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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 March 31, 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 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.

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 May 4, 2012
Common stock, par value $.01 per share		25,632,322 shares

TABLE OF CONTENTS


	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements.

	Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011.	3

	Consolidated Statements of Income for the Three Months ended March 31, 2012 and 2011.	5

	Consolidated Statements of Comprehensive Income for the Three Months ended March 31, 2012 and 2011.	6

	Consolidated Statement of Stockholders’ Equity for the Three Months ended March 31, 2012.	7

	Consolidated Statements of Cash Flows for the Three Months ended March 31, 2012 and 2011.	8

	Notes to Consolidated Financial Statements.	9

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	32

Item 4.	Controls and Procedures.	33

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.	34

Item 1A.	Risk Factors.	35

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	35

Item 3.	Defaults Upon Senior Securities.	35

Item 4.	Mine Safety Disclosures.

Item 5.	Other Information.	35

Item 6.	Exhibits.	36

	Signatures.	37

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	March 31,			December 31,
	2012			2011
	(unaudited)
ASSETS

Current assets:

Cash	$	21,535		$	39,144
Accounts receivable:
Oil and gas revenues		32,323			26,485
Joint interest billings and other, less allowance for doubtful accounts of $609 and $609, respectively		27,321			21,328
Affiliated partnerships		757			371
Notes receivable		545			545
Derivative financial instruments		4,320			4,037
Income taxes receivable		9,765			7,753
Prepaid expenses and other		5,019			3,681


Total current assets		101,585			103,344


Oil and gas properties, successful efforts method:
Proved properties		531,755			428,871
Unproved properties		60,602			44,613
Office and other equipment		1,780			1,675
Land		146			146

		594,283			475,305

Less accumulated depreciation, depletion and amortization		(106,529	)		(96,753	)

Net property and equipment		487,754			378,552


Equity in oil and gas limited partnerships		1,975			2,240

Derivative financial instruments		206			868

Deferred financing costs and other		2,506			2,687


	$	594,026		$	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)


	March 31,			December 31,
	2012			2011
	(unaudited)
LIABILITIES AND EQUITY

Current liabilities:

Accounts payable	$	44,381		$	25,483
Accounts payable to affiliated partnerships		2,459			3,597
Revenue and royalties payable		22,880			17,043
Drilling advances		7,919			12,965
Accrued expenses		9,416			5,073
Derivative financial instruments		5,184			2,890


Total current liabilities		92,239			67,051


Long-term debt		60,000			—

Deferred income taxes		52,325			44,389

Asset retirement obligations		9,458			7,940

Derivative financial instruments		865			—

Stockholders’ equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 25,631,672 in 2012 and 25,595,930 in 2011		256			256
Additional paid-in capital		283,072			281,515
Accumulated other comprehensive income (loss)		(1,080	)		1,069
Retained earnings		96,891			85,471


Total stockholders’ equity		379,139			368,311

	$	594,026		$	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 March 31,
	2012			2011

Revenue:
Oil and gas revenues	$	42,564		$	26,614
Partnership management fees		101			111
Property operating income		1,805			676
Gain on sale of property and equipment		2			736
Partnership income		291			410
Interest and other		31			92


Total revenue		44,794			28,639

Expenses:
Lease operating expense		7,252			5,019
Severance taxes		2,822			1,621
Re-engineering and workovers		772			394
Exploration expense		279			232
General and administrative expense		4,647			2,600
Depreciation, depletion and amortization		9,774			5,580
Hedge ineffectiveness		66			2,202
Interest		409			586


Total expense		26,021			18,234

Income before income taxes		18,773			10,405

Income tax expense (benefit):
Current		(1,905	)		157
Deferred		9,258			3,935

		7,353			4,092


Net income	$	11,420		$	6,313


Net income per share (basic)	$	0.45		$	0.26

Net income per share (diluted)	$	0.44		$	0.26


Weighted average shares outstanding:
Basic		25,610,676			24,088,159


Diluted		26,073,121			24,678,013

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(unaudited)


	Three Months Ended March 31,
	2012			2011

Net income	$	11,420		$	6,313

Other comprehensive income (loss), net of tax:

Change in fair market value of hedged positions, net of taxes of $1,344 and $3,086, respectively		(2,186	)		(5,122	)

Net realized hedging loss charged to income, net of taxes of $21 and $277, respectively		37			461


Total other comprehensive loss, net of tax		(2,149	)		(4,661	)


Total comprehensive income	$	9,271		$	1,652

The accompanying notes are an integral part of these statements

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

Three Months Ended March 31, 2012

(In thousands, except share data)

(unaudited)


	Common Stock				Additional Paid-in		Retained		Accumulated Other Comprehensive
	Shares		Par value		Capital		Earning		Income (Loss)			Total
Balance, December 31, 2011		25,595,930	$	256	$	281,515	$	85,471	$	1,069		$	368,311

Exercise of employee stock options		31,112		—		300							300

Vesting of restricted stock		4,630		—									—

Excess tax benefit from share-based compensation						91							91

Net income								11,420					11,420

Other comprehensive loss, net of taxes of $1,323										(2,149	)		(2,149	)

Equity based compensation expense						1,166							1,166


Balance, March 31, 2012		25,631,672	$	256	$	283,072	$	96,891	$	(1,080	)	$	379,139

The accompanying notes are an integral part of this statement.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)


	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income	$	11,420		$	6,313
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		9,774			5,580
Gain on sale of property and equipment		(2	)		(736	)
Accretion of asset retirement obligations		107			111
Hedge ineffectiveness loss		66			2,202
Partnership income		(291	)		(410	)
Partnership distributions		557			463
Deferred income taxes		9,258			3,935
Non-cash compensation		1,166			288
Excess tax benefit from share-based compensation		(91	)		(2,050	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(14,138	)		(4,925	)
Decrease (increase) in prepaid expense and other		(1,158	)		(640	)
Increase (decrease) in accounts payable and accrued expense		22,895			4,135

Net cash provided by operating activities		39,563			14,266

Cash flows from investing activities:
Proceeds from sale of property and equipment		2			345
Additions to property and equipment		(117,565	)		(24,251	)

Net cash used in investing activities		(117,563	)		(23,906	)

Cash flows from financing activities:
Proceeds from stock options exercised		300			4,885
Excess tax benefit from share-based compensation		91			2,050
Issuance of common stock		—			122,486
Issuance of long-term debt		60,000			—
Reduction of long-term debt		—			(87,000	)

Net cash provided by financing activities		60,391			42,421


Net increase (decrease) in cash and cash equivalents		(17,609	)		32,781


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


Cash and cash equivalents at end of period	$	21,535		$	42,151

Supplementary information:
Interest paid	$	260		$	302
Income taxes paid	$	16		$	285

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. operates a single business segment involved in the acquisition, exploration, development and production of crude oil, natural gas and related products primarily in Texas, North Dakota, Louisiana, Oklahoma, Montana and Colorado.

Consolidated Financial Statements

The unaudited consolidated financial statements include the accounts of GeoResources, Inc. (“GeoResources” or the “Company”) and its majority-owned subsidiaries. The Company consolidated its non-controlling interest in Trigon Energy Partners, LLC (“Trigon”) from November 2010 until September 2011, at which time the Company deconsolidated the non-controlling interest due to a distribution of all of Trigon’s assets to Trigon’s owners. These 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 has been no material changes to the information disclosed in the notes to the consolidated financial statements included in our 2011 Annual Report on Form 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.

The parent, GeoResources, Inc., has no assets or operations independent of its subsidiaries. The long-term debt of GeoResources, Inc. under its Credit Agreement discussed in Note D is fully and unconditionally guaranteed on a joint and several basis by all of its significant subsidiaries, all of which are wholly owned. Subject to a pledge of all the significant subsidiary assets pursuant to the Credit Agreement, there are no restrictions on the ability of GeoResources, Inc. to obtain funds from its significant subsidiaries. The significant subsidiaries of GeoResources, Inc. are: AROC (Texas) Inc., a Texas corporation; Catena Oil & Gas, LLC; a Texas limited liability company; G3 Energy, LLC, a Colorado limited liability company; G3 Operating, LLC, a Colorado limited liability company; Southern Bay Energy, LLC, a Texas limited liability company; Southern Bay Louisiana, L.L.C., a Texas limited liability company; and Southern Bay Operating, L.L.C., a Texas limited liability company.

Reclassifications

Certain reclassifications have been made to the three month period ended March 31, 2011 amounts on the Company’s Consolidated Statement of Income to conform to the current presentation of property operating income and interest and other income. In the consolidated statement of income for the quarter ended March 31, 2011, certain property operating related revenues have been reclassified from interest and other income to property operating income.

Earnings Per Share

Basic net income per common share is computed based on the weighted average shares of common stock outstanding. Net income per share computations to reconcile basic and diluted net income for the three months ended March 31, 2012 and 2011 consist of the following (in thousands, except per share data):


	Three Months Ended March 31,
	2012		2011

Numerator:
Net income available for common shares	$	11,420	$	6,313

Denominator:
Basic weighted average shares		25,611		24,088
Effect of dilutive securities - share based compensation		462		590

Diluted weighted average shares		26,073		24,678


Earnings per share
Basic	$	0.45	$	0.26

Diluted	$	0.44	$	0.26

For the three months ended March 31, 2012, options to purchase 1,158 shares of common stock, were excluded from the dilutive earnings per share calculation because the effect would have been anti-dilutive. For the period ended March 31, 2011, no options were excluded from the dilutive earnings per share calculation.

For the periods ended March 31, 2012 and March 31, 2011, no restricted stock units were excluded from the dilutive earnings per share calculation because the effect would have been antidilutive.

Warrants to purchase 613,336 shares of common stock were excluded from the dilutive earnings per share calculation for March 31, 2012 and 2011 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 activity from effective date, June 1, 2011 until closing. The acquisition included approximately 3,700 net acres. For the three months ended March 31, 2012, these properties contributed $704,000 of revenue and $474,000 of net income.

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.

On January 20, 2012, the Company closed on an acquisition of unproved leasehold interests in McKenzie County, North Dakota. The Company acquired an average net interest of 10.2% in approximately 3,700 net acres. The Company’s net acquisition cost was $12.7 million and was funded with working capital and borrowings on its credit facility.

On February 29, 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 from the effective date of January 1, 2012, until closing. The acquisition was funded with borrowings on the Company’s credit facility. Through March 31, 2012, these properties contributed $436,000 of revenue and $139,000 of net income.

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 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 ASC Topic 220, Comprehensive Income. The objective of ASU 2011-05 is to require 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 of comprehensive income or in two separate 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 Reclassifications 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 became 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 requirements between 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 facility provides for financing of up to $450 million for the Company. The borrowing base at March 31, 2012 was $180 million. The credit facility 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 upon the amount borrowed. The credit facility also requires the payment of commitment fees to

the lender on the unutilized commitment. The commitment rate is 0.375% per annum if less than 50% of the borrowing based is outstanding and 0.50% per annum if more than 50% of 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 March 31, 2012.

The principal outstanding under the Company’s credit agreement was $60 million at March 31, 2012. The Company had no principal outstanding under the Company’s credit facility at December 31, 2011. The maturity date for amounts outstanding under the credit facility is November 9, 2016.

The remaining borrowing base capacity under the credit facility at March 31, 2012 was $120 million. The annual interest rate in effect at March 31, 2012 was 2.35% on the entire amount of outstanding principal.

Our borrowing base is redetermined on May 1 and November 1of every year. Effective May 4, 2012, the Company’s borrowing base under this credit facility was raised to $210 million.

Interest expense for the three months ended March 31, 2012 and 2011 includes amortization of deferred financing costs of $128,000 and $264,000, respectively.

NOTE E: Stock Options, Performance Awards and Stock Warrants

In March 2007, the shareholders of the Company approved 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 2,000,000 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. In June 2011, the shareholders of the Company approved an amendment to the Plan which increased the number of authorized issuances of stock-based incentives to 3,250,000 shares. The amendment also allows the issuance of performance units, including restricted stock units.

A summary of the Company’s stock option activity for the three months ended March 31, 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		(31,112	)	$	9.64	$	3.09
Forfeited		—

Outstanding, March 31, 2012		750,374		$	10.94	$	4.48		6.70	$	16,363,384


Vested and exercisable		500,374		$	9.47	$	3.43		6.27	$	11,644,397

Vested and expected to vest		747,795		$	10.92	$	4.47		6.69	$	16,318,828

During the three months ended March 31, 2012, 143,750 options vested with a weighted average exercise price of $9.25. The weighted average grant date fair value of these options was $4.34 per option. At March 31, 2012, there were 250,000 unvested options with a weighted average remaining amortization period of 1.73 years.

The Company recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. For the quarters ended March 31, 2012 and 2011 the Company recognized compensation expense of $217,000 and $288,000, respectively, related to these options. As of March 31, 2012, the future pre-tax expense of non-vested stock options is $1.3 million to be recognized through the second quarter of 2015.

In addition to the stock option grants discussed above, during the first quarter of 2012, the Company granted certain officers, employees and directors 167,520 restricted stock units. Each restricted stock unit represents 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 March 31, 2012, compensation expense related to restricted stock units was $949,000. The Company has an assumed forfeiture rate of 1% on restricted stock units issued. As of March 31, 2012, the future unamortized pre-tax compensation expense associated with unvested restricted stock units totaled approximately $8.2 million to be recognized through December 2014. The weighted average vesting period related to unvested restricted stock units at March 31, 2012 was approximately 2.33 years. A summary of the Company’s restricted stock unit activity for the three months ended March 31, 2012, is as follows:


	Units			Fair Values ⁽¹⁾
Outstanding, December 31, 2011		197,050		$	27.72
Granted		167,520			28.69
Vesting ⁽²⁾		(4,630	)		28.64
Forfeited		—			—

Outstanding, March 31, 2012		359,940		$	28.16

(1)	Represents the weighted average grant date market value

(2)	One share of common stock was issued for each restricted stock unit that vested during the period

On June 5, 2008, the Company issued 613,336 warrants to purchase common stock to non-affiliated accredited investors pursuant to exemptions from registration under federal and state securities laws. The warrants have an exercise price of $32.43 and have, as of March 31, 2012, a remaining life of approximately 1 year and 2 months.

NOTE F: Income Taxes

Deferred income taxes are recognized for the tax effects of 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 is 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, and it is remote that the taxing authority would

reexamine the tax position in the future. 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 March 31, 2012, the Company did not have any uncertain tax positions that would require recognition. The Company’s uncertain tax positions could 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.

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 the 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 March 31, 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 March 31, 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 also limit future revenues from favorable price movements.

At March 31, 2012, accumulated other comprehensive income (loss) consisted of unrecognized losses of $1.1 million, net of taxes of $664,000, 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, as of the balance sheet date. At December 31, 2011, accumulated other comprehensive income (loss) consisted of unrecognized gains of $1.1 million, net of taxes of $658,000. For the quarter ended March 31, 2012 and 2011, the Company recognized realized cash settlement losses of $58,000 and $738,000, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at March 31, 2012, the Company expects to reclassify net losses of $864,000 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

During the first quarter of 2012 the Company entered into one additional natural gas swap and three additional crude oil swaps. The natural gas swap has a term of February 2012 to December 2013. The swap has a quantity of 20,000 Mmbtus per month at a fixed price of $2.925 per Mmbtu during 2012 and $3.560 per Mmbtu during 2013. The first of the three crude oil swaps has a term of January 2012 to December 2013. The swap has a quantity of 5,000 Bbls per month at a fixed price of $99.55 per barrel during 2012 and $97.60 during 2013. The second of the three crude oil swaps has a term of January 2012 to December 2013. The swap has a quantity of 5,000 Bbls per month at a fixed price of $107.30 per barrel

during 2012 and $100.70 during 2013. The third crude oil swap has a term of March 2012 to December 2013. The swap has a quantity of 10,000 Bbls per month at a fixed price of $108.45 per barrel during 2012 and $105.55 during 2013.

At March 31, 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		90,000			$	86.85
2012		90,000			$	87.22
2012		90,000			$	103.95
2012		45,000			$	105.00
2012		45,000			$	107.30
2012		45,000			$	99.55
2012		90,000			$	108.45
2013		120,000			$	101.85
2013		60,000			$	100.70
2013		60,000			$	97.60
2013		120,000			$	105.55

Costless collars contracts:
2012		90,000	$	85.00	$	110.00

Natural Gas Contracts (Mmbtu)
Swap contracts
2012		450,000			$	6.415
2012		675,000			$	4.850
2012		180,000			$	2.925
2013		225,000			$	4.850
2013		240,000			$	3.560

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
		Fair Value					Fair Value
	Balance Sheet Location	Mar. 31, 2012		Dec. 31, 2011		Balance Sheet Location	Mar. 31, 2012			Dec. 31, 2011

Commodity contracts	Current derivative financial instruments asset	$	4,320	$	4,037	Current derivative financial instruments liability	$	(5,184	)	$	(2,890	)

Commodity contracts	Long-term derivative financial instruments asset		206		868	Long-term derivative financial instruments liability		(865	)		—


		$	4,526	$	4,905		$	(6,049	)	$	(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 March 31, 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	Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
Derivatives designated as ASC 815 hedges:	Mar. 31, 2012			Mar. 31, 2011			OCI into Income (Effective Portion)	Mar. 31, 2012			Mar. 31, 2011

Commodity contracts		(3,530	)		(8,208	)	Oil and gas revenues		(58	)		(738	)


	$	(3,530	)	$	(8,208	)		$	(58	)	$	(738	)


	Location of Gain or (Loss) Recognized in	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
Derivatives in ASC 815 Cash Flow Hedging Relationships:	Income on Derivative (Ineffective Portion)	Mar. 31, 2012			Mar. 31, 2011

Commodity contracts	Hedge ineffectiveness	$	(66	)	$	(2,202	)

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 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 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 collars are 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 are 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 March 31, 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 - March 31, 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 March 31, 2012
Current portion of derivative financial instrument asset ⁽¹⁾		—	$	4,320			—	$	4,320

Long-term portion of derivative financial instrument asset ⁽¹⁾		—		206			—		206

Current portion of derivative financial instrument liability ⁽¹⁾		—		(5,184	)		—		(5,184	)

Long-term portion of derivative financial instrument liability ⁽¹⁾		—		(865	)		—		(865	)

(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	)

Long-term portion of derivative financial instrument liability ⁽¹⁾		—		—			—		—

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

At March 31, 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.

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 impairments during the three month periods ended March 31, 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 changes 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 Company’s net proceeds from the offering were approximately $122.5 million after underwriting discounts and commissions, and other offering expenses of $6.9 million. Net proceeds from this offering were used to reduce indebtedness and for other corporate purposes.

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 three months ended March 31, 2012, are as follows (in thousands):


Asset retirement obligation, January 1, 2012	$	7,940

Accretion expense		107
Additional liabilities incurred		1,411


Asset retirement obligation, March 31, 2012	$	9,458

NOTE K: Related Party Transactions

Accounts receivable at March 31, 2012, and December 31, 2011, includes $622,000 and $258,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at March 31, 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 March 31, 2012 and December 31, 2011, includes $1.9 million and $2.8 million, respectively, due to SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at March 31, 2012 and December 31, 2011, also includes $610,000 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 partnerships. These revenues are paid monthly to each partnership, which in turn reimburse the Company for the partnership’s share of expenditures. The Company earned partnership management fees during the three months ended March 31, 2012 and 2011 of $101,000 and $111,000, 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 partnership 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 gains in partnership income of $3,000 related to this investment for the three months ended March 31, 2012 and losses of $1,000 for the three months ended March 31, 2011.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings field in Texas. The Company holds a general partner interest of approximately 30%. The Company recorded partnership income related to this investment for each of the three months ended March 31, 2012 and 2011 of $288,000 and $411,000, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at March 31, 2012 and December 31, 2011, was $642,000 and $646,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at March 31, 2012 and December 31, 2011 was $1.3 million and $1.6 million, respectively.

NOTE M: Subsequent Events

Agreement and Plan of Merger

On April 24, 2012, the Company entered into a definitive merger agreement (“Merger Agreement”) with Halcón Resources Corporation (“Parent” and “Halcon”), Leopard Sub I, Inc., a wholly-owned subsidiary of Parent (“Merger Sub”), and Leopard Sub II, LLC, a wholly-owned subsidiary of Parent (“Second Merger Sub”), pursuant to which Parent has agreed to acquire all of the issued and outstanding shares of common stock of the Company. 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 the Company and the Parent, Merger Sub will merge with and into the Company, with the Company surviving as a direct wholly owned subsidiary of Parent (the “Merger”), and shortly thereafter the Company will merge with and into Second Merger Sub, with Second Merger Sub surviving as a direct wholly owned subsidiary of Parent (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 the Company.

The per share consideration is fixed in the Merger Agreement at $20.00 in cash and 1.932 shares of Parent common stock for each issued and outstanding share of the Company’s common stock (excluding shares held by the Company in treasury and dissenting shares in accordance with Colorado law). Outstanding options to purchase shares of the Company’s 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 Parent common stock; outstanding warrants to purchase the Company’s common stock will be assumed by Parent and converted into warrants to acquire Parent common stock; and issued and outstanding restricted stock units of the Company will be settled through the issuance of one share of common stock of the Company in respect of each restricted stock unit and thereafter converted into the right to receive the merger consideration.

Consummation of the transactions contemplated in the Merger Agreement is conditioned upon, among other things, (1) approval by the shareholders of each of the Company and Parent, (2) the receipt of all required regulatory approvals, (3) the 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 the Company’s or Parent’s business, as applicable, (5) receipt of customary tax opinions and (6) the effectiveness of a registration statement relating to the shares of Parent common stock to be issued in the Merger. The Merger Agreement contains certain termination rights and provides that, upon the termination of the Merger Agreement under specified circumstances, the Company will be required to pay Parent a termination fee of approximately $27.8 million, approximately 2.75% of the merger consideration. In certain circumstances involving the termination of the Merger Agreement, the Company or Parent will be obligated to reimburse the other’s expenses incurred in connection with the transactions contemplated by the Merger Agreement in an aggregate amount not to exceed $10 million.

Voting Agreements

In connection with the Merger Agreement, certain of our officers and directors (and certain of their affiliates) entered into a voting agreement dated as of April 24, 2012 with Parent and Merger Sub (the “Company Voting Agreement”). The Company Voting Agreement provides that, among other things, each holder will vote his shares in favor of the approval and adoption of the Merger Agreement and will not sell or transfer his shares until the Company Voting Agreement terminates. The Company Voting Agreement will terminate (i) at the closing of the Merger, (ii) if the Merger Agreement is terminated in accordance with its terms, or (iii) upon any amendment to the Merger Agreement to decrease the merger consideration or otherwise alter the Merger Agreement in a manner adverse to the holder in any material respect. As of the date of the Company Voting Agreement, such holders owned approximately 17.1% of our issued and outstanding common stock.

In connection with the Merger Agreement, HALRES, LLC, a Delaware limited liability company (“HALRES”) entered into a voting agreement dated as of April 24, 2012 with us (the “Parent Voting Agreement”). The Parent Voting Agreement provides

that, among other things, HALRES will vote its shares in favor of the issuance of the Parent common stock to be issued in the Merger and will not transfer its shares until the Parent Voting Agreement terminates. The Parent Voting Agreement will terminate at the Closing of the Merger or if the Merger Agreement is terminated in accordance with its terms. As of the date of this Parent Voting Agreement, HALRES owned approximately 51% of the issued and outstanding common stock of Parent.

Merger-Related Litigation

As of May 3, 2012, five putative class action lawsuits had been filed in the District Court of Harris County, Texas against the Company, each of its directors, Halcón and certain Halcón subsidiaries, and in one lawsuit, HALRES. The lawsuits have each been brought by a purported stockholder of the Company and allege, among other things, that the members of our board of directors, aided and abetted by us and Halcón, and in one lawsuit, HALRES, breached their fiduciary duties to our stockholders by entering into the Merger Agreement for merger consideration the plaintiffs claim is inadequate and 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, as well as damages, expenses, and attorneys’ fees. We believe these suits are without merit and intend to vigorously defend against such claims. There may be additional lawsuits of a similar nature.

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 for the year ended December 31, 2011.

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 future 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 regulations, and changes in state, and federal 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 for the year ended December 31, 2011, as may be supplemented and updated from time to time in our other SEC filings.

•

risks that may arise, or be associated, with our proposed merger with Halcon Resources, Inc. as described in Note M.

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.

General 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, cash flows and share values 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, and assemble an oil and gas reserve base with a market value exceeding its acquisition, development and production costs.

Our strategy includes a combination of acquisition, development drilling and exploration activities. Our capital structure and diverse asset portfolio allows us to shift our emphasis among these basic activities to take advantage of changing market conditions and to facilitate profitable growth. The majority of our efforts are currently focused on developing our oil-weighted acreage positions in the Bakken Shale trend of North Dakota and Montana, the Eagle Ford trend of Texas and to a lesser extent the Austin Chalk trend of Texas. In addition, it is essential that, over time, our personnel expand our current projects and/or generate additional projects so we have the potential of economically replacing our production and increasing our proved reserves. Following is a brief outline of our current plans:

•

Accelerating the cost-effective development and exploitation of our existing acreage positions with a focus on our properties in the Bakken, Eagle Ford and Austin Chalk trends;

•

Expanding our acreage positions and drilling inventory in and around our focus areas through acquisitions and farm-in opportunities with an emphasis on operated positions and selective non-operated participations with other capable operators;

•

Generating additional exploration and development projects in and around our focus areas;

•

Selectively divesting of legacy assets to high-grade our property portfolio and to lower corporate wide “per-unit” operating and administrative costs, and focus our attention on our current focus areas and new projects with greater development and exploitation potential;

•

Pursuing value-accretive corporate merger and acquisition opportunities; and

•

Obtain additional capital, as needed, through the issuance of equity securities and/or through debt financing.

While the impact and success of our corporate plans cannot be predicted with accuracy, our goal is to replace production and further increase our reserve base at an acquisition or finding cost that will yield attractive rates of return.

As part of our fundamental business strategy, we intend to pursue selective asset acquisitions and corporate acquisitions and mergers. We believe that asset acquisitions and/or corporate acquisitions or mergers could potentially accelerate growth, increase market visibility and allow us to realize operating and administrative benefits. Accordingly, we intend to consider any such opportunities which may become available that we consider beneficial to our shareholders. The primary financial considerations in the evaluation of any such potential transactions include, but are not limited to: (1) the potential to increase assets and drilling inventory in our focus areas, (2) the opportunity to increase our earnings and cash flow on a per share basis, (3) opportunities for development and/or exploration upside, and (4) potential realization of operating and/or administrative savings. Further, we believe a corporate acquisition could lead to increased visibility in the market place, greater trading volume and therefore greater shareholder liquidity and possibly access to capital with lower costs.

The overview and strategy set forth above may be significantly changed if our proposed Merger with Halcon, as discussed in Note M, is consummated as expected in the third quarter of 2012.

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 February 29, 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. The acquisition was funded with borrowings on our credit facility.

Recent Event

On April 24, 2012, the Company entered into a definitive merger agreement with Halcón Resources Corporation (“Halcon”), in which the Company will merge into a wholly-owned subsidiary of Halcón in a cash and stock transaction that value the Company at approximately $1.0 billion, based on the closing price of Halcón’s common stock on April 24, 2012. Under the terms of the merger agreement, Halcón will acquire all the outstanding shares of the Company’s common stock. The Company’s stockholders will receive $20.00 in cash and 1.932 shares of Halcón common stock for each share of the Company’s common stock they hold, representing consideration to the Company’s stockholders of $37.97 per share based on the closing price of Halcón common stock of $9.30 per share on April 24, 2012. See Note M for further discussion.

Results of Operations

Three months ended March 31, 2012, compared to three months ended March 31, 2011.

The Company recorded net income of $11.4 million for the three months ended March 31, 2012 compared to net income of $6.3 million for the same period in 2011. This $5.1 million increase resulted primarily from the following factors:


Net amounts contributing to increase (decrease) in net income (in 000s):

Oil and gas sales	$	15,950
Lease operating expenses		(2,233	)
Production taxes		(1,201	)
Exploration expense		(47	)
Re-engineering and workovers		(378	)
General and administrative expenses (“G&A”)		(2,047	)
Depletion, depreciation and amortization expense (“DD&A”)		(4,194	)
Hedge ineffectiveness		2,136
Gain (loss) on sale of property		(734	)
Interest expense		177
Other income - net		939

Income before income taxes		8,368
Provision for income taxes		(3,261	)

Net income	$	5,107

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $16.0 million, or 60%. Sales are a function of oil and gas volumes sold and average sales prices. The majority of the increase is due to a $14.6 million increase in volumes sold. Oil volumes accounted for $13.2 million of the increase and gas volumes accounted for the remaining $1.4 million. Commodity prices resulted in a $1.3 million increase in revenue, which was comprised of a $2.5 million increase as a result of oil prices, offset by a $1.2 million decrease due to gas prices. Our gas production increased by 27% 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 62% in the first quarter of 2012 compared to the first quarter of 2011 as a result of successful drilling in our Bakken and Eagle Ford areas. Also, our 2011 oil production was lower than we had initially expected due to production delays related to severe weather conditions which affected our production operations and support services in North Dakota.


	Percent			Three Months
	increase			Ended March 31,
	(decrease)			2012		2011

Oil Production (Mbbls)		62	%		405		250
Gas Production (MMcf)		27	%		1,288		1,011
Barrel of Oil Equivalent (MBOE)		48	%		620		419
Average Price Oil Before Hedge Settlements (per Bbl)		2	%	$	95.01	$	93.03
Average Realized Price Oil (per Bbl)		7	%	$	91.68	$	85.37
Average Price Gas Before Hedge Settlements (per Mcf)		-20	%	$	3.22	$	4.03
Average Realized Price Gas (per Mcf)		-19	%	$	4.23	$	5.20

Lease Operating Expense. Lease operating expenses (“LOE”) increased from approximately $5.0 million in the first quarter of 2011 to $7.3 million for the same period in 2012, an increase of $2.3 million or 44%. Included in lease operating expenses are ad valorem taxes of $347,000 and $272,000 for the three months period ending March 31, 2012 and 2011, respectively. Our LOE, excluding ad valorem taxes, increased due to the higher number of producing wells, coupled with increased industry wide service costs and demand for labor. However, on a per unit basis, LOE costs (excluding ad valorem taxes) per BOE decreased from $11.34 in 2011 to $11.14 in 2012.

Re-engineering and workover. Re-engineering and workover costs increased from $394,000 in the first quarter of 2011 to $772,000 for the same period in 2012, an increase of $378,000 or 96%. Reengineering

and workover projects occur in different fields and at different times due to operational matters 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 $1.2 million or 74%. 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 quarter ended March 31, 2012 and 2011 were 6.6% and 5.9%, respectively, of oil and gas sales before the effects of hedging. The increase was due to a shift in production from lower costs tax jurisdictions to higher costs jurisdictions.

General and Administrative Expenses. G&A increased by approximately $2.0 million or 79% primarily due to increases in personnel hired in the last 12 months, general pay increases and non-cash stock-based compensation expense. The total non-cash charges related to stock-based compensation included in G&A expense for the three month periods ended March 31, 2012 and 2011 were $1.2 million and $288,000, respectively. The increase in stock-based compensation was primarily due to the restricted stock units granted during 2011 and the first quarter of 2012.

Depreciation, Depletion and Amortization. DD&A expense increased by $4.2 million or 75%, due to higher capitalized costs and increases in production. Capitalized costs increased due to acquisitions of additional property interests and continued successful drilling in the Eagle Ford and Bakken trends. On a units-of-production basis, for the three months ended March 31, 2011 and 2012, DD&A per BOE increased from $13.33 to $15.77.

Interest Expense. Interest expense decreased by $177,000 due to a decrease in the amortization of deferred financing costs. Interest expense includes amortization of deferred financing costs and payment of loan fees. For the three months ended March 31, 2012 and 2011 amortization of deferred financing costs were $128,000 and $264,000, respectively.

Hedge Ineffectiveness. During the first quarter of 2012 the loss from hedge ineffectiveness was $66,000 compared to a loss of $2.2 million for the same period in 2011. The ineffectiveness in 2012 and 2011 related to our derivatives accounted for as a cash flow hedges, which decreased in value. The change in the ineffective portion of these derivatives was a loss.

Other Income. Other income increased by $939,000 or 73% primarily due to property operating income increasing by $1.1 million as a result of an increase in the number of operated wells and fees earned on operated wells drilled. This increase was offset by a decrease in partnership income of $119,000 in the first quarter of 2012 compared to the same period in 2011.

Income Tax Expense. Income tax expense for the first quarter of 2012 was $7.4 million compared to $4.1 million for the same period in 2011. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the first quarter of 2012 was approximately 39.17% versus 39.33% in the same period during 2011.

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 can be 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 $91.68 per Bbl, net of hedges, for the three months ended March 31, 2012, was 7% higher than for the comparable period in 2011. Our average realized natural gas price of $4.23 per Mcf, net of hedges, for the three months ended March 31, 2012, was 19% lower than for the comparable period in 2011. Should significant 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 and will likely continue to enter into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. Management believes our hedging strategy will result in greater predictability of internally generated funds, which can be dedicated to capital development projects and corporate obligations.

We do not engage in speculative commodity trading activities and do not hedge all available or anticipated quantities. Our strategy with regard to hedging includes the following factors:

(1)

Secure and maintain favorable debt financing terms;

(2)

Minimize price volatility and generate internal funds available for capital development projects and additional acquisitions;

(3)

“Lock-in” growth in revenues, cash flows and profits for financial reporting purposes; and

(4)

Allow certain quantities to float, particularly in months with high price potential.

We believe that commodity speculation and trading activities are inappropriate for us, but further believe appropriate management of realized prices is an integral part of managing our business strategy.

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. We believe that as our production increases in our focus areas we will reduce per unit operating expenses through various means, including but not limited to, increasing Company employed (rather than third-party employed) operating personnel and installation of salt-water disposal facilities, among other means. We must continue to attract and retain competent management, technical, operating and administrative personnel to successfully pursue our business strategy. Our industry has experienced a shortage of such personnel over the past few years, and we expect this shortage to continue as long as oil prices and demand for services in our key operating areas remain at high levels.

Liquidity and Capital Resources

We expect to finance our future acquisition, development and exploration activities through working capital, cash flow from operating activities, our bank credit facility, sale of non-strategic assets, various means of corporate and project finance and possibly through the issuance of additional debt and equity securities. In addition, we intend to continue to partially finance our drilling activities through the sale of participations to industry partners on a promoted basis, whereby we will earn working interests in reserves and production greater than our proportionate capital cost.

Credit Facility

As of March 31, 2012, our borrowing base under our credit facility with Wells Fargo Bank was $180 million and we had borrowings of $60 million outstanding. Subsequent to quarter-end, we borrowed $20 million. As of May 4, 2012 our outstanding balance under the credit facility was $80 million. The borrowing base is subject to redetermination on May 1 and November 1 of each year. Effective May 4, 2012, the Company’s borrowing base under this credit facility was raised to $210 million.

Cash Flows from Operating Activities

For the three months ended March 31, 2012, our net cash provided by operating activities was $39.6 million, versus $14.3 million from the same period in 2011. We believe that we have sufficient liquidity and capital resources to execute our business plans over the next twelve months and foreseeable future. We expect to fund our planned capital program through debt, working capital and projected cash flows.

Cash Flows from Investing Activities

Cash applied to oil and gas capital expenditures for the three months ended March 31, 2012 and 2011, was $117.6 million and $24.3 million, respectively. During the first quarter 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. Capital expenditures for the three months ended March 31, 2012 were financed with working capital and long-term debt. In addition, cash generated from the sale of oil and gas properties for the three months ended March 31, 2012 and 2011 was $2,000 and $345,000, respectively. We expect to spend approximately $129 million and $207 million in additional capital expenditures during the remainder of 2012 and 2013, respectively.

Capital Budget

We continue to expand our portfolio of drilling and development projects and therefore have increased our projected drilling and development expenditures compared to prior years. As summarized below, our current expectation is for the 2012 capital budget to be between approximately $247 million and $325 million. The table below illustrates the components of the 2012 budget, as presently contemplated. A benefit of our property portfolio is that it consists of relatively new acreage positions and therefore we generally have two to four years to drill the bulk of our undeveloped leases. In addition, many of our drilling opportunities, including the bulk of our gas drilling locations, are “held by production” or long term leases and therefore not subject to lease expiration or significant future incremental carrying costs. Accordingly, we have a substantial ability to adjust our capital spending as industry circumstances dictate or as opportunities arise.

We have initiated drilling on our operated Bakken acreage in the Williston Basin and our operated Eagle Ford acreage in Texas. Further, our Bakken non-operated holdings continue to be actively developed by our operating partners. However, we continue to evaluate adjusting our expenditures between geographic areas and projects in an attempt to maximize production, reserve growth and cash flow and take advantage of regional differences in net commodity prices and service costs, while effectively transforming our acreage to held-by-production status.

While industry circumstances may require us to make capital expenditure adjustments, our capital budget reflects our current intent to develop our Bakken and Eagle Ford positions and further expand our acreage. To a lesser extent, we intend to drill certain locations in the Austin Chalk and certain of our prospects on conventional properties, but those projects could be deferred in favor of increased activity in these other areas or so long as low natural gas prices prevail.

The projects, estimated costs and timing of actual expenditures seen below are subject to significant change as we continue to technically and economically evaluate existing and alternative projects, as we further expand our property portfolio, and as industry conditions dictate. There can be no assurance that all of the projects identified and summarized in the table below will remain economically viable and therefore certain projects may be sold or deferred by us to redeploy capital elsewhere. However, in the opinion of management, at present, we have sufficient cash flows and liquidity to fulfill lease obligations or otherwise maintain all of our material mineral leases. Our current estimate of capital expenditures for 2012 is as follows:


2012 Capital Expenditure Guidance					($ in millions)
	Low		High		Notes

Bakken (Williams County Project Area)	$	45	$	58	20-24 gross wells at $7.5-$8.0MM (30% WI)
Bakken (Eastern Montana Project Area)		10		18	3-5 gross wells at $7.5-$8.0MM (45% WI)
Bakken (Mountrail Project Area)		19		28	46-60 gross wells at $5.5-$8.5 MM (65% WI)
Bakken (McKenzie Line Project Area)		6		8	6-8 gross wells at $9.5-$10.5MM (10% WI)
Eagle Ford		73		98	20-24 gross wells at $8.0-$9.00MM (46% WI)
Austin Chalk		3		7	2-4 gross wells at $2.8-$3.3MM (50% WI)
Other Drilling		10		14	Other


Total Drilling Capital Expenditures	$	166	$	231

Acreage and Seismic		25		35	Bakken and Eagle Ford Primarily
Infrastructure and Other		3		6	Saltwater disposal, etc.

Total Capital Expenditure Excl. Acquisitions	$	194	$	272

1Q 2012 Acquisitions (Bakken and Chalk)		53		53	McKenzie Line & Brookeland Acquisitions.


Total Capital Expenditures	$	247	$	325

NOTE: The data in the “High” column above is based on well cost assumptions using figures we previously experienced early on in our drilling activities in these areas. Our goal is to reduce well costs below the amounts indicated above. See the “Low” column. Management believes that Bakken well costs of $7.5 million and Eagle Ford wells costs of $8.0 million are attainable under current market conditions.

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 March 31, 2012:

Transaction
Type

Beginning

Ending

Price Per Unit

Remaining
Annual Volumes

Fair Value
Outstanding
as of
March 31,
2012

(in thousands)

Swap

04/01/12

12/31/12

$6.415

450,000 Mmbtu

1,804

Swap

01/01/12

03/31/13

4.850

900,000 Mmbtu

2,008

Swap

02/01/12

12/31/12

2.925

180,000 Mmbtu

Swap

01/01/13

12/31/13

3.560

240,000 Mmbtu

3,944

Swap

01/01/12

12/31/12

$86.85

90,000 Bbls

(1,619

)

Swap

01/01/12

12/31/12

$87.22

90,000 Bbls

(1,585

)

Collar

01/01/12

12/31/12

$85.00 - $110.00

90,000 Bbls

(249

)

Swap

01/01/12

12/31/12

$103.95

90,000 Bbls

Swap

01/01/13

12/31/13

$101.85

120,000 Bbls

(224

)

Swap

01/01/12

12/31/12

$105.00

45,000 Bbls

(635

)

Swap

01/01/12

12/31/12

$107.30

45,000 Bbls

(518

)

Swap

01/01/13

12/31/13

$100.70

60,000 Bbls

(624

)

Swap

01/01/12

12/31/12

$99.55

45,000 Bbls

(215

)

Swap

01/01/13

12/31/13

$97.60

60,000 Bbls

(383

)

Swap

03/01/12

12/31/12

$108.45

90,000 Bbls

388

Swap

01/01/13

12/31/13

$105.55

120,000 Bbls

194

(5,467

)

(1,523

)

Interest rates. We are exposed to financial risk from changes in future interest rates to the extent that we incur future indebtedness. As of March 31, 2012, we had $60 million outstanding under our Third Amended and Restated Credit Agreement, which matures in November 2016. 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.

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 March 31, 2012. Based upon their evaluation of these disclosure controls and procedures, our Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of March 31, 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 March 31, 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

As discussed above, we have entered into the Merger Agreement with Halcón. As of May 3, 2012, five putative stockholder lawsuits styled as class actions have been filed against us and our Board of Directors challenging our proposed merger with Halcón. All five lawsuits also name Halcón has a defendant. Four of the lawsuits also name Halcón’s subsidiaries as defendants, and one lawsuit names HALRES as a defendant. The lawsuits are as follows:


Plaintiff	Defendants	Court	Filed
Hilary Coyne	Frank A. Lodzinski, Robert J. Anderson, Jay F. Joliat, Bryant W. Seaman, III, Michael A. Vlasic, Nicholas L. Voller, Donald J. Whelley, GeoResources, Inc., Halcón Resources Corporation, Leopard Sub I, Inc., and Leopard Sub II, LLC.	District Court of Harris County, Texas; 24^th Judicial District.	04/26/2012

Bruno Eisner	GeoResources, Inc., Halcón Resources Corporation, Frank A. Lodzinski, Robert J. Anderson, Jay F. Joliat, Bryant W. Seaman, III, Michael A. Vlasic, Nicholas L. Voller, Donald J. Whelley, Leopard Sub I, Inc., and Leopard Sub II, LLC	District Court of Harris County, Texas	04/30/2012

George Assad	Frank A. Lodzinski, Robert J. Anderson, Jay F. Joliat, Bryant W. Seaman, III, Michael A. Vlasic, Nicholas L. Voller, Donald J. Whelley, GeoResources, Inc., and Halcón Resources Corporation	District Court of Harris County, Texas	05/01/2012

Vernon and Roberta Futterman	GeoResources, Inc., Frank A. Lodzinski, Robert J. Anderson, Jay F. Joliat, Bryant W. Seaman, III, Michael A. Vlasic, Nicholas L. Voller, Donald J. Whelley, Halcón Resources Corporation, HALRES, LLC, Leopard Sub I, Inc., and Leopard Sub II, LLC	District Court of Harris County, Texas; 61st Judicial District.	05/02/2012

Employees’ Retirement System of the Government of the Virgin Islands	GeoResources, Inc., Frank A. Lodzinski, Robert J. Anderson, Jay F. Joliat, Bryant W. Seaman, III, Michael A. Vlasic, Nicholas L. Voller, Donald J. Whelley, Halcón Resources Corporation, Leopard Sub I, Inc., and Leopard Sub II, LLC	District Court of Harris County, Texas; 127^th Judicial District.	05/03/2012

The lawsuits generally allege that the members of our board of directors, aided and abetted by us, Halcón, and in one lawsuit, HALRES, breached their fiduciary duties to our stockholders by entering into the Merger Agreement for merger consideration plaintiffs claim is inadequate and pursuant to a process 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, as well as damages, expenses, and attorneys’ fees. We believe these suits are without merit and we intend to vigorously defend against such claims. There may be additional lawsuits of a similar nature.

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 1 A- Risk Factors” in our Annual Report for the year ended December 31, 2011 on Form 10-K, which could materially affect our business, financial condition or future results. The Risks described in our 2011 Annual Report on Form 10-K 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 quarter ended March 31, 2012.



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

31.2		Certification of the Principal 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.

Pursuant to Rule 406T of Regulation S-T, these interactive data files 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.

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.


		GEORESOURCES, INC.

May 8, 2012

		/s/ Frank A. Lodzinski
		Frank A. Lodzinski
		Chief Executive Officer (Principal Executive Officer)

		/s/ Howard E. Ehler
		Howard E. Ehler

Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

Larger accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

GEORESOURCES INC 10-Q