BATTALION OIL CORP - Quarter Report: 2012 March (Form 10-Q)

BATTALION OIL CORP - Quarter Report: 2012 March (Form 10-Q)

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Form 10-Q

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 March 31, 2012

¨	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 ¨

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 ¨

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.

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

At May 7, 2012, 143,825,987 shares of the Registrant’s Common Stock were outstanding.

First Quarter 2012 Form 10-Q Report

TABLE OF CONTENTS


	Page
PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (unaudited)

Condensed Consolidated Statements of Operations — Three Months Ended March 31, 2012 and 2011		5

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

Condensed Consolidated Statements of Stockholders’ Equity – Three Months Ended March 31, 2012 and Year Ended December 31, 2011		7

Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 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		23

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		28

ITEM 4. CONTROLS AND PROCEDURES		29

PART II — OTHER INFORMATION		29

ITEM 1. LEGAL PROCEEDINGS		29

ITEM 1A. RISK FACTORS		29

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		31

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		31

ITEM 4. MINE SAFETY DISCLOSURES		31

ITEM 5. OTHER INFORMATION		32

ITEM 6. EXHIBITS		32

SIGNATURES		36

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;

•

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 for 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 fully develop our undeveloped acreage positions;

•

our ability to 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, necessary to fully execute our capital program;

•

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 make it difficult to access financial markets;

•

the ability to complete the acquisition of GeoResources, Inc. (“GeoResources”);

•

failure to obtain, delays in obtaining or adverse conditions contained in, any required regulatory approvals associated with the GeoResources acquisition;

•

our ability to successfully integrate GeoResources’ operations and to realize the benefits expected from the merger;

•

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.

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 March 31,
	2012			2011
Operating revenues:
Oil and natural gas sales
Oil	$	22,997		$	20,412
Natural gas		1,668			2,892
NGLs		2,169			2,415

Total oil and natural gas sales		26,834			25,719
Other		36			51

Total operating revenues		26,870			25,770

Operating expenses:
Production:
Lease operating		8,668			8,375
Taxes		1,570			1,411
Restructuring		104			—
General and administrative		20,334			4,547
Depletion, depreciation and accretion		5,979			5,675

Total operating expenses		36,655			20,008

Income (loss) from operations		(9,785	)		5,762

Other expenses:
Net loss on derivative contracts		(4,945	)		(14,250	)
Interest expense and other, net		(12,997	)		(6,502	)

Total other expenses		(17,942	)		(20,752	)

Loss before income taxes		(27,727	)		(14,990	)
Income tax provision (benefit)		5,595			(5,079	)

Net loss		(33,322	)		(9,911	)
Preferred dividend		(1,102	)		—

Net loss available to common stockholders	$	(34,424	)	$	(9,911	)

Net loss per common share:
Basic	$	(0.50	)	$	(0.38	)

Diluted	$	(0.50	)	$	(0.38	)

Weighted average common shares outstanding:
Basic		68,816			26,120

Diluted		68,816			26,120

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)


	March 31, 2012			December 31, 2011
Current assets:
Cash	$	685,783		$	49
Accounts receivable		10,851			10,288
Receivables from derivative contracts		—			260
Deferred income taxes		2,316			2,601
Inventory		4,264			4,310
Prepaids and other		1,691			2,729

Total current assets		704,905			20,237
Oil and natural gas properties (full cost method):
Evaluated		723,293			715,666
Unevaluated		16,438			—

Gross oil and natural gas properties		739,731			715,666
Less — accumulated depletion and impairment		(507,355	)		(501,993	)

Net oil and natural gas properties		232,376			213,673

Other operating property and equipment:
Other operating assets		9,890			9,979
Less — accumulated depreciation		(6,632	)		(7,133	)

Net other operating property and equipment		3,258			2,846

Other noncurrent assets:
Debt issuance costs, net of amortization		5,180			5,966
Deferred income taxes		18,865			24,102
Other		4,828			978

Total assets	$	969,412		$	267,802


Current liabilities:
Accounts payable and accrued liabilities	$	21,264		$	25,061
Liabilities from derivative contracts		1,615			265
Asset retirement obligations		1,000			1,010

Total current liabilities		23,879			26,336
Long-term debt		235,475			202,000
Other noncurrent liabilities:
Liabilities from derivative contracts		4,046			805
Asset retirement obligations		33,152			32,703
Other		10			10
Commitments and contingencies
Stockholders’ equity:
Preferred stock: 1,000,000 shares of $0.0001 par value authorized, 4,444.4511 shares issued and outstanding at March 31, 2012		298,209			—
Common stock: 336,666,666 shares of $0.0001 par value authorized; 101,031,946 and 27,694,583 shares issued; 99,381,476 and 26,244,452 outstanding at March 31, 2012 and December 31, 2011, respectively		10			3
Additional paid-in capital		633,561			229,414
Treasury stock: 1,650,470 and 1,450,131 shares at March 31, 2012 and December 31, 2011, respectively, at cost		(9,298	)		(7,159	)
Accumulated deficit		(249,632	)		(216,310	)

Total stockholders’ equity		672,850			5,948

Total liabilities and stockholders’ equity	$	969,412		$	267,802

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)


	Year Ended December 31, 2011 and
	Three Months Ended March 31, 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
Offering costs		—		(14,449	)		—			—		(4,592	)		—		—			—			(19,041	)
Net loss		—		—			—			—		—			—		—			(33,322	)		(33,322	)
Preferred beneficial conversion feature		—		—			—			—		88,445			—		—			—			88,445
Preferred dividend		—		1,102			—			—		(1,102	)		—		—			—			—
Repurchase of stock		—		—			—			—		—			200		(2,139	)		—			(2,139	)
Share-based compensation		—		—			—			—		2,813			—		—			—			2,813

BALANCE, March 31, 2012		4	$	298,209			101,032		$	10	$	633,561			1,650	$	(9,298	)	$	(249,632	)	$	672,850

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)


	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net loss	$	(33,322	)	$	(9,911	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depletion, depreciation and accretion		5,979			5,675
Deferred income tax provision (benefit)		5,522			(5,140	)
Stock-based compensation		1,935			669
Unrealized loss on derivatives contracts		4,851			15,992
Amortization and write-off of deferred loan costs		6,087			2,662
Non-cash interest and amortization of discount		4,065			362
Other income		(12	)		(17	)
Changes in assets and liabilities:
Accounts receivable		(563	)		(841	)
Inventory		46			(108	)
Prepaid expenses and other		(828	)		260
Derivative premiums		—			(111	)
Accounts payable and accrued liabilities		(2,950	)		(5,262	)
Other		(9	)		(26	)

Net cash (used in) provided by operating activities		(9,199	)		4,204

Cash flows from investing activities:
Oil and natural gas capital expenditures		(23,986	)		(5,620	)
Proceeds received from sales of oil and natural gas properties		—			462
Other operating property and equipment capital expenditures		(629	)		(219	)
Proceeds received from sales of other property and equipment		13			11
Funds held in escrow		(3,776	)		—

Net cash used in investing activities		(28,378	)		(5,366	)

Cash flows from financing activities:
Proceeds from borrowings		237,410			224,064
Repayments of borrowings		(208,000	)		(216,142	)
Debt issuance costs		(4,495	)		(6,712	)
Offering costs		(18,056	)		—
Common stock repurchased		(2,139	)		(43	)
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		723,311			1,167

Net increase in cash		685,734			5
Cash at beginning of period		49			37

Cash at end of period	$	685,783		$	42

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

HALCÓN RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Continued

(In thousands)


	Three Months Ended March 31,
	2012		2011
Supplemental cash flow information:
Cash received for income taxes	$	—	$	(23	)
Cash paid for interest		3,316		5,355
Disclosure of non-cash investing and financing activities:
Asset retirement obligations		47		5
Preferred dividend		1,102		—
Payment-in-kind interest		3,239		583

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

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. Certain prior year amounts have been reclassified to conform to the current year presentation. 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 footnotes 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 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 “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 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 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 reflect 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.

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 $3.4 million and related costs will be recognized as restructuring expense over the requisite service periods through May 2013, as applicable.

4. 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.

At March 31, 2012 the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended March 31, 2012 of the West Texas Intermediate (WTI) spot price of $98.15 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended March 31, 2012 of the Henry Hub price of $3.73 per million British thermal units (Mmbtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at March 31, 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 March 31, 2011 the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended March 31, 2011 of the WTI posted price of $83.54 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended March 31, 2011 of the Henry Hub price of $4.10 per Mmbtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at March 31, 2011, did not exceed the ceiling amount.

5. LONG-TERM DEBT

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


	March 31, 2012		December 31, 2011
8% senior convertible note ⁽¹⁾	$	235,475	$	—
Revolving credit facility		—		127,000
Term loan facility		—		75,000

	$	235,475	$	202,000

⁽¹⁾	Amount includes a $42.8 million unamortized discount at March 31, 2012, recorded by the Company in conjunction with the issuance of the 8% $275.0 million senior convertible note. 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 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 Note, all or any portion of the interest due on the Note. At March 31, 2012, the Company elected to pay the interest in kind and rolled $3.2 million of interest incurred during the first quarter of 2012 into the Note. The 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 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 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 Note utilizing the effective interest rate method. The remaining unamortized discount was $42.8 million at March 31, 2012.

Current 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 previous revolving credit facility. The new 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 new agreement is LIBOR plus a margin ranging from 1.5% to 2.5% based on a percentage of usage. Advances under the new 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 is required to maintain commodity hedges on a rolling basis 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 March 31, 2012, the Company is in compliance with the financial debt covenants under this credit agreement. At March 31, 2012, the Company had no indebtedness outstanding under the $500.0 million senior revolving credit agreement and $225.0 million of borrowing capacity available.

Previous Credit Facilities

The Company’s prior facilities, entered into during March 2011, included a $250.0 million first lien revolving credit facility and a $75.0 million second lien term loan facility, replacing the previous 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 credit facility allowed for funds advanced under the revolving credit facility 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 Note and senior secured revolving credit agreement, respectively. In the first quarter of 2012, the Company expensed $5.8 million of debt issuance costs as a result of the pay off and termination of the previous revolving credit and term loan facilities. As previously noted, the Company entered into new credit facilities in March 2011. The Company expensed the remaining debt issuance cost associated with the previous facility totaling approximately $2.7 million in the first quarter 2011. At March 31, 2012 and December 31, 2011, the Company had approximately $5.2 million and $6.0 million, respectively, of unamortized debt issuance costs.

6. 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 months ended March 31, 2012 and 2011, the Company analyzed and made no adjustment to the valuation allowance.

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 are as follows:


	Three Months Ended March 31,
	2012			2011
Income tax at the federal statutory rate		34.0	%		34.0	%

State income tax benefit (expense), net of federal benefit		2.7	%		-29.4	%
Non-deductible dues and entertainment		-0.2	%		22.9	%
Non-deductible interest and expense on Note		-44.6	%		—
Reduction in deferred tax asset		-4.8	%		—
Share-based compensation		—			6.5	%
Non-deductible compensation		-6.0	%		—
Non-deductible basis in other operating property and equipment		-1.3	%		—
Other		—			-0.1	%

		-20.2	%		33.9	%

The Company has calculated an estimated negative effective annual tax rate for the current annual reporting period, excluding any discrete items, of 15.4% as of March 31, 2012. The Company has a discrete item of $1.3 million related to the reduction in net operating losses due to additional limitations created by the recapitalization of the Company in February 2012. This event created an “ownership change” and as a result the net operating losses of the Company will be subject to additional limitations. The discrete item for the first quarter of 2012 increases the negative effective tax rate to 20.2%. The negative tax rate reflected for the three months ended March 31, 2012 is primarily due to a Federal income tax limitation on the deductibility of the interest expense on the Note that was issued as part of the recapitalization of the Company. The estimated annual rate differs from the statutory rate primarily due to the estimate of state income taxes and non-deductible expenses for the period. Based on the estimated effective annual tax rate, the Company has recorded a tax provision of $5.6 million on a pre-tax loss of $27.7 million for the three months ended March 31, 2012. For the three months ended March 31, 2011, the Company recorded income tax benefit of $5.1 million on a pre-tax loss of $15.0 million, resulting in an effective tax rate of 34%.

For the quarter ended March 31, 2012 the Company has net operating losses of $61.1 million that are not expected to be limited due to the limitations created by the “ownership change” on February 8, 2012.

7. 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.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of March 31, 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 three months ended March 31, 2012 and for the year ended December 31, 2011.


	March 31, 2012
	Level 1		Level 2		Level 3		Total
Assets:
Receivables from derivative contracts	$	—	$	—	$	—	$	—

Liabilities:
Liabilities from derivative contracts	$	—	$	5,661	$	—	$	5,661


	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”, sold put options and bare purchased 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 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 March 31, 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 Note as of March 31, 2012, is $783.9 million and exceeded the carrying value of $235.5 million by $548.4 million. The fair value of the Note at March 31, 2012 was calculated using Level 2 criteria.

8. 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.

The Company recorded the following activity related to its ARO liability for the three months ended March 31, 2012 (in thousands):


Liability for asset retirement obligations as of December 31, 2011	$	33,713
Liabilities settled		(9	)
Additions		47
Accretion expense		401

Liability for asset retirement obligations as of March 31, 2012		34,152
Less: current asset retirement obligations		1,000

Long-term asset retirement obligations	$	33,152

9. COMMITMENTS AND CONTINGENCIES

Commitments

The Company enters into various commitments, operating leases and other contractual commitments in the normal course of business. At March 31, 2012, the aggregate commitments were not material to the financial position of the Company.

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

See Note 14 “Subsequent Events” for information regarding putative class action lawsuits filed in connection with a transaction contemplated by a merger agreement with GeoResources, Inc. (“GeoResources”) executed on April 24, 2012.

10. 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 and 2011, 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 new 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, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. 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 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 March 31, 2012 consist of put/call “collars,” sold put options and bare purchased 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. Bare purchased put options, also called “bare floors,” provide a floor price without a corresponding ceiling. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 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	March 31, 2012		December 31, 2011		March 31, 2012			December 31, 2011			March 31, 2012			December 31, 2011
Commodity contracts	Current assets — receivables from derivative contracts	$	—	$	1,850	$	—		$	(1,590	)	$	—		$	260

Commodity contracts	Current liabilities — liabilities from derivative contracts		1,545		—		(3,160	)		—			(1,615	)		—

Commodity contracts	Other noncurrent liabilities —liabilities from derivative contracts		—		2,050		(4,046	)		(2,602	)		(4,046	)		(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		$	1,545	$	3,900	$	(7,206	)	$	(4,710	)	$	(5,661	)	$	(810	)

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


	Amount of gain or (loss) recognized on derivative contracts for the three months ended March 31,
Derivatives not designated as hedging contracts	2012			2011
Unrealized loss on commodity contracts	$	(5,462	)	$	(14,953	)
Realized gain on commodity contracts		575			836
Unrealized gain (loss) on interest rate swaps		518			(122	)
Realized loss on interest rate swaps		(576	)		(11	)

Total net loss on derivative contracts	$	(4,945	)	$	(14,250	)

At March 31, 2012, the Company had the following open derivative contracts:


			March 31, 2012
					Floors			Ceilings			Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu’s/Bbl’s		Price/Price Range	Weighted Average Price		Price/Price Range	Weighted Average Price		Price/Price Range		Weighted Average Price
April 2012 — December 2012	3 Way-collars	Crude oil		309,500	$80.00 - $100.00	$	89.25	$101.70 - $113.25	$	104.86	$	70.00	$	70.00
April 2012 — December 2012	Collars	Crude oil		208,300	80.00 - 95.00		86.24	102.40 -107.00		105.62
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

At December 31, 2011, the Company had the following open derivative contracts:


			December 31, 2011
					Floors			Ceilings			Put Options Sold
Period	Instrument	Commodity	Volume in Mmbtu’s/Bbl’s		Price/Price Range	Weighted Average Price		Price/Price Range	Weighted Average Price		Price/Price Range		Weighted Average Price
January 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)
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%.

11. STOCKHOLDERS’ EQUITY

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

On May 8, 2006, the Company’s stockholders approved its 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. As of March 31, 2012 and December 31, 2011, a maximum of 1,423,951 and 491,450 shares of common stock, respectively remained reserved for issuance under the Plan.

Stock Options

During the three months ended March 31, 2012, the Company granted stock options covering 300,833 shares of common stock to employees of the Company. The stock options have exercise prices ranging from $10.00 to $11.55 with a weighted average price of $10.89. These awards vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. During the three months ended March 31, 2012, $0.1 million of recognized compensation expense was recorded as compensation expense. At March 31, 2012, the unrecognized compensation expense related to stock options totaled $1.2 million and will be recognized on the graded-vesting method over the requisite service periods.

Stock Appreciation Rights

During the three months ended March 31, 2012, the Company accelerated vesting and exercise of all unvested stock appreciation rights (“SARs”) that were granted in May 2011, due to the change in control in the Company resulting from the recapitalization as described in Note 2. The Company settled the SARs in cash, resulting in $2.2 million of share-based compensation expense recognized for the three months ended March 31, 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 three months ended March 31, 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 March 31, 2011, the Company had $4.3 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 months ended March 31, 2011 was $0.8 million. The Company recorded $0.7 million as compensation expense and $0.1 million as capitalized internal costs.

Warrants

During the three months ended March 31, 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 as described in Note 2 and are reflected in additional paid-in capital in Stockholders’ Equity. Costs incurred of $0.6 million were netted against the proceeds allocated to the Warrants. 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 being 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 a 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 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 Preferred Stock, conversion occurred prior to May 31, 2012. In accordance with the guidance of ASC 480 – Distinguishing Liabilities from Equity (“ASC 480”), the Company has reflected the Preferred Stock as permanent equity in the accompanying Condensed Consolidated Statements of Stockholders’ Equity as the Preferred Stock (including its ability and timing to convert) was solely within the control of the Company (issuer) from inception as the Company had obtained the Consent prior to issuing the Preferred Stock and had complete control over the mailing of the definitive information statement which was required per the Certificate of Designation in order for the shares to be automatically converted.

The Preferred Stock conversion feature was not considered a derivative instrument under ASC Topic 815—Derivatives and Hedging as it met the scope exception since 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 is 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. In accordance with the guidance in ASC 480, the Preferred dividend is to be charged against additional paid-in capital if there are no retained earnings available. As a result, approximately $1.1 million of the Discount was amortized in the first quarter of 2012 and is reflected as a Preferred dividend in the accompanying Condensed Consolidated Statements of Operations. Due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of Discount amortization will be accelerated to the conversion date as per the guidance of ASC 470 and reflected as a Preferred dividend in the Condensed Consolidated Statement of Operations for the three month period ended June 30, 2012.

12. EARNINGS PER COMMON SHARE

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


	Three Months Ended March 31,
	2012			2011
Basic

Net loss available to common stockholders	$	(34,424	)	$	(9,911	)

Weighted average basic number of common shares outstanding		68,816			26,120

Basic net loss per common share	$	(0.50	)	$	(0.38	)

Diluted

Net loss available to common stockholders	$	(34,424	)	$	(9,911	)

Weighted average basic number of common shares outstanding		68,816			26,120

Common stock equivalent shares representing shares issuable upon exercise or conversion		Anti-dilutive			—

Weighted average diluted number of common shares outstanding		68,816			26,120

Diluted loss per common share	$	(0.50	)	$	(0.38	)

Common stock equivalents of stock options, Preferred Stock, Warrants and the Note were not included in the computations of diluted earnings per share of common stock for the three months ended March 31, 2012, as the effect would have been anti-dilutive due to the net loss.

13. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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


	March 31, 2012			December 31, 2011
Accounts receivable:
Oil and natural gas revenues	$	10,023		$	9,519
Joint interest accounts		643			597
Other		185			172

	$	10,851		$	10,288

Prepaids and other:
Prepaid expenses	$	1,688		$	936
Other		3			1,793

	$	1,691		$	2,729

Accounts payable and accrued liabilities:
Trade payables	$	8,003		$	12,890
Revenues and royalties payable		8,614			8,564
Accrued interest expense		124			464
Accrued income taxes payable		479			406
Accrued employee compensation		3,823			1,600
Other		221			1,137

	$	21,264		$	25,061


	Three Months Ended March 31,
	2012			2011
General and administrative:
Share-based compensation	$	4,103		$	669
General and administrative, overhead and other		16,231			3,878

	$	20,334		$	4,547

Depletion, depreciation and accretion:
Depletion and depreciation	$	5,578		$	5,273
Accretion		401			402

	$	5,979		$	5,675

Interest expense and other, net:
Interest expense	$	13,038		$	6,550
Other income		(41	)		(48	)

	$	12,997		$	6,502

14. SUBSEQUENT EVENTS

Preferred Stock

On April 17, 2012, 4,444.4511 shares of Preferred Stock converted into 44,444,511 shares of common stock. See Note 11, “Stockholders’ Equity” for additional discussion on the terms of the Preferred Stock and its conversion to common stock.

Merger Agreement

On April 25, 2012, Halcón, a Delaware corporation, and GeoResources, Inc., a Colorado corporation (“GeoResources”), announced the execution of an Agreement and Plan of Merger, dated as of April 24, 2012 (the “Merger Agreement”), by and among Halcón, GeoResources, Leopard Sub I, Inc., a Colorado corporation and wholly owned subsidiary of Halcón (“Merger Sub”), and Leopard Sub II, LLC, a Delaware limited liability company and wholly owned subsidiary of Halcón (“Second Merger Sub”), pursuant to which Halcón has agreed to acquire all of the issued and outstanding shares of GeoResources common stock. Under the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved by the Boards of Directors of both Halcón and GeoResources, Merger Sub will merge with and into GeoResources, with GeoResources surviving as a direct wholly owned subsidiary of Halcón (the “Merger”), and shortly thereafter GeoResources will merge with and into Second Merger Sub, with Second Merger Sub surviving as a direct wholly owned subsidiary of Halcón (the “Second Merger”). The Merger and the Second Merger, taken together, are intended to qualify as a tax-free reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended, to the extent of the stock portion of the merger consideration received by shareholders of GeoResources.

The per share consideration is fixed in the Merger Agreement at $20.00 in cash and 1.932 shares of Halcón common stock for each issued and outstanding share of GeoResources common stock (excluding shares held by GeoResources in treasury, shares held by Halcón, Merger Sub, Second Merger Sub or GeoResources or any of their respective subsidiaries, and dissenting shares in accordance with Colorado law). Outstanding options to purchase GeoResources common stock may either be exercised immediately prior to the effective time of the Merger on a net cashless basis and converted into the right to receive the merger consideration or converted into options to purchase Halcón common stock; outstanding warrants to purchase GeoResources common stock will be assumed by Halcón and converted into warrants to acquire Halcón common stock; and issued and outstanding shares of restricted stock units of GeoResources will be settled through the issuance of one share of GeoResources common stock in respect of each restricted stock unit and thereafter converted into the right to receive the merger consideration.

Consummation of the transaction with GeoResources is conditioned upon, among other things, (1) approval by the stockholders of each of GeoResources and Halcón, (2) the receipt of all required regulatory approvals, (3) absence of any order or injunction prohibiting the consummation of the Merger, (4) subject to certain exceptions, the accuracy of representations and warranties with respect to GeoResources’ and Halcón’s business, as applicable, (5) receipt of customary tax opinions and (6) the effectiveness of a registration statement relating to the shares of Halcón common stock to be issued in the Merger. Subject to the satisfaction of the foregoing conditions, the Company expects the transaction to close during the third quarter of 2012.

The Merger Agreement contains certain termination rights and provides that, upon the termination of the Merger Agreement under specified circumstances, GeoResources will be required to pay Halcón a termination fee of approximately $27.8 million. In certain circumstances involving the termination of the Merger Agreement, GeoResources or Halcón will be obligated to reimburse the other’s expenses associated with the transaction in an aggregate amount not to exceed $10 million.

At the time of the execution of the Merger Agreement, certain officers and directors of GeoResources and certain of their affiliates (individually, a “Holder” and, collectively, the “Holders”) entered into a voting agreement with Halcón and Merger Sub providing that, among other things, unless earlier terminated, each Holder will vote the shares of GeoResources common stock owned by such Holder in favor of the approval and adoption of the Merger Agreement. As of the date of such agreement, the Holders owned approximately 17.1% of the issued and outstanding common stock of GeoResources. HALRES, LLC, a Delaware limited liability company, entered into a voting agreement with GeoResources providing that, among other things, unless earlier terminated, HALRES, LLC will vote the shares of Halcón common stock owned by HALRES, LLC in favor of the issuance of Halcón’s common stock to be issued in the Merger. As of the date of such agreement, HALRES, LLC owned approximately 51% of the issued and outstanding common stock of Halcón.

As of May 2, 2012, four putative class action lawsuits (the “Class Actions”) relating to the transactions contemplated in the Merger Agreement had been filed against GeoResources and its board of directors, Halcón and certain subsidiaries of Halcón and, in one lawsuit, HALRES LLC, a stockholder of Halcón. Each of the lawsuits has been brought by a purported stockholder of GeoResources and seeks certification of a class of all stockholders of GeoResources’ common stock. The lawsuits allege, among other things, that the members of GeoResources’ board of directors, aided and abetted by Halcón (and, in one lawsuit, HALRES LLC), breached their fiduciary duties to GeoResources’ stockholders by entering into the Merger Agreement for merger consideration that plaintiffs claim is inadequate pursuant to a process the plaintiffs claim to be flawed. The lawsuits seek, among other things, to enjoin the defendants from consummating the Merger on the agreed-upon terms or to rescind the Merger to the extent already implemented. We believe these suits are without merit and intend to vigorously defend against such claims.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 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. We have been active in our core producing areas of Texas, Oklahoma and Louisiana since our inception in 1987 and have grown through a balanced strategy of acquisitions, development and exploratory drilling.

Our oil and natural gas assets are characterized by a combination of developing and mature 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, the Woodbine, the Wilcox and the Mississippian Lime formations.

Our average daily oil and natural gas production decreased 6% in the first three months of 2012 compared to the same period in the prior year. During the first three months of 2012, we averaged 4,055 barrels of oil equivalent (“Boe”) per day compared to average daily production of 4,300 Boe per day during the first three months of 2011. The decrease in production compared to the prior year period is driven primarily by natural production declines. During the first quarter of 2012, we drilled or participated in the drilling of seven gross (7.0 net) wells of which were completed as wells capable of production and one gross (0.9 net) well was a dry hole, resulting in a success rate of 88%.

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 at economical costs is critical to our long-term success.

Recent Developments

Recapitalization

On February 8, 2012, HALRES LLC (formerly, “Halcón Resources, LLC”), a newly-formed 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. At closing, Floyd C. Wilson was appointed as our Chairman, President and Chief Executive Officer, and our name was changed to Halcón Resources Corporation. Mark Mize, former Executive Vice President and Chief Financial Officer of Petrohawk, was also appointed as our Executive Vice President, Chief Financial Officer, Treasurer and was designated as our Principal Accounting Officer, and the composition of our board was altered to consist of 10 new individuals: Floyd C. Wilson, Tucker S. Bridwell, James W. Christmas, Thomas R. Fuller, James L. Irish III, E. Murphy Markham IV, David B. Miller, Daniel Rioux, Stephen P. Smiley and Mark A. Welsh IV. Information as to our recent recapitalization is set forth under Note 2 to the Condensed Consolidated Financial Statements.

New Revolving Credit Facility

In connection with the closing of the recapitalization, we entered into a senior revolving credit agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A. (“JPMorgan”), as administrative agent, and other lenders on February 8, 2012. The Credit Agreement provides for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the Credit Agreement will initially 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 credit agreement may be paid down and re-borrowed during the five-year term of the revolver. The pricing on the Credit Agreement is LIBOR plus a margin ranging from 1.5% to 2.5% based on a percentage of usage. Advances under the Credit Agreement are secured by liens

on substantially all of our properties and assets. The 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. We are required to maintain commodity hedges on a rolling basis 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 March 31, 2012, we are in compliance with the financial debt covenants under the Credit Agreement. At March 31, 2012, we had no indebtedness outstanding under the $500.0 million credit agreement and $225.0 million of borrowing capacity available.

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 is 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. For the three month period ended March 31, 2012, we recorded a non-cash preferred dividend of $1.1 million to reflect amortization of the Discount. Due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of Discount amortization will be accelerated to the conversion date and reflected as a Preferred dividend for the three month period ended June 30, 2012.

Agreement and Plan of Merger with GeoResources, Inc.

On April 24, 2012, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with GeoResources, Inc., a Colorado corporation (“GeoResources”), pursuant to which we have agreed to acquire all of the issued and outstanding shares of GeoResources common stock in a cash and stock transaction that values GeoResources at approximately $1.0 billion based on the closing price of our common stock on April 24, 2012. The per share consideration is fixed in the Merger Agreement at $20.00 in cash and 1.932 shares of our common stock for each issued and outstanding share of GeoResources common stock.

The transaction has been approved by each company’s board of directors. Prior to closing, the transaction will require approval of each company’s shareholders. The transaction is expected to close in the third quarter of 2012 and is subject to customary regulatory approvals.

Prior to the merger, the Company and GeoResources will continue to operate as separate companies. Accordingly, except for specific references to the pending merger, the descriptions of strategy and outlook and the risks and challenges the Company faces, and the discussion and analysis of results of operations and financial condition set forth below relate solely to the Company. Additional details regarding the pending merger are discussed in Note 14 to the Condensed Consolidated Financial Statements, “Subsequent Events.”

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 areas we have determined are prospective for oil or liquids-rich resource plays. In addition to the assets held by GeoResources in the pending merger, we have identified several target resource plays for potential leasehold acquisition, including the Utica Shale/Point Pleasant formations in Ohio and Pennsylvania, the Mississippian Lime formation in Northern Oklahoma and Southern Kansas, the Wilcox formation in Southwest Louisiana and the Woodbine formation in East Texas. 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.

Our near-term capital spending requirements are expected to be funded with the proceeds from our recent financing activities, cash flows from operations, proceeds from potential asset dispositions and borrowings under our Credit Agreement. We strive to maintain financial flexibility while continuing our aggressive drilling plans and evaluating potential acquisitions, and will therefore likely access capital markets (if on acceptable terms) as necessary to, among other things, maintain substantial borrowing capacity under our 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 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.

Cash Flow

Our primary source of cash for the three months ended March 31, 2012 was from financing activities. Our primary sources of cash for the three months ended March 31, 2011 were from operating and financing activities. Proceeds from our recent convertible Preferred Stock offering and recapitalization, as well as borrowings under our 8% convertible note, were slightly offset by repayments of our previous credit facilities and cash used in investing activities to fund our drilling program and acquisition activities. Operating cash flow fluctuations were substantially driven by the increase in general and administrative and interest expense in the first quarter of 2012 as a result of the recapitalization, related change in control matters and the change in credit facilities during the first quarter of 2012. 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):


	Three Months Ended
	March 31,
	2012			2011
Cash flows provided by (used in) operating activities	$	(9,199	)	$	4,204
Cash flows used in investing activities		(28,378	)		(5,366	)
Cash flows provided by financing activities		723,311			1,167

Net increase in cash	$	685,734		$	5

Operating Activities. Net cash used in operating activities for the three months ended March 31, 2012 was $9.2 million as compared to cash provided by operating activities for the three months ended March 31, 2011 of $4.2 million.

The recapitalization, change in control and related activities which occurred during February 2012 resulted in a significant increase in general and administrative and interest expense which adversely affected operating cash flows. Operating cash flows of negative $9.2 million include cash used in operating activities of $1.5 million for expensing a prepayment fee in connection with the payoff of the former credit facilities, $1.8 million in share-based compensation expense for accelerated vesting of stock appreciation rights, $4.2 million in change in control payments to former management, $2.5 million for a consulting agreement termination fee, $0.8 million for legal fees, $0.4 million for derivatives novation fees and $2.4 million of various other charges, all related to the recapitalization and change in control.

Investing Activities. The primary driver of cash used in investing activities is capital spending, inclusive of acquisitions net of dispositions. Cash used in investing activities was $28.4 million and $5.4 million for the three months ended March 31, 2012 and 2011, respectively.

During the first three months of 2012, we spent $24.0 million on oil and natural gas capital expenditures, $16.4 million of which was for unproved leasehold property costs. We participated in the drilling of eight gross (7.9 net) wells and spent an additional $0.6 million on other operating property and equipment capital expenditures. We also had funds held in escrow of approximately $3.8 million related to leasehold acquisitions.

During the first three months of 2011, we spent $5.6 million on oil and natural gas capital expenditures. During the quarter ended March 31, 2011, we participated in the drilling of 15 gross (12.3 net) wells, of which six gross (6.0 net) wells were capable of production. Nine gross (6.3 net) wells were either drilling, testing or waiting on completion as of March 31, 2011. We spent an additional $0.2 million on other operating property and equipment capital expenditures. Proceeds from sales of oil and gas properties were $0.5 million for the three months ended March 31, 2011.

Financing Activities. Net cash flows provided by financing activities were $723.3 million and $1.2 million for the three months ended March 31, 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 a credit agreement with JPMorgan, as administrative agent, and the other lenders named therein on February 8, 2012. The credit agreement provides for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the credit agreement will initially mature on February 8, 2017. We did not utilize any of the funds available under the credit facility during the first quarter of 2012; however, we incurred $2.0 million of debt issuance costs in conjunction with the issuance of the credit agreement, and $2.5 million of debt issuance costs in connection with the convertible note.

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 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 $18.0 million in equity issuance costs during the three months ended March 31, 2012.

Capital financing was used to repay borrowings under our previous credit facilities. During the first quarter 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 quarter of 2011, we refinanced our previous credit facilities, which resulted in $7.9 million in net borrowings on long-term debt offset by $6.7 million in payments for deferred loan costs.

All restricted stock awards were vested as a result of the change in control in February 2012. We repurchased $2.1 million in common stock from participants under our 2006 Long-term Incentive Plan to net settle the related withholding tax liability.

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. 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.

Results of Operations

Three Months Ended March 31, 2012 and 2011

We reported a net loss of $33.3 million for the three months ended March 31, 2012 compared to a net loss of $9.9 million for the same period in 2011, resulting in an increase in the net loss of $23.4 million. The following tables summarize key items of comparison and their related change for the periods indicated.


	Three Months Ended
	March 31,
In thousands	2012			2011			Change
Net loss	$	(33,322	)	$	(9,911	)	$	(23,411	)
Operating revenues:
Oil		22,997			20,412			2,585
Natural gas		1,668			2,892			(1,224	)
NGLs		2,169			2,415			(246	)
Other revenue		36			51			(15	)
Operating expenses:
Production:
Lease operating		8,668			8,375			293
Taxes		1,570			1,411			159
General and administrative:
General and administrative		16,231			3,878			12,353
Share-based compensation		4,103			669			3,434
Restructuring costs		104			—			104
Depletion, depreciation and amortization:
Depletion — Full cost		5,362			5,024			338
Depreciation — Other		216			249			(33	)
Accretion expense		401			402			(1	)
Other expenses, net:
Net loss on derivative contracts		(4,945	)		(14,250	)		9,305
Interest expense		(13,038	)		(6,550	)		(6,488	)
Other income		41			48			(7	)
Loss before income taxes		(27,727	)		(14,990	)		(12,737	)
Income tax provision (benefit)		5,595			(5,079	)		10,674


	Three Months Ended
	March 31,
In thousands (except per unit and per Boe amounts)	2012			2011			Change

Production:
Oil (MBbls)		226			222			4
Natural gas (MMcf)		615			710			(95	)
NGLs (MBbls)		40			47			(7	)
Total per MBoe		369			387			(18	)
Average daily production (Boe)		4,055			4,300			(245	)

Average price per unit:
Oil (Bbl)	$	101.76		$	91.95		$	9.81
Natural gas (Mcf)		2.71			4.07			(1.36	)
NGLs (Bbl)		54.23			51.38			2.85
Total per Boe		72.72			66.46			6.26

Cash effect of derivative contracts per unit:
Oil (Bbl)	$	(0.62	)	$	(4.58	)	$	3.96
Natural gas (Mcf)		1.16			2.61			(1.45	)
NGLs (Bbl)		—			—			—
Total per Boe		1.56			2.16			(0.60	)

Average prices computed after cash effect of settlement of derivative contracts per unit:
Oil (Bbl)	$	101.14		$	87.37		$	13.77
Natural gas (Mcf)		3.87			6.68			(2.81	)
NGLs (Bbl)		54.23			51.38			2.85
Total per Boe		74.28			68.62			5.66

Average cost per Boe:
Production:
Lease operating	$	23.49		$	21.64		$	1.85
Taxes		4.25			3.65			0.60
General and administrative:
General and administrative		43.99			10.02			33.97
Share-based compensation		11.12			1.73			9.39
Restructuring costs		0.28			—			0.28
Depletion		14.53			12.98			1.55

For the three months ended March 31, 2012, oil and natural gas revenues increased $1.1 million from the same period in 2011. The increase was primarily due to higher realized average prices during the 2012 period. Increased realized average price of $6.26 per Boe contributed approximately $2.3 million in revenues for the three months ended March 31, 2012. The increase was partially offset by a decrease in production of 18 MBoe or 5%, which resulted in a $1.2 million decline in oil and natural gas revenues.

Lease operating expenses increased $0.3 million for the three months ended March 31, 2012 primarily due to higher workover expenses and repairs 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 $23.49 per Boe in 2012 compared to $21.64 per Boe in 2011.

Oil and natural gas production taxes increased $0.2 million for the three months ended March 31, 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 increase is primarily due to an increase in oil and natural gas sales for the quarter ended March 31, 2012 compared to the same period in 2011. As a percentage of revenue, oil and natural gas production tax was 6% for the first quarter of 2012 compared to 5% for the first quarter of 2011.

General and administrative expense for the three months ended March 31, 2012 increased $12.4 million to $16.2 million as compared to the same period in 2011, largely reflecting the impact of the recapitalization that included charges of approximately $5.4 million for change in control payments and $2.5 million for engagement termination fees coupled with higher professional fees of approximately $1.0 million related in an increase in corporate activities subsequent to the recapitalization. The remainder of the increase is primarily attributable to higher payroll and employee related costs in support of the expanding business base.

Share-based compensation expense for the quarter ended March 31, 2012 was $4.1 million, an increase of $3.4 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.

We incurred $0.1 million in restructuring costs for the three months ended March 31, 2012 related to the 2012 restructuring to close the Plano, Texas office and began the process of relocating key administrative functions to Houston, Texas. There were no restructuring costs incurred for the three months ended March 31, 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 volume for the current period to total remaining reserve volume for the evaluated properties. Depletion expense increased $0.3 million for the three months ended March 31, 2012 from the same period in 2011, to $5.4 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 $14.53 per Boe for the quarter ended March 31, 2012 compared to $12.98 per Boe for the quarter ended March 31, 2011.

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 year, 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 March 31, 2012, we had a $5.7 million net derivative liability, $1.6 million which was classified as current, and $4.1 million of which was classified as noncurrent. We recorded a net derivative loss of $4.9 million, all of which was unrealized loss, for the three months ended March 31, 2012 compared to a net derivative loss of $14.3 million ($15.1 million net unrealized loss and $0.8 million net realized gain for cash received on settled contracts and premium costs) in the same period in 2011.

Interest expense increased $6.5 million for the three months ended March 31, 2012 compared to the same period in 2011. The increase is due to the expensing of $7.3 million in unamortized debt issuance costs and prepayment fee in connection with the payoff of the former credit facilities in our recapitalization, partially offset by lower interest rates in the 2012 period.

Based on the estimated effective annual tax rate, we recorded a tax provision of $5.6 million on pre-tax loss of $27.7 million for the three months ended March 31, 2012. We calculated an estimated negative effective annual tax rate for the current annual reporting period, excluding any discrete items, of 15.4% as of March 31, 2012. We have a discrete item of $1.3 million related to the reduction in net operating losses due to additional limitations created by our recapitalization in February 2012. This event

created an “ownership change”, and as a result our net operating losses will be subject to additional limitations. The discrete item for the first quarter of 2012 increases our negative effective tax rate to 20.2%. The negative tax rate reflected for the three months ended March 31, 2012 is primarily due to a Federal income tax limitation on the deductibility of the interest expense on the 8% senior convertible note that was issued as part of the recapitalization. The estimated annual rate differs from the statutory rate primarily due to the estimate of state income taxes and non-deductible expenses for the period. For the three months ended March 31, 2011, we recorded income tax benefit of $5.1 million on a pre-tax loss of $15.0 million, resulting in an effective tax rate of 34%.

Recently Issued Accounting Pronouncements

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. When oil 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. During the quarter ended March 31, 2012, two of our purchasers accounted for $19.6 million, or approximately 73%, 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 quarter ended March 31, 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 approximately 60% to 70% of our current and anticipated production for the next 12 to 36 months. At March 31, 2012, our commodity hedging represented approximately 62% of our current and anticipated production through June 30, 2014. Our hedge policies and objectives may change significantly as commodities prices or price futures change.

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. Condensed Consolidated Financial Statements (Unaudited) — Note 10, “Derivatives” for additional information.

Based on March 31, 2012 NYMEX forward curves of natural gas and crude oil futures prices, adjusted for volatility by 150 basis points, we would expect to pay future cash payments of $5.7 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 $5.0 million, and if future prices were to increase by 10%, we would expect to pay future cash payments of $18.2 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. Condensed Consolidated Financial Statements (Unaudited) — Note 10, “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 March 31, 2012, we had no borrowings under our Senior Revolving Credit Agreement, which bears interest at LIBOR plus 150 to 250 basis points. We had $231.4 million in long-term debt net of discount related to an 8% convertible note. Fluctuations in market interest rates will cause our annual interest costs on borrowings under our Senior Revolving 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 March 31, 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 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 March 31, 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

Note 14 “Subsequent Events” to the Unaudited Condensed Consolidated Financial Statements sets forth information regarding the execution of a Merger Agreement on April 24, 2012, pursuant to which Halcón has agreed to acquire all of the issued and outstanding shares of common stock of GeoResources, Inc. As of May 2, 2012, four putative class action lawsuits (the “Class Actions”) relating to the transactions contemplated in the Merger Agreement had been filed against GeoResources and its board of directors, Halcón and certain subsidiaries of Halcón and, in one lawsuit, HALRES LLC, a stockholder of Halcón. On April 26, 2012, Hilary Coyne filed a purported class action lawsuit in the 24th Judicial District Court of Harris County, Texas against GeoResources, its board of directors, Halcón and certain of its subsidiaries. On April 30, 2012, Bruno Eisner filed a purported class action lawsuit in the District Court of Harris County, Texas against GeoResources, its board of directors, Halcón and certain of its subsidiaries. On May 1, 2012, George Assad filed a purported class action lawsuit in the District Court of Harris County, Texas against GeoResources, its board of directors, and Halcón. On May 2, 2012, Vernon and Roberta Futterman filed a purported class action lawsuit in the 61st Judicial District Court of Harris County, Texas against GeoResources, its board of directors, Halcón, certain of its subsidiaries and HALRES, LLC. Each of the lawsuits has been brought by a purported stockholder of GeoResources and seeks certification of a class of all stockholders of GeoResources’ common stock. The lawsuits allege, among other things, that the members of GeoResources board of directors, aided and abetted by Halcón (and, in the Futterman lawsuit, HALRES, LLC), breached their fiduciary duties to GeoResources’ stockholders by entering into the Merger Agreement for merger consideration that plaintiffs claim is inadequate pursuant to a process the plaintiffs claim to be flawed. The lawsuits seek, among other things, to enjoin the defendants from consummating the Merger on the agreed-upon terms or to rescind the Merger to the extent already implemented. We believe these suits are without merit and intend to vigorously defend against such claims.

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 the risk factors which could materially affect our business, financial condition or future results. There have been no material changes to the risk factors described in the Company’s Annual Report on Form 10-K, for the year ended December 31, 2012, except as stated below.

We and GeoResources may be unable to obtain the regulatory clearances and approvals, or satisfy other closing conditions required to complete the merger.

Our acquisition of GeoResources is subject to various conditions, including regulatory approvals and that there be no statute, rule, order, decree or regulation by a governmental authority in effect or promulgated that temporarily, preliminarily or permanently restrains, precludes, enjoins or otherwise prohibits the transactions contemplated by the Merger Agreement. We can provide no assurance that all required regulatory approvals will be obtained or that these approvals will not contain terms, conditions or restrictions, such as the divestiture of assets or lines of business, that would be detrimental to us after the effective time of the merger.

The completion of the merger is also subject to other closing conditions beyond our control and GeoResources that may prevent, delay or otherwise materially adversely affect its completion. These conditions include, among other things, the approval by our stockholders of the issuance of common stock related to the merger, the adoption and approval by GeoResources’ stockholders of the merger agreement, that neither party has undergone a material adverse effect, which for our purposes includes Floyd C. Wilson’s death or disability at any time prior to completion of the merger, and the effectiveness of the registration statement related to our common stock issued in conjunction with the merger. We cannot predict whether or when the conditions required to complete the merger will be satisfied.

Failure to complete the merger could negatively affect the trading price of our common stock and our future business and financial results.

Completion of the merger is not assured and is subject to risks, including the risks that approval of the transaction by our stockholders, the stockholders of GeoResources or by governmental agencies is not obtained or that other closing conditions are not satisfied. If the merger is not completed, it could negatively affect the trading price of our common stock and our future business and financial results, and we will be subject to several risks, including the following:

•

having to pay certain significant costs relating to the merger;

•

negative reactions from the financial markets, including declines in the price of our common stock due to the fact that current prices may reflect a market assumption that the merger will be completed; and

•

the attention of our management will have been diverted to the merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

If completed, the Company’s merger with GeoResources may not achieve its intended results.

The Company and GeoResources entered into the Merger Agreement with the expectation that the merger would result in various benefits, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business of GeoResources is integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result 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.

We and GeoResources may have difficulty attracting, motivating and retaining executives and other employees in light of the merger.

Uncertainty about the effect of the merger on GeoResources’ employees and our employees may have an adverse effect on GeoResources and us and consequently the combined company. This uncertainty may impair the respective company’s ability to attract, retain and motivate personnel until the merger is completed. Employee retention may be particularly challenging during the pendency of the merger, as employees may feel uncertain about their future roles with the combined company. If employees of GeoResources or our employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined company, the combined company’s ability to realize the anticipated benefits of the merger could be reduced.

We will incur substantial transaction and merger-related costs in connection with the merger and our stockholders will be diluted by the merger.

We expect to incur a number of non-recurring transaction and merger-related costs associated with completing the merger with GeoResources, combining the operations of the two companies and achieving desired synergies. These fees and costs will be substantial. Additional unanticipated costs may be incurred in the integration of our company’s businesses and GeoResources. Although we expect the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, this net benefit may not be achieved in the near-term, or at all.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

On March 5, 2012, we sold 4,444.4511 shares of our preferred stock, each share convertible into 10,000 shares of common stock, for gross proceeds of approximately $400.0 million, or $9.00 per share of common stock. We incurred placement agent fees totaling approximately $14.0 million and associated expenses of approximately $0.5 million in connection with this offering. The preferred stock converted automatically into 44,444,511 shares of common stock on April 17, 2012. The preferred stock was offered and sold pursuant to the exemptions from registration provided in Regulation D, Rule 506, under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). The preferred stock was offered (i) to institutional “accredited investors” (as defined in Rule 501(a) under the Securities Act), who either (a) are “qualified institutional buyers” as defined in Rule 144A under the Securities Act or (b) own and invest on a discretionary basis, for their own accounts or the accounts of others, an amount of securities equal to at least $25.0 million (calculated in accordance with the provisions of Rule 144A) and (ii) to certain other accredited investors specifically approved by Halcón and the placement agents.

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	Description	Method of Filing

2.1	Securities Purchase Agreement dated December 21, 2011 by and between RAM Energy Resources, Inc. and Halcón Resources LLC	(22) [2.1]

2.1.1	First Amendment to Securities Purchase Agreement dated January 4, 2012 by and between RAM Energy Resources, Inc. and Halcón Resources LLC	(23) [2.1.1]

2.2	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.	(28) [2.1]

3.1	Amended and Restated Certificate of Incorporation of RAM Energy Resources, Inc. dated February 8, 2012	(24) [3.1]

3.1.1	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of February 10, 2012	(24) [3.2]

3.1.2	Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated March 2, 2012	(25) [3.1]

3.2	Second Amended and Restated Bylaws of RAM Energy Resources, Inc.	(23) [3.2]

4.1	Convertible Promissory Note, dated February 8, 2012, between RAM Energy Resources, Inc. and Halcón Resources LLC	(24) [4.1]

4.2	Warrant Certificate, dated February 8, 2012, between RAM Energy Resources, Inc. and Halcón Resources LLC	(24) [4.2]

4.3	Registration Rights Agreement, dated February 8, 2012, between RAM Energy Resources, Inc. and Halcón Resources LLC	(24) [4.3]

4.4	Registration Rights Agreement, dated March 5, 2012, between Halcón Resources Corporation and Barclays Capital, Inc.	(25) [4.1]

10.1	Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006	(1) [10.15]

10.1.1**	First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006	(3) [10.1]

10.1.2**	Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008	(6) [10.2]

10.1.3**	Third Amendment to Employment Agreement of Larry E. Lee dated December 30, 2008	(9) [10.6.3]

10.1.4**	Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009	(10) [10.6.4]

10.1.5**	Fifth Amendment to Employment Agreement of Larry E. Lee dated March 17, 2010	(13) [10.2.6]

10.1.6**	Sixth Amendment to Employment Agreement of Larry E. Lee dated March 8, 2011	(17) [10.2.6]

10.2	Agreement between RWG Energy, Inc. and Shell Trading (US) Co dated February 1, 2006	(1) [10.22]

10.3	Gas Purchase Contract between Four Sevens Oil Company, Ltd., J W Energy Company, Ltd. and Dynegy NGL, Inc. dated January 30, 1998	(1) [10.23]

10.3.1	Amendment to Purchase Contract between RWG Energy, Inc. and Targa North Texas LP dated effective as of April 1, 2006	(4) [10.23.1]

10.4**	RAM Energy Resources, Inc. Long-Term Incentive Plan	(2) [Annex C]

10.4.1**	First Amendment to the RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 8, 2008	(7) [Exhibit A]

10.4.2**	Second Amendment to the RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 3, 2010	(14) [10.8.2]

10.4.3**	Third Amendment to the RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan	(24) [10.3]

10.5	Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders	(5) [10.1]






10.5.1	First Amendment to Loan Agreement dated February 6, 2009, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders	(11) [10.17.1]



10.5.2	Second Amendment to Loan Agreement dated June 26, 2009, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders	(12) [10.17.2]

10.5.3	Third Amendment to Loan Agreement dated November 29, 2010, effective December 3, 2010, by and between RAM Energy Resources, Inc., as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders	(16) [10.8.3]

10.6**	Description of Compensation Arrangement with G. Les Austin	(8) [10.18]

10.6.1**	First Amendment to Employment Agreement of G. Les Austin dated December 30, 2008	(9) [10.18.1]

10.6.2**	Second Amendment to Employment Agreement of G. Les Austin, dated March 23, 2011	(20) [10.11.2]

10.7	Change in Control Separation Benefit Plan of Ram Energy Resources, Inc. and Participating Subsidiaries	(11) [10.19]

10.8	Purchase and Sale Agreement dated October 29, 2010, by and between RWG Energy, Inc., as Seller, and Milagro Producing, LLC, as Buyer	(15) [10.13]

10.9	Revolving Credit Agreement dated March 14, 2011 among RAM Energy Resources, Inc., as Borrower, SunTrust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders	(18) [10.14]

10.9.1	First Amendment to Revolving Credit Agreement dated as of June 10, 2011, by and between RAM Energy Resources, Inc., as Borrower, and Sun Trust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders	(21) [10.14.1]

10.10	Second Lien Term Loan Agreement dated March 14, 2011 among RAM Energy Resources, Inc., as Borrower, Guggenheim Corporate Funding, LLC, as Administrative Agent, and the financial institutions named therein as the Lenders	(18) [10.15]

10.11	Equity Distribution Program Distribution Agreement, dated March 17, 2011	(19) [1.1]

10.12	Senior Revolving Credit Agreement, dated as of February 8, 2012, among Halcón Resources Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A. as Syndication Agent, Bank of Montreal, as Documentation Agent, and the Lenders Party thereto	(24) [10.1]

10.13	Guarantee and Collateral Agreement, dated February 8, 2012, among the Grantors named therein and JPMorgan Chase Bank, N.A., as Administrative Agent	(24) [10.2]

10.14**	Summary of Non-Employee Director Compensation	(26) [10.1]

10.15**	Stock Ownership Guidelines Policy	(26) [10.2]

10.16**	Form of Indemnity Agreement, dated as of March 13, 2012	(27) [10.1]

10.17	Voting Agreement, dated as of April 24, 2012 by and between GeoResources, Inc. and HALRES, LLC	(28) [10.1]

10.18	Voting Agreement, dated as of April 24, 2012 by and among Halcón Resources Corporation, Leopard Sub I, Inc. and each of the Persons listed on Schedule A thereto	(28) [10.2]

10.19	Confidential Information, Non-Competition and Non-Solicit Agreement, dated April 24, 2012 by and between Halcón Resources Corporation and Frank A. Lodzinski	(28) [10.3]

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.

**	Management contract or compensatory plan or arrangement.

***

Furnished with this report. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.



(1)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on May 12, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(2)		Included as an annex to the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, as the annex letter indicated in brackets and incorporated by reference herein.

(3)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K on October 20, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(4)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K on June 5, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(5)		Filed as an exhibit to Registrant’s Form 8-K dated December 5, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(6)		Filed as an exhibit to Registrant’s Form 8-K dated February 28, 2008, as the exhibit number indicated in brackets and incorporated by reference herein.

(7)		Filed as an exhibit to Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 14, 2008, as the exhibit number indicated in brackets and incorporated by reference herein.

(8)		Filed as an exhibit to Registrant’s Form 10-Q dated May 9, 2008, as the exhibit number indicated in brackets and incorporated by reference herein.

(9)		Filed as an exhibit to Registrant’s Form 8-K dated January 5, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

(10)		Filed as an exhibit to Registrant’s Form 8-K dated March 25, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

(11)		Filed as an exhibit to Registrant’s Annual Report on Form 10-K filed on March 12, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

(12)		Filed as an exhibit to Registrant’s Form 8-K filed July 2, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

(13)		Filed as an exhibit to Registrant’s Form 8-K filed March 18, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(14)		Filed as an exhibit to Registrant’s Form 8-K filed May 7, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(15)		Filed as an exhibit to Registrant’s Form 8-K filed November 2, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(16)		Filed as an exhibit to Registrant’s Form 8-K filed December 8, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(17)		Filed as an exhibit to Registrant’s Form 8-K filed March 10, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(18)		Filed as an exhibit to Registrant’s Form 10-K filed March 16, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(19)		Filed as an exhibit to Registrant’s Form 8-K filed March 18, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(20)		Filed as an exhibit to Registrant’s Form 8-K filed March 24, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.



(21)		Filed as an exhibit to Registrant’s Form 8-K filed June 15, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(22)		Filed as an exhibit to Registrant’s Form 8-K filed December 22, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(23)		Filed as an exhibit to Registrant’s Form 8-K filed January 5, 2012, as the exhibit number indicated in brackets and incorporated by reference herein.

(24)		Filed as an exhibit to Registrant’s Form 8-K filed February 9, 2012, as the exhibit number indicated in brackets and incorporated by reference herein.

(25)		Filed as an exhibit to Registrant’s Form 8-K filed March 5, 2012, as the exhibit number indicated in brackets and incorporated by reference herein.

(26)		Filed as an exhibit to Registrant’s Form 8-K filed March 8, 2012, as the exhibit number indicated in brackets and incorporated by reference herein.

(27)		Filed as an exhibit to Registrant’s Form 8-K filed March 19, 2012, as the exhibit number indicated in brackets and incorporated by reference herein.

(28)		Filed as an exhibit to Registrant’s Form 8-K filed April 25, 2012, as the exhibit number indicated in brackets and incorporated by reference herein.

SIGNATURES

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


	HALCÓN RESOURCES CORPORATION

May 8, 2012	By:	/s/ FLOYD C. WILSON
	Name:	Floyd C. Wilson
	Title:	Chairman of the Board, President and Chief Executive Officer

May 8, 2012	By:	/s/ MARK J. MIZE
	Name:	Mark J. Mize
	Title:	Executive Vice President and Chief Financial Officer

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