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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(X) Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period ended June 30, 2012

Commission File Number – 0-8041

LOGO

GEORESOURCES, INC.

(Exact name of registrant as specified in its charter)

Colorado

84-0505444

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

110 Cypress Station Drive, Suite 220

Houston, Texas

77090-1629

(Address of principal executive offices)

(Zip code)

(281) 537-9920

(Registrant’s telephone number, including area code)

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 12 months (or for such shorter period that the registration 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 ¨

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class of equity		Outstanding at July 31, 2012
Common stock, par value $.01 per share		25,703,102 shares

TABLE OF CONTENTS


	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements.

	Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011.	4

	Consolidated Statements of Income for the Three and Six Months ended June 30, 2012 and 2011.	6

	Consolidated Statements of Comprehensive Income for the Three and Six Months ended June 30, 2012 and 2011.	7

	Consolidated Statement of Stockholders’ Equity for the Six Months ended June 30, 2012.	8

	Consolidated Statements of Cash Flows for the Six Months ended June 30, 2012 and 2011.	9

	Notes to Consolidated Financial Statements.	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	34

Item 4.	Controls and Procedures.	35

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.	36

Item 1A.	Risk Factors.	36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	36

Item 3.	Defaults Upon Senior Securities.	36

Item 4.	Mine Safety Disclosures.	36

Item 5.	Other Information.	36

Item 6.	Exhibits.	37

	Signatures.	38

EXPLANATORY NOTE

On August 1, 2012, GeoResources, Inc., a Colorado corporation (the “Company”), completed the previously announced merger with Leopard Sub I, Inc. (“Merger Sub”), a Colorado corporation and wholly-owned subsidiary of Halcón Resources Corporation, a Delaware corporation (“Halcón”), whereby Merger Sub merged with and into the Company with the Company continuing as the surviving corporation (the “Merger”). Immediately following the effective time of the Merger, the Company merged (the “Second Merger”) with and into Leopard Sub II, LLC (“Second Merger Sub”), a Delaware limited liability company and wholly-owned subsidiary of Halcón with Second Merger Sub continuing as the surviving entity and a wholly-owned subsidiary of Halcón. Following the effectiveness of the Second Merger, the Second Merger Sub amended its certificate of formation and changed its name to Halcón Geo Holdings LLC. The Merger and the Second Merger were effected pursuant to that certain Agreement and Plan of Merger, dated as of April 24, 2012 and as amended on June 22, 2012, by and among the Company, Halcón, Merger Sub and Second Merger Sub.

This Quarterly Report on Form 10-Q of the Company for the period ended June 30, 2012, is being filed by its successor company, Halcón Geo Holdings LLC. The financial information in this Quarterly Report and the accompanying management’s discussion and analysis reflect the corporate status of the reporting entity as it was at June 30, 2012.

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	June 30, 2012			December 31, 2011
	(unaudited)
ASSETS
Current assets:
Cash	$	40,289		$	39,144
Accounts receivable:
Oil and gas revenues		29,027			26,485
Joint interest billings and other, less allowance for doubtful accounts of $579 and $609, respectively		36,419			21,328
Affiliated partnerships		581			371
Notes receivable		476			545
Derivative financial instruments		8,311			4,037
Income taxes receivable		7,849			7,753
Prepaid expenses and other		4,211			3,681

Total current assets		127,163			103,344

Oil and gas properties, successful efforts method:
Proved properties		577,093			428,871
Unproved properties		58,304			44,613
Office and other equipment		1,961			1,675
Land		146			146

		637,504			475,305
Less accumulated depreciation, depletion and amortization		(117,715	)		(96,753	)

Net property and equipment		519,789			378,552

Equity in oil and gas limited partnerships		1,668			2,240
Derivative financial instruments		2,189			868
Deferred financing costs and other		2,502			2,687

	$	653,311		$	487,691

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	June 30, 2012		December 31, 2011
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	32,357	$	25,483
Accounts payable to affiliated partnerships		1,679		3,597
Revenue and royalties payable		25,201		17,043
Drilling advances		18,024		12,965
Accrued expenses		10,159		5,073
Derivative financial instruments		—		2,890

Total current liabilities		87,420		67,051

Long-term debt		80,000		—
Deferred income taxes		67,517		44,389
Asset retirement obligations		9,587		7,940
Stockholders’ equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 25,639,622 in 2012 and 25,595,930 in 2011		256		256
Additional paid-in capital		284,673		281,515
Accumulated other comprehensive income		6,263		1,069
Retained earnings		117,595		85,471

Total stockholders’ equity		408,787		368,311

		653,311	$	487,691

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except share and per share amounts)

(unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenue:
Oil and gas revenues	$	51,797		$	29,292		$	94,361		$	55,906
Partnership management fees		143			131			244			242
Property operating income		748			923			2,553			1,361
Gain on sale of property and equipment		15,108			1			15,110			737
Partnership income		104			505			395			915
Interest and other		409			28			440			358

Total revenue		68,309			30,880			113,103			59,519
Expenses:
Lease operating expense		7,919			5,747			15,171			10,766
Production taxes		3,258			1,898			6,080			3,519
Re-engineering and workovers		1,020			709			1,792			1,103
Exploration expense		2			124			281			356
General and administrative expense		8,394			2,962			13,041			5,562
Depreciation, depletion and amortization		13,616			6,348			23,390			11,928
Hedge ineffectiveness		(164	)		(1,561	)		(98	)		641
Interest		760			452			1,169			1,038

Total expense		34,805			16,679			60,826			34,913

Income before income taxes		33,504			14,201			52,277			24,606

Income tax expense (benefit):
Current		2,124			641			219			798
Deferred		10,676			4,781			19,934			8,716

		12,800			5,422			20,153			9,514

Net income	$	20,704		$	8,779		$	32,124		$	15,092

Less: Net loss attributable to GeoResources, Inc.		—			(87	)		—			(87	)

Net income attributable to GeoResources, Inc.	$	20,704		$	8,866		$	32,124		$	15,179

Net income per share (basic)	$	0.81		$	0.35		$	1.25		$	0.61

Net income per share (diluted)	$	0.79		$	0.34		$	1.23		$	0.60

Weighted average shares outstanding:
Basic		25,633,832			25,460,622			25,622,254			24,778,182

Diluted		26,159,756			25,861,849			26,114,113			25,271,578

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(unaudited)


	Three Months Ended June 30,
	2012			2011
Net income	$	20,704		$	8,779
Other comprehensive income, net of tax:
Changes in fair market value of hedged positions, net of taxes of $5,124 and $2,602, respectively		8,332			4,318
Net realized hedging (gain) loss charge to income, net of taxes of $608 and $666, respectively		(989	)		1,106

Total other comprehensive income, net of tax		7,343			5,424

Comprehensive Income		28,047			14,203
Comprehensive loss attributable to noncontrolling interest		—			(87	)

Comprehensive income attributable to GeoResources, Inc.	$	28,047		$	14,290


	Six Months Ended June 30,
	2012			2011
Net income	$	32,124		$	15,092
Other comprehensive income, net of tax:
Changes in fair market value of hedged positions, net of taxes of $3,780 and $484, respectively		6,146			(804	)
Net realized hedging (gain) loss charge to income, net of taxes of $586 and $944, respectively		(952	)		1,566

Total other comprehensive income, net of tax		5,194			762

Comprehensive Income		37,318			15,854
Comprehensive loss attributable to noncontrolling interest		—			(87	)

Comprehensive income attributable to GeoResources, Inc.	$	37,318		$	15,941

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

Six Months Ended June 30, 2012

(In thousands, except share data)

(unaudited)


	Common Stock				Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total
	Shares		Par value		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total
Balance, December 31, 2011		25,595,930	$	256	$	281,515	$	85,471	$	1,069	$	368,311
Exercise of employee stock options		39,062		—		431						431
Vesting of restricted stock		4,630		—		—						—
Excess tax benefit from share-based compensation						299						299
Net income								32,124				32,124
Other comprehensive income, net of taxes, $3,194										5,194		5,194
Equity based compensation expense						2,428						2,428

Balance, June 30, 2012		25,639,622	$	256	$	284,673	$	117,595	$	6,263	$	408,787

The accompanying notes are an integral part of this statement.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)


	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	32,124		$	15,092
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		23,390			11,928
Gain on sale of property and equipment		(15,110	)		(737	)
Accretion of asset retirement obligations		226			224
Hedge ineffectiveness (gain) loss		(98	)		641
Partnership income		(395	)		(915	)
Partnership distributions		967			465
Deferred income taxes		19,934			8,716
Settlement of asset retirement liability		(41	)		—
Non-cash compensation		2,428			810
Excess tax benefit from share-based compensation		(299	)		(2,125	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(17,419	)		(21,705	)
(Increase) decrease in prepaid expense and other		(432	)		(789	)
(Decrease) increase in accounts payable and accrued expense		23,258			26,777

Net cash provided by operating activities		68,533			38,382
Cash flows from investing activities:
Proceeds from sale of property and equipment		20,399			345
Additions to property and equipment		(168,517	)		(42,440	)

Net cash used in investing activities		(148,118	)		(42,095	)
Cash flows from financing activities:
Proceeds from stock options exercised		431			5,022
Issuance of common stock		—			122,486
Excess tax benefit from share-based compensation		299			2,125
Issuance of long-term debt		80,000			—
Reduction of long-term debt		—			(87,000	)

Net cash provided by financing activities		80,730			42,633

Net increase in cash and cash equivalents		1,145			38,920

Cash and cash equivalents at beginning of period		39,144			9,370

Cash and cash equivalents at end of period	$	40,289		$	48,290

Supplementary information:
Interest paid	$	753		$	485
Income taxes paid	$	16		$	627

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE A: Organization and Basis of Presentation

Description of Operations

GeoResources, Inc. (“GeoResources” or the “Company”) operates a single business segment involved in the acquisition, development and production of, and exploration for, crude oil, natural gas and related products primarily in Texas, North Dakota, Louisiana, Oklahoma, Montana and Colorado. On July 31, 2012, the stockholders of GeoResources and Halcón Resources Corporation (“Halcón”) approved the merger of GeoResources into a subsidiary of Halcón. On August 1, 2012 Halcón acquired all of the issued and outstanding shares of common stock of the Company. See Note M “Subsequent Events” for discussion of the merger.

Consolidated Financial Statements

The unaudited consolidated financial statements include the accounts of GeoResources and its majority-owned subsidiaries. We consolidated our non-controlling interest in Trigon Energy Partners, LLC, a Delaware limited liability company (“Trigon”) until September 2011, at which time we deconsolidated the non-controlling interest due to a distribution of all of Trigon’s assets to Trigon’s owners. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. Our 2011 Annual Report on Form 10-K and 10-K/A includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in GeoResources’ 2011 Annual Report on Forms 10-K and 10-K/A. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to common shares by the basic weighted-average shares of common stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents. Dilutive common stock equivalents consist of unvested restricted stock unit awards, warrants to purchase common stock, and outstanding stock options. The number of potential common shares outstanding relating to stock options, warrants to purchase common stock, and restricted stock units is computed using the treasury stock method. Net income per share computations reconciling basic and diluted net income for the three and six months ended June 30, 2012 and 2011 consist of the following (in thousands, except per share data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Numerator:
Net income attributable to GeoResources, Inc. common shares	$	20,704	$	8,866	$	32,124	$	15,179
Denominator:
Basic weighted average shares		25,634		25,461		25,622		24,778
Effect of dilutive securities - share-based compensation		478		401		471		494
Effect of dilutive securities - warrants to purchase common stock		48		—		21		—

Diluted weighted average shares		26,160		25,862		26,114		25,272
Earnings per share
Basic	$	0.81	$	0.35	$	1.25	$	0.61
Diluted	$	0.79	$	0.34	$	1.23	$	0.60

For the three month period ended June 30, 2012, no options were excluded from the dilutive earnings per share calculation because the effect would have been anti-dilutive. For the three month period ended June 30, 2011, options to purchase approximately 21,000 shares of common stock were excluded from the dilutive earnings per share calculation because the effect would have been anti-dilutive. For the six month periods ended June 30, 2012 and 2011, options to purchase approximately 300 and 20,000 shares of common stock, respectively, were excluded from the dilutive earnings per share calculation because the effect would be anti-dilutive.

For the three month periods ended June 30, 2012 and 2011, approximately 400 and 13,000 restricted stock units, respectively, were excluded from the dilutive earnings per share calculation because their effect would be anti-dilutive. For the six month periods ended June 30, 2012 and 2011, approximately 575 and 13,000 restricted stock units, respectively, were excluded from the dilutive earnings per share calculation because their effect would be anti-dilutive.

For the three and six month periods ended June 30, 2012, no warrants to purchase shares of common stock were excluded from the dilutive earnings per share calculation because the warrants’ exercise price exceeded the average market price of the Company’s common shares during these periods. For the three and six month periods ended June 30, 2011, warrants to purchase 613,336 shares of common stock were excluded from the dilutive earnings per share calculation because the warrants’ exercise price exceeded the average market price of the Company’s common shares during these periods.

NOTE B: Acquisitions and Dispositions

In August 2011, the Company closed an acquisition of producing oil and gas properties located in the Austin Chalk trend of east Texas. The purchase price was $11 million plus closing adjustments for normal operating activities. The acquisition included approximately 3,700 net acres. For the three months ended June 30, 2012 these properties contributed $877,000 of revenue and $296,000 of net loss to the Company. For the six months ended June 30, 2012 these properties contributed $1.6 million of revenue and $178,000 of net income to the Company.

In December 2011, the Company sold approximately 1,800 net acres in Atacosa County, Texas for $4.6 million. For accounting purposes, the Company used the cost recovery method; under this method proceeds have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties.

In January 2012, the Company closed an acquisition of unproved leasehold interest in McKenzie County, North Dakota. The Company’s net acquisition cost was $12.7 million and was funded with working capital and borrowings on its credit facility.

In February 2012, the Company closed an acquisition of producing wells and acreage in the Austin Chalk trend of east Texas in the Brookeland field area, Newton and Jasper Counties. The Company acquired varying working interests in 96 producing and productive wells across approximately 170,000 net acres. The Company’s net acquisition cost was $40.4 million, subject to closing adjustments for normal operating activity and other customary purchase price adjustments for the effective date of January 1, 2012,

until closing. The acquisition was funded with borrowings on the Company’s credit facility. For the three months ended June 30, 2012 this acquisition contributed $3.9 million of revenue and $876,000 of net income to the Company. For the six months ended June 30, 2012 this acquisition contributed $4.4 million of revenue and $1.0 million of net income to the Company.

In June 2012, the Company sold a producing property located in Duval, Texas to an unaffiliated third party for $20.4 million. The Company recognized a gain of $15.1 million in conjunction with this sale.

NOTE C: Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance Sheet (Topic 210) – Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting under current accounting literature or are subject to master netting agreements irrespective of whether they are offset. The objective of the new disclosures is to facilitate comparison between entities that prepare financial statements on the basis of U.S. GAAP and entities that prepare financial statements under International Financial Reporting Standards (“IFRS”). The disclosure requirements will be effective for the periods beginning on or after January 1, 2013 and must be applied retrospectively to all periods presented on a balance sheet. The Company will adopt the requirements of ASU No. 2011-11 on January 1, 2013, which may require additional note disclosures for derivative instruments and is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”), which provides amendments to FASB Topic 220, Comprehensive Income. The objective of ASU 2011-05 is to require an entity to present the total comprehensive income, the components of net income and the components of other comprehensive either in a single continuous statement of comprehensive income or in two separate statements but consecutive statements. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of equity. ASU 2011-05 was effective for interim and annual periods beginning after December 15, 2011 and is to be applied retrospectively. In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which defers the effective date of changes in ASU 2011-05 that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income. The amendments in this update become effective at the same time as the amendments in ASU 2011-05. The Company adopted the provisions of ASU 2011-05 and 2011-12 effective January 1, 2012, which did not have an impact on its consolidated financial statements other than requiring the Company to present its statements of comprehensive income separately from its statements of equity, as these statements were previously presented on a combined basis.

In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement. The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirement between U.S. GAAP and IFRS. The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. ASU 2011-04 was effective for interim and annual periods beginning after December 15, 2011. The Company adopted this standard effective January 1, 2012, which did not have an impact on the Company’s consolidated financial statements other than additional disclosures.

NOTE D: Long-term Debt

On November 9, 2011, the Company entered into a Third Amended and Restated Credit Agreement (the “Credit Agreement”). The credit agreement provides for a credit facility for financing of up to $450 million for the Company. The borrowing base at June 30, 2012 was $210 million. The credit agreement provides for annual interest rates at (a) LIBOR plus 1.75% to 2.75% or (b) the prime rate plus 0.75% to 1.75%, depending on the amount borrowed. The credit agreement also requires the payment of commitment fees to the ledger on the unutilized commitment. The commitment rate is 0.375% per annum if less than 50% of the borrowing base is outstanding and 0.50% per annum if more than 50% of the borrowing base is outstanding. The Company is also required to pay customary letter of credit fees. All of the obligations under the credit facility, and guarantees of those obligations, are secured by substantially all of the Company’s assets.

The credit facility requires the maintenance of certain financial ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at June 30, 2012.

The principal outstanding under the Company’s credit agreement was $80 million at June 30, 2012. The Company did not have any principal outstanding at December 31, 2011. The annual interest rate in effect at June 30, 2012 was 2.35% on the entire outstanding principal. Upon the closing of the merger discussed in Note M “Subsequent Event”, Halcón paid the outstanding balance under the credit facility in full. Once the balance was paid, the credit facility was terminated.

Interest expense for the three months ended June 30, 2012 and 2011 includes amortization of deferred financing costs of $128,000 and $269,000, respectively. Interest expense for the six months ended June 30, 2012 and 2011 includes amortization of deferred financing costs of $256,000 and $533,000, respectively.

NOTE E: Stock Options, Performance Awards and Stock Warrants

In June 2011, the shareholders of the Company approved amendments to the GeoResources, Inc., Amended and Restated 2004 Employees’ Stock Incentive Plan (the “Plan”), which authorizes the issuance of options and other stock-based incentives to officers, employees, directors and consultants of the Company to acquire up to 3,250,000 shares of the Company’s common stock at prices which may not be less than the stock’s fair market value on the date of grant. The options can be designated as either incentive options or nonqualified options. The plan also allows the issuance of performance units, including restricted stock units.

A summary of the Company’s stock option activity for the six months ended June 30, 2012 is as follows:


	Number of Shares			Weighted Average Exercise Price		Weighted Average Fair Value		Weighted Average Remaining Contractual Life (year)		Aggregate Intrinsic Value
Outstanding, December 31, 2011		781,486		$	10.88	$	4.42		6.93	$	14,402,787
Granted		—
Exercised		(39,062	)	$	11.03	$	4.05
Canceled/forfeited		—

Outstanding, June 30, 2012		742,424		$	10.87	$	4.44		6.43	$	19,107,332

Vested and exercisable		521,174		$	9.96	$	3.71		6.11	$	13,891,432
Vested and expected to vest		740,428		$	10.86	$	4.44		6.43	$	19,066,272

During the six months ended June 30, 2012, 172,500 options vested with a weighted average exercise price of $11.08. The weighted average grant date fair value of these options was $5.22 per option. At June 30, 2012, there were 221,250 unvested options, in respect of 221,250 shares of the Company’s common stock, with a weighted average remaining amortization period of 1.51 years.

The Company recognizes compensation expense by first calculating the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. The Company then amortizes the value of these options as compensation expense on a straight line basis over the vesting period of the options. For the three month periods ended June 30, 2012 and 2011 the Company recognized compensation expense of $233,000 and $273,000, respectively, related to these options. For the six month periods ended June 30, 2012 and 2011, the Company recognized compensation expense of $450,000 and $562,000, respectively, related to these options. As of June 30, 2012, the future un-amortized pre-tax compensation expense associated with non-vested stock options totaled $1.0 million to be recognized through the second quarter of 2015.

In addition to the stock options discussed above the Company has granted certain officers, employees and directors restricted stock unit awards. Each restricted stock unit represent a contingent right to receive one share of the Company’s common stock upon vesting. Compensation expense, determined by multiplying the number of restricted stock units granted by the closing market price of the Company’s common stock on the grant date, is recognized over the respective vesting periods on a straight-line basis. For the three months ended June 30, 2012 and 2011, compensation expense related to restricted stock units was $1.0 million and $248,000, respectively. For the six month periods ended June 30, 2012 and 2011, compensation expense related to restricted stock units was $2.0 million and $248,000, respectively. The Company has an assumed forfeiture rate of 1% on restricted stock issued. As of June 30, 2012, the future unamortized pre-tax compensation expense associated with unvested restricted stock units totaled approximately $10.4 million to be recognized through June 2015. The weighted average vesting period related to unvested restricted stock units at June 30, 2012 was approximately 2.34 years. A summary of the Company’s restricted stock unit activity for the six months ended June 30, 2012 is as follows:


	Units			Fair Value⁽¹⁾
Outstanding, December 31, 2011		197,050		$	27.72
Granted		257,970		$	31.58
Vested⁽²⁾		(66,930	)	$	28.62
Forfeited		—			—

Outstanding, June 30, 2012		388,090		$	30.13

(1)	Represents the weighted average grant date market value.

(2)

During the three month period ended March 31, 2012, 4,630 restricted stock units vested. On March 31, 2012, one share of common stock was issued for each restricted stock unit that vested during the first quarter. During the second quarter of 2012, 62,300 restricted stock units vested and on July 2, 2012, 48,964 shares of common stock were issued as a result of this vesting. Employees relinquished their rights to the remaining 13,336 restricted stock units in exchange for the Company satisfying the employees’ tax liability related to the issuance of the 48,964 shares of common stock.

The Company has outstanding warrants to purchase 613,336 shares of common stock at June 30, 2012. The warrants, which were acquired by non-affiliated accredited investors pursuant to exemptions from registration under the federal and state securities laws on June 5, 2008 have an exercise price of $32.43 and have a remaining life of 11 months at June 30, 2012.

The merger with Halcón, which is discussed in Note M “Subsequent Event”, constituted a change in control as defined in the Plan. The change in control triggered the vesting of all unvested options and restricted stock units as of August 1, 2012. In addition, Halcón assumed the outstanding warrants of the Company.

NOTE F: Income Taxes

Deferred income taxes are recorded to account for the tax effects associated with temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and tax purposes, as required by current accounting standards. The deferred tax amounts are measured using the enacted tax rates applicable to periods when these differences are expected to reverse.

Uncertain Tax Positions

The Company will consider a tax position settled if the taxing authority has completed its examinations, the Company does not plan to appeal the tax authority ruling, and the Company deems the possibility that the taxing authority will reexamine the tax position in the future as remote. For uncertain tax issues, the Company uses the benefit recognition model which contains a two-step approach, a more-likely-than-not recognition criteria and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. The amount of interest expense recognized by the Company related to uncertain tax positions is computed by applying the applicable statutory rate of interest to the difference between the tax position recognized and the amount previously taken or expected to be taken in a tax return.

At June 30, 2012, the Company did not have any uncertain tax positions that would require recognition. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position as of June 30, 2012.

The Company files a consolidated federal income tax return and various combined and separate filings in several state and local jurisdictions. The Company’s 2010 income tax return is currently under examination by the Internal Revenue Service (“IRS”). We do not expect the outcome of the examination to have a material adverse effect on Company’s financial position, results of operations or cash flows.

It is also the Company’s practice to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statements of Income. As of June 30, 2012, the Company did not have any accrued interest or penalties associated with any unrecognized tax liabilities. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statutes of limitations prior to June 30, 2013.

NOTE G: Derivative Financial Instruments

The Company enters into various crude oil and natural gas hedging contracts, primarily costless collars and swaps, in an effort to manage its exposure to product price volatility. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. Swaps are designed so

that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has designated its commodity derivative contracts as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.

At June 30, 2012, accumulated other comprehensive income consisted of unrecognized gains of $6.3 million, net of taxes of $3.8 million, representing the inception to date change in mark-to-market value of the effective portion of the Company’s open commodity contracts, designated as cash flow hedges. At December 31, 2011, accumulated other comprehensive income consisted of unrecognized gains of $1.1 million, net of taxes of $658,000. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at June 30, 2012, the Company expects to reclassify net gains of $8.3 million into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

At June 30, 2012, the Company had hedged its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:


	Total Remaining Volume		Floor Price		Ceiling / Swap Price
Crude Oil Contracts (Bbls):
Swap contracts:
2012		60,000			$	86.85
2012		60,000			$	87.22
2012		30,000			$	99.55
2012		60,000			$	103.95
2012		30,000			$	105.00
2012		30,000			$	107.30
2012		60,000			$	108.45
2013		60,000			$	97.60
2013		60,000			$	100.70
2013		120,000			$	101.85
2013		120,000			$	105.55
Costless collar contracts
2012		60,000	$	85.00	$	110.00
Natural Gas Contracts (Mmbtu)
Swap contracts
2012		120,000			$	2.925
2012		450,000			$	4.850
2012		300,000			$	6.415
2013		240,000			$	3.560
2013		225,000			$	4.850

All derivative instruments are recorded on the consolidated balance sheet at fair value. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheets (in thousands):


Derivatives designated as ASC 815 hedges:	Asset Derivatives					Liability Derivatives
	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
	Balance Sheet Location	Jun. 30, 2012		Dec. 31, 2011		Balance Sheet Location	Jun. 30, 2012		Dec. 31, 2011
Commodity contracts	Current derivative financial instruments asset	$	8,311	$	4,037	Current derivative financial instruments liability	$	—	$	(2,890	)
Commodity contracts	Long-term derivative financial instruments asset		2,189		868	Long-term derivative financial instruments liability		—		—

		$	10,500	$	4,905		$	—	$	(2,890	)

Commodity derivative contracts – The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the three months ended June 30, 2012 and 2011 (in thousands):


Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)				Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
Derivatives designated as ASC 815 hedges:	Jun. 30, 2012		Jun. 30, 2011			Jun. 30, 2012		Jun. 30, 2011
Commodity contracts	$	13,456	$	6,920	Oil and gas revenues	$	1,597	$	(1,772	)

	$	13,456	$	6,920		$	1,597	$	(1,772	)


	Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain Recognized in Income on Derivative (Ineffective Portion)
		Jun. 30, 2012		Jun. 30, 2011
Derivatives in ASC 815 Cash Flow Hedging Relationships:		Jun. 30, 2012		Jun. 30, 2011
Commodity contracts	Hedge ineffectiveness	$	164	$	1,561

The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the six months ended June 30, 2012 and 2011 (in thousands):


Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)					Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
Derivatives designated as ASC 815 hedges:	Jun. 30, 2012		Jun. 30, 2011				Jun. 30, 2012		Jun. 30, 2011
Commodity contracts	$	9,926	$	(1,288	)	Oil and gas revenues	$	1,538	$	(2,510	)

	$	9,926	$	(1,288	)		$	1,538	$	(2,510	)


Derivatives in ASC 815 Cash Flow Hedging Relationships:	Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
		Jun. 30, 2012		Jun. 30, 2011
		Jun. 30, 2012		Jun. 30, 2011
Commodity contracts	Hedge ineffectiveness	$	98	$	(641	)

Contingent features in derivative instruments – None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s derivative contracts are high credit quality financial institutions that are lenders under the Company’s credit facility. The Company uses its credit facility participants to hedge with, since these institutions are secured equally with the holders of the Company’s debt, which eliminates the potential need to post collateral when the Company is in a large derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

NOTE H: Fair Value Disclosures

ASC Topic 820 defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.

ASC Topic 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•

Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•

Level 2 – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•

Level 3 – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of the 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 in its entirety requires judgment and considers factors specific to the asset or liability.

Cash, Cash Equivalents, Accounts Receivable and Payable and Royalties Payable – The carrying amount of cash and cash equivalents, accounts receivable and payable and royalties payable are estimated to approximate their fair values due to the short maturities of these instruments.

Long-term Debt – The Company’s long-term debt obligation under its current credit facility at June 30, 2012 bears interest at floating market rates, so carrying amounts and fair values are approximately equal.

Derivative Financial Instruments – Derivative financial instruments are carried at fair value. Commodity derivative instruments consist of costless collars and swaps for crude oil and natural gas. The Company’s costless collar is valued based on the counterparty’s marked-to-market statements, which are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and is designated as Level 2 within the valuation hierarchy. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is the NYMEX futures index. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy. The discount rate used in determining the fair values of these instruments includes a measure of nonperformance risk.

The table below presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

Fair Value of Financial Assets and Liabilities - June 30, 2012

(in thousands)


	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balances as of June 30, 2012
Current portion of derivative financial instrument asset ⁽¹⁾		—	$	8,311	$	—	$	8,311
Long-term portion of derivative financial instrument asset ⁽¹⁾		—		2,189		—		2,189

(1)	Commodity derivative instruments accounted for as cash flow hedges.

Fair Value of Financial Assets and Liabilities - December 31, 2011

(in thousands)


	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balances as of December 31, 2011
Current portion of derivative financial instrument asset ⁽¹⁾		—	$	4,037			—	$	4,037
Long-term portion of derivative financial instrument asset ⁽¹⁾		—		868			—		868
Current portion of derivative financial instrument liability ⁽¹⁾		—		(2,890	)		—		(2,890	)

(1)	Commodity derivative instruments accounted for as cash flow hedges.

At June 30, 2012, and December 31, 2011, the Company did not have any assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3. Also, there were no transfers between Level 1, Level 2 or Level 3 as of June 30, 2012 and December 31, 2011.

Asset Impairments – The Company reviews proved oil and gas properties for impairment quarterly and when events and circumstances indicate a significant decline in the recoverability of the carrying value of such properties. When events and circumstances indicate a significant decline in the recoverability of a property, the Company estimates the future cash flows expected in connection with the property and compares such future cash flows to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted

future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include significant Level 3 assumptions associated with estimates of future oil and gas production, commodity prices based on commodity futures price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The Company did not record any asset impairment during the three or six month periods ended June 30, 2012 or 2011.

Asset Retirement Obligations – The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include estimates of plugging costs and estimates of reserve lives. The estimated plugging costs per well and reserve lives vary significantly depending on the nature and location of the well. Significant increases or decreases in the plugging costs and/or reserve lives would result in a significant change to the fair value measurement. A reconciliation of the Company’s asset retirement obligation is presented in Note J.

Property Acquisitions and Business Combinations – The Company records the identifiable assets acquired, liabilities assumed and any non-controlling interests at fair value at the date of acquisition. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate of future natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note B.

NOTE I: Public Offering of Common Stock

On January 19, 2011, the Company closed a public offering of 5,175,000 shares of common stock issued by the Company (including 675,000 shares of over allotment granted to underwriters) and 989,000 shares sold by certain selling shareholders in a public offering, at a price of $25.00 per share. The net proceeds for the shares sold by the Company were approximately $122.5 million after deducting the underwriters’ discount and other offering expenses of $6.9 million.

NOTE J: Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. The Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the six months ended June 30, 2012, are as follows (in thousands):


Asset retirement obligation, January 1, 2012	$	7,940
Accretion expense		226
Additional liabilities incurred		1,611
Settlement of liabilities		(41	)
Disposals of property		(149	)

Asset retirement obligation, June 30, 2012	$	9,587

NOTE K: Related Party Transactions

Accounts receivable at June 30, 2012, and December 31, 2011, includes $446,000 and $258,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at June 30, 2012 and December 31, 2011, also includes $135,000 and $113,000, respectively, due from OKLA Energy Partners LP (“OKLA Energy”). Both of these partnerships are oil and gas limited partnerships for which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued management fees. Accounts payable at June 30, 2012, and December 31, 2011, includes $1.5 million and $2.8 million, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at June 30, 2012, and December 31, 2011, also includes $189,000 and $817,000, respectively, due to OKLA Energy for oil and gas revenues collected on its behalf.

Subsidiaries of the Company operate the majority of the oil and gas properties in which the two limited partnerships have an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and development expenditures on behalf of the limited partnerships. These revenues are paid monthly to each limited partnership, which in turn reimburse the Company for the limited partnership’s share of expenditures. The Company earned management fees during the three months ended June 30, 2012 and 2011 of $143,000, and $131,000 respectively. The Company earned management fees during the six months ended June 30, 2012 and 2011, of $244,000 and $242,000, respectively.

NOTE L: Equity Investments

The Company holds investments, in the form of general partnership interests, in two affiliated partnerships, SBE Partners and OKLA Energy. The Company accounts for these investments using the equity method of accounting. Under this accounting method the Company records its net share of income and expenses in the Partnership Income line item of its Consolidated Statement of Income. Contributions to the investment increase the Company’s investment while distributions from the investment decrease the Company’s carrying value of the investment.

OKLA Energy, formed during 2008, holds direct working interests in producing oil and gas properties located throughout Oklahoma. The Company’s 2% general partner interest reverts to 35.66% when the limited partner realizes a contractually specified rate of return. The Company recorded losses in partnership income related to this investment of $2,100 and gains of $10,000, respectively for the three month periods ended June 30, 2012 and 2011. For the six month periods ended June 30, 2012 and 2011 the Company recorded gain in partnership income of $900 and $9,000, respectively.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings field, Texas. The Company holds a general partnership interest of approximately 30%. The Company recorded gains in partnership income related to this investment of $106,000 and $495,000, respectively for the three month periods ended June 30, 2012 and 2011. For the six month periods ended June 30, 2012 and 2011 the Company recorded gain in partnership income of $394,000 and $906,000, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at June 30, 2012 and December 31, 2011, was $629,000 and $646,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at June 30, 2012 and December 31, 2011 was $1.0 million and $1.6 million, respectively.

NOTE M: Subsequent Events

On July 31, 2012, the stockholders of the GeoResources and Halcón Resources Corporation (“Halcón”) approved the merger of GeoResources into a subsidiary of Halcón. The closing of the transaction occurred on August 1, 2012 and the Company’s stockholders received $20 in cash and 1.932 shares of Halcón’s common stock for each share of the Company’s common stock. The cash consideration aggregated approximately $531.5 million, and Halcón issued approximately 51.3 million shares of common stock to the stockholders of the Company. In addition, Halcón assumed outstanding warrants of the Company providing for the issuance of 1,184,966 shares of Halcón’s common stock upon exercise. Upon the closing of the merger, Halcón paid the outstanding balance under our credit facility with Wells Fargo Bank, N.A. in full. Once the balance was paid, the credit facility was terminated.

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

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

The following is Management’s Discussion and Analysis of significant factors that have affected certain aspects of our financial position and operating results during the periods included in the accompanying unaudited consolidated financial statements. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K and 10-K/A, for the year ended December 31, 2011.

Merger with Halcón Resources Corporation

On August 1, 2012, we were acquired by Halcón Resources Corporation (“Halcón”) through a merger. As consideration, the Company’s shareholders received $20 in cash and 1.932 shares of Halcón common stock for each share of the Company’s common stock that was issued and outstanding and Halcón also assumed our outstanding warrants. Additional details regarding the merger are discussed in Note M to the Consolidated Financial Statements, “Subsequent Events.” This discussion and analysis should be read keeping in mind that we became a wholly owned subsidiary of Halcón’s subsequent to the periods covered hereby.

Forward-Looking Information

Certain statements contained in this report on Form 10-Q are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, (the “Securities Act”) and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including, without limitation, the statements specifically identified as forward-looking statements within this report. Many of these statements contain risk factors as well. In addition, certain statements in our filings with the SEC, in press releases and in oral and written statements made by or with our approval which are not statements of historical fact constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital expenditures, revenues, income or loss, earnings or loss per share, capital structure, and other financial items, (ii) statements of our plans and objectives or our management or board of directors including those relating to planned development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes,” “anticipates,” “expects,” “intends,” “targeted,” “may,” “will” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

•

changes in production volumes, worldwide demand and commodity prices for oil and natural gas;

•

changes in estimates of proved reserves;

•

declines in the values of our oil and natural gas properties resulting in impairments;

•

the timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;

•

our ability to acquire leases, drilling rigs, supplies and services on a timely basis and at reasonable prices;

•

reductions in the borrowing base under our credit facility;

•

risks incident to the drilling and operation of oil and natural gas wells;

•

future production and development costs;

•

the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on prices;

•

the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America;

•

changes in environmental laws and the regulation and enforcement related to those laws;

•

the identification of and severity of environmental events and governmental responses to the events;

•

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, derivatives reform, and changes in state, federal and foreign income taxes;

•

the effect of oil and natural gas derivatives activities;

•

conditions in the capital markets; and

•

other risks, described in Item 1A, “Risk Factors,” in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011, as may be supplemented and updated from time to time in our other SEC filings.

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

Overview

We are an independent oil and gas company engaged in the acquisition, development and production of oil and gas reserves. As further discussed in this report, future growth in assets, earnings and cash flows will be dependent upon our ability to acquire, discover and develop commercial quantities of oil and gas reserves that can be produced at a profit.

Oil and Gas Properties

We use the Successful Efforts method of accounting for oil and gas operations. Under this method, costs to acquire oil and gas properties, drill successful exploratory wells, drill and equip development wells and install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs are charged to operations as incurred. Depreciation, depletion and amortization (“DD&A”) of the capitalized costs associated with proved oil and gas properties are computed using the unit-of-production method, at the field level, based on proved reserves. Oil and gas properties are periodically assessed for impairment and generally written down to estimated fair value if the sum of estimated future undiscounted pretax cash flows, based on engineering and expected economic circumstances, is less than the carrying value of the asset. The fair value of impaired assets is generally determined using market values, if known, or using reasonable projections of production, prices and costs and discount rates commensurate with the risks involved.

Recent Property Acquisitions and Divestitures

On January 20, 2012, we closed on an acquisition of unproved leasehold interest in McKenzie County, North Dakota. We acquired an average net interest of 10.2% in approximately 3,700 net acres. Our net acquisition cost was $12.7 million and was funded with working capital and borrowing on our credit agreement.

On February 29, 2012, we closed an acquisition of producing wells and acreage in the Austin Chalk trend of east Texas in the Brookeland field area, Newton and Jasper Counties. We acquired varying interest in 96 producing and productive wells across approximately 170,000 net acres. Our net acquisition cost was $40.4 million, subject to closing adjustments for normal operating activity and other customary purchase price adjustments. The acquisition was funded with borrowings on our credit facility.

Results of Operations

Three months ended June 30, 2012, compared to three months ended June 30, 2011

The Company recorded net income of $20.7 million for the three months ended June 30, 2012 compared to net income of $8.8 million for the same period in 2011. This $11.9 million increase resulted primarily from the following factors:

Net amounts contributing to increase (decrease) in net income (in thousands):


Oil and natural gas sales	$	22,505
Lease operating expenses		(2,172	)
Production taxes		(1,360	)
Exploration expense		122
Re-engineering and workovers		(311	)
General and administrative expenses (“G&A”)		(5,432	)
Depletion, depreciation and amortization expense (“DD&A”)		(7,268	)
Hedge ineffectiveness		(1,397	)
Gain (loss) on sale of property		15,107
Interest expense		(308	)
Other income		(183	)

Income before income taxes		19,303
Provision for income taxes		(7,378	)

Increase in net income	$	11,925

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and natural gas sales increased $22.5 million, or 77% due to volume increases of $27.5 million offset by price decreases (including the effects of hedge settlements) of $5.0 million. Oil volumes accounted for $24.9 million of the volume increase and gas volumes accounted for the remaining $2.6 million. Our oil production increased by 92% in the second quarter of 2012 compared to the second quarter of 2011 as a result of successful drilling in our Bakken and Eagle Ford areas. Also, oil production from many of our new wells drilled in the first half of 2011 was delayed due to adverse weather conditions in North Dakota and Montana, as well as significant delays in obtaining services and equipment. Our gas production increased by 63% primarily due to production in our Austin Chalk trend of east Texas which is a result of recent property acquisitions during the third quarter of 2011 and first quarter of 2012. Price and production comparisons are set forth in the following table.


	Percent increase (decrease)			Three Months Ended June 30,
	Percent increase (decrease)			2012		2011
Oil Production (MBbls)		92	%		509		265
Gas Production (MMcf)		63	%		1,638		1,004
Barrel of Oil Equivalent (MBOE)		81	%		782		432
Average Price Oil before Hedge Settlements (per Bbl)		-11	%	$	90.08	$	101.78
Average Price Oil after Hedge Settlements (per Bbl)		0	%	$	90.91	$	90.71
Average Price Gas before Hedge Settlements (per Mcf)		-35	%	$	2.64	$	4.08
Average Price Gas after Hedge Settlements (per Mcf)		-36	%	$	3.36	$	5.24

Lease Operating Expenses. Lease operating expenses (“LOE”) increased from $5.8 million in the second quarter of 2011 to $7.9 million for the same period in 2012, an increase of $2.1 million or 38%. Included in lease operating expenses are ad valorem taxes of $333,000 and $337,000 for the three month periods ended June 30, 2012 and 2011, respectively. Our LOE, excluding ad valorem taxes,

increased due to the higher number of producing wells and increased levels of oil and gas production. However, on a per unit basis, LOE costs (excluding ad valorem taxes) per BOE decreased from $12.52 in 2011 to $9.70 in 2012. The decrease in LOE per BOE is primarily attributable to drilling new wells with relatively high initial rates of production.

Re-engineering and workovers. Re-engineering and workover costs increased by $311,000 from $709,000 to $1.0 million. Re-engineering and workover projects occur in different fields and at different times due to operational decisions and therefore when comparing quarterly expenditures, this variance is due to the timing of initiation and the size of individual projects.

Production Taxes. Production taxes increased by $1.4 million or 72%, consistent with the increase in oil and gas revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the quarters ended June 30, 2012 and 2011 were 6.49% and 6.11%, respectively, of oil and gas sales before the effects of hedging.

General and Administrative Expenses. G&A increased by $5.4 million, or 183%, due primarily to increases in personnel hired in the last 12 months, general pay increases, non-cash stock-based compensation expense, and merger-related costs. The total non-cash charges related to stock-based compensation included in G&A expense for the three month periods ended June 30, 2012 and 2011 were $1.3 million and $522,000, respectively. The increase in non-cash charges related to stock-based compensation is a result of the issuance of restricted stock units. We also incurred professional fees related to the Halcón merger of $4.0 million during the second quarter of 2012.

Depreciation, Depletion and Amortization. DD&A expense increased by $7.3 million, or 114%, due to higher capitalized costs and increased production. DD&A on oil and gas properties is computed on the units-of-production method, with production volumes as the numerator and estimated proved reserve volumes as the denominator. On a unit of production basis, DD&A per BOE increased from $14.69 in 2011 to $17.41 in 2012. Capitalized costs increased due to acquisitions of additional property interests and continued successful drilling in the Eagle Ford and Bakken trends, where wells are more costly to drill compared to conventional wells, resulting in higher finding and development costs.

Interest Expense. Interest expense, inclusive of commitment fees and amortization of deferred financing costs, increased by $308,000 or 68% due to higher debt levels in the second quarter of 2012 compared to the same period in 2011. This increase was partially offset by a decrease in amortization of deferred financing costs. Our debt was fully extinguished in January 2011. For the three months ended June 30, 2012, average outstanding debt was $77.3 million. Interest expense for the three months ended June 30, 2012 and 2011 includes amortization of deferred financing costs of $128,000 and $269,000, respectively.

Gain on Sale of Property. Gain on sale of property increased $15.1 million in the second quarter of 2012 compared to the same period in 2011. In June 2012, we sold a producing property located in Duval, Texas to an unaffiliated third party for $20.4 million and recognized a gain of $15.1 million.

Hedge Ineffectiveness. In the second quarter of 2012 the gain from hedge ineffectiveness was $164,000 compared to a gain of $1.6 million for the same period in 2011. During the second quarter of 2012 and 2011, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a net gain in both periods. In 2012 the gain was not as significant because a large portion of the 2012 gain on oil hedges was effective and therefore included in accumulated other comprehensive income.

Other Income. Other income decreased by $183,000 in the second quarter of 2012 compared to the same period in 2011 due primarily to a decrease in property operating income of $175,000, which was due to a reduction in the fees earned on operated wells drilled.

Income Tax Expense. Income tax expense for the second quarter of 2012 was $12.8 million compared to $5.4 million for the same period in 2011. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rates during the second quarter of 2012 and 2011 were 38% in both periods.

Six months ended June 30, 2012, compared to the six months ended June 30, 2011

The Company recorded net income of $32.1 million for the six months ended June 30, 2012 compared to net income of $15.1 million for the same period in 2010. This $17.0 million increase resulted primarily from the following factors:

Net amounts contributing to increase (decrease) in net income (in thousands):


Oil and natural gas sales	$	38,455
Lease operating expenses		(4,405	)
Production taxes		(2,561	)
Exploration expense		75
Re-engineering and workovers		(689	)
General and administrative expenses (“G&A”)		(7,479	)
Depletion, depreciation and amortization expense (“DD&A”)		(11,462	)
Hedge ineffectiveness		739
Gain (loss) on sale of property		14,373
Interest expense		(131	)
Other Income		756

Income before income taxes		27,671
Provision for income taxes		(10,639	)

Increase in net income	$	17,032

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and natural gas sales increased $38.4 million, or 69% due to volume increases of $42.6 million offset by price decreases (including the effects of hedge settlements) of $4.2 million. Oil volumes accounted for $38.9 million of the increase and gas volumes accounted for the remaining $3.7 million. Our gas production increased by 45% primarily due to production in our Austin Chalk trend of East Texas which is a result of recent property acquisitions during the third quarter of 2011 and first quarter of 2012. Our oil production increased by 77% in the first six months of 2012 compared the same period in 2011 as a result of successful drilling in our Bakken and Eagle Ford areas. Also, oil production from many of our new wells drilled in the first half of 2011 was delayed due to adverse weather conditions in North Dakota and Montana, as well as significant delays in obtaining services and equipment. Price and production comparisons are set forth in the following table.


	Percent increase (decrease)			Six Months Ended June 30,
	Percent increase (decrease)			2012		2011
Oil Production (MBbls)		77	%		914		515
Gas Production (MMcf)		45	%		2,926		2,015
Barrel of Oil Equivalent (MBOE)		65	%		1,402		851
Average Price Oil before Hedge Settlements (per Bbl)		-5	%	$	92.26	$	97.53
Average Price Oil after Hedge Settlements (per Bbl)		4	%	$	91.25	$	88.12
Average Price Gas before Hedge Settlements (per Mcf)		-29	%	$	2.90	$	4.06
Average Price Gas after Hedge Settlements (per Mcf)		-28	%	$	3.74	$	5.22

Lease Operating Expenses. Lease operating expenses increased from approximately $10.8 million during the six months ended June 30, 2011 to $15.2 million for the same period in 2012, an increase of $4.4 million or 41%. Included in lease operating expenses are ad valorem taxes of $680,000 and $609,000 for the six months ended June 30, 2012 and 2011, respectively. Our lease operating expenditures, excluding ad valorem taxes, have increased due to the higher number of producing wells and increased levels of oil and gas production. However, on a per unit basis, LOE costs (excluding ad valorem taxes) per BOE decreased from $11.94 in 2011 to $10.34 in 2012. The decrease in LOE per BOE is primarily attributable to drilling new wells with relatively high initial rates of production.

Re-engineering and Workover. Re-engineering and workover costs increased by $689,000 or 62% from $1.1 million for the six months ended June 30, 2011 to $1.8 million for the six months ended June 30, 2012. Reengineering and workover projects occur in different fields and at different times due to operational decisions and therefore when comparing expenditures, this variance is due to the timing of initiation and the size of individual projects.

Production Taxes. Production taxes increased by $2.6 million or 73%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the first six months of 2012 and 2011 were 6.55% and 6.02%, respectively, of oil and gas sales before the effects of hedging.

Exploration Costs. Our exploration costs were $281,000 for the six months ended June 30, 2012 and $356,000 for the same period during 2011 a decrease of $75,000 or 21%. The costs incurred during both periods were primarily geological and geophysical costs.

General and Administrative Expenses. G&A increased $7.5 million or 134% in the first six months of 2012 compared to the same period in 2011 due to increased non-cash equity based compensation, increases in personnel and office facilities, and increases in merger related costs. As our business has expanded, we have also expanded our staff and office space. Included in G&A expense for the six months ended June 30, 2012 and 2011 are non-cash charges related to our stock-based compensation of $2.4 million and $810,000, respectively. The increase in non-cash charges related to stock-based compensation is a result of the issuance of restricted stock units. Also, we incurred professional fees related to the Halcón merger of $4.0 million during the six months ended June 30, 2012.

Depreciation, Depletion and Amortization. DD&A expense increased by $11.5 million or 96% due to higher capitalized costs and higher production. On a units-of- production basis, DD&A per BOE increased from $14.02 in 2011 to $16.68 in 2012. This increase is a result of increased activity in the Bakken and Eagle Ford trends, where wells are more costly to drill compared to conventional wells, resulting in higher finding and development costs as well as higher DD&A expense.

Interest Expense. Interest expense, inclusive of commitment fees and amortization of deferred financing costs, increase by $131,000 due to higher average debt levels during the first six months of 2012, as compared to the same period in 2011. During the first six months of 2012, our weighted average outstanding debt was approximately $50.2 million compared to $9.6 million for the same period in 2011.

Gain on Sale of Property. Gain on sale of property increased $14.3 million in the second quarter of 2012 compared to the same period in 2011. In June 2012, we sold a producing property located in Duval, Texas to an unaffiliated third party for $20.4 million and recognized a gain of $15.1 million.

Hedge Ineffectiveness. For the first six months of 2012 the gain from hedge ineffectiveness was $98,000, compared to a loss of $641,000 in the same period in 2011. During 2012, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a gain. In 2011, our derivatives accounted for as cash flow hedges decreased in value; therefore, the change in the ineffective portion of these derivatives was a loss.

Other Income. Other income increased by $756,000 in the first six months of 2012 compared to the same period in 2011. Property operating income increased by $1.2 million due to an increase in the number of operated wells and fees earned on operated wells drilled. This increase was partially offset by a decrease in partnership income of $520,000.

Income Tax Expense. Income tax expense for the first six months of 2012 was $20.2 million compared to $9.5 million for the same period in 2011. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during both the first six months of 2012 and 2011 was approximately 39%.

Impact of Changing Prices and Costs

Our revenues and the carrying value of our oil and gas properties are impacted by significant changes in underlying oil and gas commodity prices. The oil and gas industry is cyclical and the demand for goods and services put significant pressure on the pricing structures within the industry and therefore have a direct impact on the underlying economics of our exploration and development programs. Typically, as prices for oil and natural gas increase, so do all associated costs of materials, services and personnel. However, in periods of declining prices, associated cost reductions may lag and not move downward in proportion to prices. Material changes in prices also impact the current revenue stream, estimates of future oil and gas reserves, depletion expense, impairment assessments of oil and gas properties due to low prices, and values of properties in purchase and sale transactions. Material changes in prices can impact the market value of shares of oil and gas companies and their ability to raise capital, borrow money and retain personnel.

Our average realized oil price of $91.25 per Bbl, net of hedges, for the six months ended June 30, 2012, was 4% higher than for the comparable period in 2011. Our average realized natural gas price of $3.74 per Mcf, net of hedges, for the six months ended June 30, 2012, was 28% lower than the $5.22 received for the same period in 2011. The average realized prices for the six months ended June 30, 2012, included the effects of our hedges. Should significant additional price decreases occur or should prices fail to remain at levels which will facilitate reinvestment of cash flow to economically replace current production, we could experience difficulty in developing our assets and growing our production and reserves.

Hedging Activities

In an attempt to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing, we have historically entered into hedging transactions including fixed price swaps, price collars, puts and other derivatives. Management believes our hedging provides greater predictability of internally generated funds, which can be dedicated to capital development projects and corporate obligations.

We have not engaged in speculative commodity trading activities and do not hedge all of our current or anticipated production.

Administrative and Operating Costs

On an ongoing basis, we focus on cost-containment efforts related to capital, operating and administrative costs. The demand for equipment, services and personnel in our industry is significant, particularly in our focus areas. In spite of the pressures on cost resulting from such demand we have generally been able to achieve cost reductions in our drilling and completion operations in our focus areas, largely due to efficiency and logistical improvements resulting from pad drilling, efficiencies associated with running multiple rigs, and other initiatives.

Liquidity and Capital Resources

On August 1, 2012, we were acquired by Halcón as discussed in Note M to the Consolidated Financial Statements, “Subsequent Events”. Our future capital resources and liquidity are dependent on a variety of factors, including, but not limited to, Halcon’s ability to obtain financing, generation of cash flow, acquisition opportunities and drilling results.

Credit Facility

As of June 30, 2012, our borrowing base under our credit facility with Wells Fargo Bank, N.A. was $210 million on which we had an outstanding balance of $80 million. Upon the closing of the merger discussed in Note M to the Consolidated Financial Statements, “Subsequent Events”, Halcón paid the outstanding balance under the credit facility in full. Once the balance was paid, the credit facility was terminated; Halcón has a $1.5 billion credit facility with a post-merger borrowing base of $525 million.

Cash Flows from Operating Activities

For the six months ended June 30, 2012, our net cash provided by operating activities was $68.5 million, versus $38.4 million in the same period in 2011.

Cash Flows from Investing Activities

Cash used for capital expenditures for the six months ended June 30, 2012 and 2011, was $168.5 million and $42.4 million, respectively. During the first six months of 2012, oil and gas capital expenditures include the purchase of unproved leasehold in McKenzie County, North Dakota for $12.7 million and the purchase of producing wells and acreage in the Austin Chalk trend of east Texas for $40.4 million. In addition, cash generated from the sale of properties for the six months ended June 30, 2012 and 2011 was $20.4 million and $345,000. During the first six months of 2012, we sold a producing property located in Duval, Texas to an unaffiliated third party for $20.4 million. Capital expenditures for the first six months of 2012 were financed through borrowing under our credit facility and with working capital.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodities. We are exposed to market risk from changes in commodity prices. In the normal course of business, we enter into derivative transactions, including commodity price collars, swaps and floors to mitigate our exposure to commodity price movements. We do not participate in these transactions for trading or speculative purposes. While the use of these arrangements may limit the benefit to us of increases in the prices of oil and natural gas, it also limits the downside risk of adverse price movements.

The following is a list of contracts outstanding at June 30, 2012:


Transaction Type	Beginning		Ending		Price Per Unit		Remaining Annual Volumes	Fair Value Outstanding as of June 30, 2012
								(in thousands)
Swap		01/01/12		03/31/13	$	4.850	675,000 Mmbtu		1,170
Swap		02/01/12		12/31/12	$	2.925	120,000 Mmbtu		9
Swap		04/01/12		12/31/12	$	6.415	300,000 Mmbtu		1,033
Swap		01/01/13		12/31/12	$	3.560	240,000 Mmbtu		11

									2,223

Swap		01/01/12		12/31/12	$	86.85	60,000 Bbls		41
Swap		01/01/12		12/31/12	$	87.22	60,000 Bbls		63
Swap		01/01/12		12/31/12	$	99.55	30,000 Bbls		408
Swap		01/01/12		12/31/12	$	103.95	60,000 Bbls		1,072
Swap		01/01/12		12/31/12	$	105.00	30,000 Bbls		272
Swap		01/01/12		12/31/12	$	107.30	30,000 Bbls		364
Collar		01/01/12		12/31/12	$	85.00 - $110.00	60,000 Bbls		242
Swap		03/01/12		12/31/12	$	108.45	60,000 Bbls		1,342
Swap		01/01/13		12/31/13	$	97.60	60,000 Bbls		538
Swap		01/01/13		12/31/13	$	100.70	60,000 Bbls		349
Swap		01/01/13		12/31/13	$	101.85	120,000 Bbls		1,575
Swap		01/01/13		12/31/13	$	105.55	120,000 Bbls		2,011

									8,277

								$	10,500

Interest rates. We are exposed to financial risk from changes future in interest rates to the extent that we incur future indebtedness. As of June 30, 2012, we had $80 million outstanding under our Third Amended and Restated Credit Agreement. The Credit Agreement provides for a variable interest rate. In the event interest rates rise significantly, and we incur future indebtedness without mitigating or fixing future interest rates, our interest expense will increase in accordance with any future borrowings and at rates in effect at the time of those borrowings. Upon the closing of the merger discussed in Note M to the Consolidated Financial Statements, “Subsequent Events”, Halcón paid the outstanding balance under the credit facility in full. Once the balance was paid, the credit facility was terminated.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our Chief Executive Officer, Chief Financial Officer and other members of management evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of June 30, 2012. Based upon their evaluation of these disclosure controls and procedures, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of June 30, 2012, in ensuring that information required to be disclosed by us in the reports that we file or submit 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 by us in such reports is accumulated and communicated to our management, including our principal executive and principal financial officers to allow timely discussion regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A- Risk Factors” in our Annual Report for the year ended December 31, 2011 on Form 10-K, as amended; which could materially affect our business, financial condition or future results. The risks described in our 2011 Annual Report on Form 10-K, as amended, may not be the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.


*Item 2.*	*Unregistered Sales of Equity Securities and Use of Proceeds*	None
*Item 3.*	*Defaults Upon Senior Securities*	None
*Item 4.*	*Mine Safety Disclosure*	Not Applicable
*Item 5.*	*Other Information*	None

Item 6. Exhibits

EXHIBIT INDEX

FOR

Form 10-Q for the quarterly period ended June 30, 2012.



2.1		Agreement and Plan of Merger, dated as of April 24, 2012 as amended, and among Halcón Resources Corporation, Leopard Sub I, Inc., Leopard Sub II, LLC and GeoResources, Inc. (Incorporated by reference to Annex A of our Definitive Proxy Statement (DEFM14A filed with the SEC on June 27, 2012)

31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)

31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)

32.1		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)

32.2		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)

101.INS		XBRL Instance Document. (1)

101.SCH		XBRL Schema Document. (1)

101.CAL		XBRL Calculation Linkbase Document. (1)

101.DEF		XBRL Definition Linkbase Document. (1)

101.LAB		XBRL Label Linkbase Document. (1)

101.PRE		XBRL Presentation Linkbase Document. (1)

(1)	Filed herewith

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 thereunto duly authorized.


		Halcón Geo Holdings LLC
August 9, 2012		(Successor to GeoResources, Inc.)

		/s/ Floyd C. Wilson
		Floyd C. Wilson
		Chief Executive Officer (Principal Executive Officer)

		/s/ Mark J. Mize
		Mark J. Mize
		Chief Financial Officer
		(Principal Financial Officer)

		/s/ Joseph S. Rinando, III
		Joseph S. Rinando, III
		Chief Accounting Officer
		(Principal Accounting Officer)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

GEORESOURCES INC 10-Q