obligations under the 9.75% Notes or other indebtedness and increasing the risk that we may default on our debt obligations;

· requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

· limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

· limiting management’s discretion in operating our business;

· limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

· detracting from our ability to withstand successfully a downturn in our business or the economy generally;

· placing us at a competitive disadvantage against less leveraged competitors; and

· making us vulnerable to increases in interest rates, because debt under any senior revolving credit facility may vary with prevailing interest rates.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions.

We are able to incur a substantial amount of additional indebtedness. This could further exacerbate the risks associated with our indebtedness.

Our revolving credit facility currently has a borrowing base of $525.0 million for secured borrowings, subject to periodic borrowing base redeterminations. If new debt is incurred, the related risks that we and our subsidiaries now face could intensify. Increased leverage could, for example:

· make it more difficult for us to satisfy our obligations under our indebtedness; if we fail to comply with the requirements of our indebtedness, that failure could result in an event of default of such indebtedness;

· require us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other business activities;

· limit our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate purposes;

· limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

· diminish our ability to successfully withstand a downturn in our business or the economy generally; and

· place us at a competitive disadvantage against less leveraged competitors.

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If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could increase.

Our business plan includes substantial capital requirements which may require additional debt or equity financing.

We expect to make substantial capital expenditures for the acquisition, development, production and exploration of our oil and natural gas properties in order to fully execute our business plan. Our capital requirements will depend on numerous factors, and we cannot predict accurately the exact timing and amount of our capital requirements. Although we intend to finance a substantial portion of our future capital expenditures through cash flow from operations, cash on hand, and our revolving credit facility, we may require additional funds which could come from debt or equity financing or asset sales. A decrease in expected revenues or adverse change in market conditions could make obtaining financing economically unattractive or impossible or reduce the value we expect to receive from asset divestitures.

A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity could negatively impact our ability to remain in compliance with the financial covenants under our revolving credit facility which could force us to limit or defer our planned natural gas and oil leasing, exploration and development program. Moreover, if we are unable to finance our growth as expected, we could be required to sell assets, seek alternative financing, the terms of which may not be attractive to us, or reduce the scope of our business plan. In addition, a significant increase in our indebtedness could cause us to be unable to obtain sufficient credit capacity with counterparties to finance the hedging of our future crude oil and natural gas production which may limit our ability to manage price risk. As a result of these factors, we may lack the capital necessary to fully pursue our drilling program, obtain credit necessary to enter into derivative contracts to hedge our future crude oil and natural gas production or to capitalize on other business opportunities.

Part of our strategy involves exploratory drilling, including drilling in new or emerging unconventional resource plays using horizontal drilling and completion techniques. The results of our planned exploratory drilling program are subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production.

The results of our exploratory drilling in new or emerging plays are more uncertain than drilling results in areas that are developed and have established production. Because new or emerging plays and new formations have limited or no production history, we are less able to use past drilling results in those areas to help predict our future drilling results. Further, part of our drilling strategy to maximize recoveries in certain formations may involve the drilling of horizontal wells using completion techniques that have proven to be successful in other unconventional formations. Our experience with horizontal drilling in these areas to date, as well as the industry’s drilling and production history, is limited. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established.

Further, access to adequate gathering systems or pipeline takeaway capacity, the availability of drilling rigs, completion and other services and access to midstream services may be more challenging in new or emerging plays. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and takeaway capacity or otherwise, and/or oil, NGL or natural gas price decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.

Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We plan to invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return.

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Our ability to achieve our target results are dependent upon the current and future market prices for oil, NGLs and natural gas, costs associated with producing oil, NGLs and natural gas and our ability to add reserves at an acceptable cost. We significantly rely on 3-D seismic data and other advanced technologies in identifying leasehold acreage prospects and in conducting our exploration activities. The 3-D seismic data and other technologies we use do not allow us to know conclusively prior to our acquisition of leasehold acreage or drilling a well whether oil, NGLs or gas is present or may be produced economically. The use of 3-D seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies.

Many of the emerging resource plays that we have targeted have limited or no production history using the drilling and completion methods that we expect to employ. Accordingly, these operations are subject to more uncertainties than our drilling activities in more established fields and formations and may not meet our expectations for reserves or production or our costs to operate may be higher than initially expected. If initially successful, the ultimate success of these drilling and completion strategies and techniques in these new formations will be better evaluated over time as more wells are drilled and production profiles are better established. In addition, we may not be successful in controlling and reducing our drilling and production costs in order to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling and completion, and we may be forced to limit, delay or cancel drilling and completion operations as a result of a variety of factors, including:

· unexpected drilling conditions;

· pressure or irregularities in formations;

· equipment failures or accidents and shortages or delays in the availability of oilfield services or drilling rigs and other equipment;

· adverse weather conditions, including hurricanes; and

· compliance with and changes in governmental regulations.

We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

Our business plan contemplates significant acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy, which may include the acquisition of asset packages of producing properties or existing companies or businesses operating in our industry, such as the GeoResources merger and our acquisition of the East Texas Assets. The successful acquisition of producing properties requires an assessment of several factors, including:

· recoverable reserves;

· future oil, NGL and natural gas prices and their appropriate differentials;

· development and operating costs; and

· potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions of existing companies or businesses and other strategic transactions may involve additional risks, including:

· diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

· the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with our own while carrying on our ongoing business;

· difficulty associated with coordinating geographically separate organizations; and

· the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration

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process, which will decrease the time they will have to manage our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could be materially and adversely affected.

Limitations on the availability of drilling rigs and field services in the Bakken Shale in North Dakota and Montana could adversely affect our ability to execute our development plans.

GeoResources has experienced limitations in the availability of drilling rigs, services for pressure pumping and other services required for well completion in the Bakken Shale in North Dakota and Montana. During 2011 GeoResources experienced substantial delays between drilling and completion of many of its operated and non-operated wells in the Williston Basin. In the latter half of 2011, timing between drilling and well completion improved, but continued increases in drilling activity could lengthen delays. Increased delays could adversely affect production and reserve replacement, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. The lack of availability of these types of services causes delays in our development and production operations and caused us to incur additional expenditures above what we have budgeted for those services. We cannot determine the magnitude or length of the shortages for these services, but should they persist or increase the cost or lack of availability of these services they could have a material adverse effect on our business, cash flows and their timing, financial condition and results of operations.

We may not be able to successfully integrate the businesses of the Company and GeoResources.

The success of the GeoResources merger depends in large part upon our ability to integrate the Company’s and GeoResources’ organizations, operations, systems and personnel. The integration of two previously independent companies is a challenging, time-consuming and costly process. The Company and GeoResources have operated independently. It is possible that the integration process could result in the loss of key employees, the disruption of each company’s ongoing businesses or inconsistencies in standards, controls, procedures and policies that adversely affect our ability to maintain relationships with suppliers, customers and employees or to achieve the anticipated benefits of the GeoResources merger. In addition, successful integration of the companies will require the dedication of significant management resources, which will temporarily detract attention from the day-to-day businesses of the combined company. If we are not able to integrate our organizations, operations, systems and personnel in a timely and efficient manner, the anticipated benefits of the GeoResources merger may not be realized fully or at all or may take longer to realize than expected.

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

Effective June 7, 2012, the Company granted 5,000 shares of common stock to each non-employee director as an equity award pursuant to the Company’s 2006 Long Term Incentive Plan (the “Plan”); with the exception that non-employee director Daniel A. Rioux was not issued an award of common stock. Instead, an award of 5,000 shares of common stock was issued under the Plan to Kellen Holdings, LLC, a entity affiliated with Liberty Energy Holdings, LLC, where Mr. Rioux is Co-President and Chief Executive Officer. The Company relied on the exemption from registration contained in Section 4(2) of the Securities Act of 1933, as amended, in issuing the shares of common stock to Kellen Holdings, LLC. The Company did not receive any proceeds from the issuance of the shares of common stock to Kellen Holdings, LLC. The shares of common stock are subject to a six month vesting period, which provides that the shares will vest if Mr. Rioux remains a director of the Company through the six month anniversary of the date of grant, subject to acceleration under certain circumstances.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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

Exhibit No.		Description

2.1		Agreement and Plan of Merger, dated as of April 24, 2012 by and among Halcón Resources Corporation, Leopard Sub I, Inc., Leopard Sub II, LLC and GeoResources, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed April 25, 2012).

2.2		Agreement of Sale and Purchase dated May 8, 2012 between NCL Appalachian Partners, L.P., as Seller, and Halcón Energy Properties, Inc., as Buyer (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed July 2, 2012)

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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).

3.1.1		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).

3.1.2		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).

3.2		Second Amended and Restated Bylaws of RAM Energy Resources, Inc. (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed January 5, 2012).

4.1		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).

4.2		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).

10.1†		Halcón Resources Corporation 2012 Long-Term Incentive Plan effective May 17, 2012 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 22, 2012).

10.2†		Employment Agreement between Floyd C. Wilson and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 5, 2012)

10.3†		Employment Agreement between Stephen W. Herod and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed June 5, 2012)

10.4†		Employment Agreement between Mark J. Mize and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed June 5, 2012)

10.5†		Employment Agreement between David S. Elkouri and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed June 5, 2012)

10.6†		Employment Agreement between Joseph S. Rinando, III and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K filed June 5, 2012)

10.7†		Form of Stock Option Award Agreement (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 13, 2012)

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10.8†		Form of Employee Restricted Stock Agreement (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed June 13, 2012)

10.9†		Form of Non-Employee Director Restricted Stock Agreement (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed June 13, 2012)

10.10		Escrow Agreement, dated as of July 16, 2012, by and among Halcón Resources Corporation, U.S. Bank National Association, as trustee under the Indenture, and U.S. Bank National Association, as escrow and paying agent (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 17, 2012)

31.1*		Rule 13(A) — 14(A) Certification of our Principal Executive Officer

31.2*		Rule 13(A) — 14(A) Certification of our Principal Financial Officer

32.1*		Section 1350 Certification of our Principal Executive Officer

32.2*		Section 1350 Certification of our Principal Financial Officer

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

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

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SIGNATURES

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

	HALCÓN RESOURCES CORPORATION


August 2, 2012	By:	/s/ FLOYD C. WILSON
	Name:	Floyd C. Wilson
	Title:	Chairman of the Board and Chief Executive Officer


August 2, 2012	By:	/s/ MARK J. MIZE
	Name:	Mark J. Mize
	Title:	Executive Vice President and Chief Financial Officer

August 2, 2012	By:	/s/ JOSEPH S. RINANDO, III
	Name:	Joseph S. Rinando, III
	Title:	Vice President and Chief Accounting Officer