GEORESOURCES INC - FORM 10-Q

GEORESOURCES INC - FORM 10-Q - August 8, 2011

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

Quarterly Report Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

For the Quarterly Period ended June 30, 2011

Commission File Number – 0-8041

LOGO

GEORESOURCES, INC.

(Exact name of registrant as specified in its charter)


Colorado		84-0505444
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

110 Cypress Station Drive, Suite 220 Houston, Texas		77090-1629
(Address of principal executive offices)		(Zip code)

(281) 537-9920

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registration was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

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

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

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


Class of equity		Outstanding at August 5, 2011
Common stock, par value $.01 per share		25,471,480 shares

TABLE OF CONTENTS


	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements.

		Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010.	3

		Consolidated Statements of Income for the Three and Six Months ended June 30, 2011 and 2010.	5

		Consolidated Statement of Equity and Comprehensive Income for the Six Months ended June 30, 2011.	6

		Consolidated Statements of Cash Flows for the Six Months ended June 30, 2011 and 2010.	7

		Notes to Consolidated Financial Statements.	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.		35

Item 4.	Controls and Procedures.		36

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.		37

Item 1A.	Risk Factors.		37

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.		37

Item 3.	Defaults Upon Senior Securities.		37

Item 4.	Reserved.		37

Item 5.	Other Information.		37

Item 6.	Exhibits.		38

	Signatures.		39

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	June 30,			December 31,
	2011			2010
	(unaudited)
ASSETS

Current assets:
Cash	$	48,290		$	9,370
Accounts receivable:
Oil and gas revenues		21,096			17,017
Joint interest billings and other		34,450			16,631
Affiliated partnerships		794			969
Notes receivable		120			120
Derivative financial instruments		2,741			4,282
Income taxes receivable		2,147			222
Prepaid expenses and other		4,021			2,645

Total current assets		113,659			51,256


Oil and gas properties, successful efforts method:
Proved properties		363,696			341,582
Unproved properties		51,885			32,403
Office and other equipment		1,326			1,140
Land		146			146

		417,053			375,271

Less accumulated depreciation, depletion and amortization		(81,240	)		(72,380	)

Net property and equipment		335,813			302,891


Equity in oil and gas limited partnerships		2,723			2,272

Derivative financial instruments		464			851

Deferred financing costs and other		2,100			2,420

	$	454,759		$	359,690

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	June 30,			December 31,
	2011			2010
	(unaudited)
LIABILITIES AND EQUITY

Current liabilities:

Accounts payable	$	20,915		$	14,616
Accounts payable to affiliated partnerships		3,107			2,931
Revenue and royalties payable		15,620			12,450
Drilling advances		19,226			4,203
Accrued expenses		3,441			1,331
Derivative financial instruments		5,134			7,433

Total current liabilities		67,443			42,964


Long-term debt		—			87,000

Deferred income taxes		28,464			19,289

Asset retirement obligations		6,970			7,052

Derivative financial instruments		1,441			1,650

Stockholders’ equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 25,462,930 in 2011 and 19,726,566 in 2010		255			197
Additional paid-in capital		278,557			148,172
Accumulated other comprehensive income		(2,238	)		(3,000	)
Retained earnings		69,312			54,133


Total GeoResources, Inc. stockholders’ equity		345,886			199,502
Noncontrolling interest		4,555			2,233

Total equity		350,441			201,735

	$	454,759		$	359,690

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except share and per share amounts)

(unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010

Revenue:
Oil and gas revenues	$	29,292		$	24,343		$	55,906		$	49,072
Partnership management fees		131			140			242			299
Property operating income		923			393			1,361			784
Gain on sale of property and equipment		1			—			737			145
Partnership income		505			488			915			1,342
Interest and other		28			1,042			358			1,340


Total revenue		30,880			26,406			59,519			52,982

Expenses:
Lease operating expense		5,747			5,193			10,766			10,217
Severance taxes		1,898			1,540			3,519			3,323
Re-engineering and workovers		709			255			1,103			508
Exploration expense		124			139			356			603
Impairment of oil and gas properties		—			2,743			—			2,743
General and administrative expense		2,962			2,039			5,562			3,858
Depreciation, depletion and amortization		6,348			5,962			11,928			12,313
Hedge ineffectiveness		(1,561	)		(61	)		641			(316	)
Gain on derivative contracts		—			(17	)		—			(4	)
Interest		452			1,285			1,038			2,558


Total expense		16,679			19,078			34,913			35,803

Income before income taxes		14,201			7,328			24,606			17,179

Income tax expense (benefit):
Current		641			912			798			1,865
Deferred		4,781			1,973			8,716			4,797

		5,422			2,885			9,514			6,662

Net income	$	8,779		$	4,443		$	15,092		$	10,517


Less: Net loss attributable to noncontrolling interest		(87	)		—			(87	)		—


Net income attributable to GeoResources, Inc.	$	8,866		$	4,443		$	15,179		$	10,517


Net income per share (basic)	$	0.35		$	0.23		$	0.61		$	0.53


Net income per share (diluted)	$	0.34		$	0.22		$	0.60		$	0.52


Weighted average shares outstanding:
Basic		25,460,622			19,723,916			24,778,182			19,716,722

Diluted		25,861,849			20,113,189			25,271,578			20,073,598

The accompanying notes are an integral part of these statements

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY and COMPREHENSIVE INCOME

Six Months Ended June 30, 2011

(In thousands, except share data)

(unaudited)


	Common Stock				Additional Paid-in Capital		Retained		Accumulated Other Comprehensive			Non- controlling			Total
	Shares		Par value		Additional Paid-in Capital		Earnings		Income (Loss)			Interest			Total
Balance, December 31, 2010		19,726,566	$	197	$	148,172	$	54,133	$	(3,000	)	$	2,233		$	201,735

Issuance of common stock
For cash, net of issuance costs of $6,469		5,175,000		52		122,434										122,486

Exercise of employee stock options		561,364		6		5,016										5,022

Excess tax benefit from share-based compensation						2,125										2,125

Comprehensive income:
Net income (loss)								15,179					(87	)		15,092
Change in fair market value of hedged positions, net of taxes of $484										(804	)					(804	)
Hedging losses charged to income, net of taxes of $944										1,566						1,566

Total comprehensive income																15,854


Equity based compensation expense						810										810

Capital contribution by noncontrolling interest													2,409			2,409


Balance, June 30, 2011		25,462,930	$	255	$	278,557	$	69,312	$	(2,238	)	$	4,555		$	350,441

The accompanying notes are an integral part of this statement.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)


	Six Months Ended June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	15,092		$	10,517
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		11,928			12,313
Proved property impairments		—			2,743
Gain on sale of property and equipment		(737	)		(145	)
Accretion of asset retirement obligations		224			200
Unrealized gain on derivative contracts		—			(205	)
Hedge ineffectiveness (gain) loss		641			(316	)
Partnership income		(915	)		(1,342	)
Partnership distributions		465			2,201
Deferred income taxes		8,716			4,797
Non-cash compensation		810			494
Excess tax benefit from share-based compensation		(2,125	)		—
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(21,705	)		9,805
Increase in prepaid expense and other		(789	)		(607	)
Increase (decrease) in accounts payable and accrued expense		26,777			(8,623	)

Net cash provided by operating activities		38,382			31,832

Cash flows from investing activities:
Proceeds from sale of property and equipment		345			425
Additions to property and equipment, net of cost recoveries of none in 2011 and $18,529 in 2010		(42,440	)		(29,110	)

Net cash used in investing activities		(42,095	)		(28,685	)

Cash flows from financing activities:
Proceeds from stock options exercised		5,022			92
Excess tax benefit from share-based compensation		2,125			—
Issuance of common stock		122,486			—
Reduction of long-term debt		(87,000	)		—

Net cash provided by financing activities		42,633			92


Net increase in cash and cash equivalents		38,920			3,239


Cash and cash equivalents at beginning of period		9,370			12,660


Cash and cash equivalents at end of period	$	48,290		$	15,899


Supplementary information:
Interest paid	$	485		$	2,025
Income taxes paid	$	627		$	115

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, development and production of, and exploration for, 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 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. GeoResources’ 2010 Annual Report on Form 10-K 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 GeoResources’ 2010 Annual Report on Form 10-K. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to common shares by the basic weighted-average shares of outstanding common stock. The calculation of diluted earnings per share is similar to basic, except the denominator includes dilutive common stock equivalents. Dilutive common stock equivalents consist of unvested restricted stock awards and outstanding stock options. Net income per share computations reconciling basic and diluted net income for the three and six months ended June 30, 2011 and 2010 consist of the following (in thousands, except per share data):


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Numerator:
Net income attributable to GeoResources, Inc. common shares	$	8,866	$	4,443	$	15,179	$	10,517

Denominator:
Basic weighted average shares		25,461		19,724		24,778		19,717
Effect of dilutive securities - share-based compensation		401		389		494		357

Diluted weighted average shares		25,862		20,113		25,272		20,074

Earnings per share:
Basic	$	0.35	$	0.23	$	0.61	$	0.53
Diluted	$	0.34	$	0.22	$	0.60	$	0.52

For the three and six month periods ended June 30, 2011, options to purchase 20,000 shares of common stock, respectively, were excluded from the dilutive earnings per share calculation because the options’ exercise prices exceed the average market price of the common stock during the period. For the three and six month periods ended June 30, 2010, options to purchase 95,000 and 110,000 shares of common stock, respectively, were excluded from the dilutive earnings per share calculation because the options’ exercise prices exceeded the average market price of the Company’s common shares during the period.

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

For the three and six month period ended June 30, 2011 and 2010, warrants to purchase 613,336 shares of common stock were excluded from the dilutive earnings per share calculation because the warrants’ exercise price exceeded the average market price of the Company’s common shares during these periods.

NOTE B: Acquisitions and Dispositions

In November 2010, the Company purchased an 86.67% membership interest in Trigon Energy Partners LLC (“Trigon”) in order to acquire and develop leases in the Eagle Ford shale trend of Texas. The acquisition cost was approximately $11.8 million. In June 2011, the Company’s membership interest decreased to 73.34% as a result of a $2.2 million capital contribution by the non-controlling interest holder. The Company fully consolidates Trigon and recorded a non-controlling interest of $4.6 million on our June 30, 2011 financials. Trigon generated a net loss of $327,000 for both the three months ended and the six months ended June 30, 2011.

In September 2010, the Company entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford shale trend of Texas. As part of this agreement, the Company sold a 50% working interest in approximately 20,000 acres for $20 million. For accounting purposes, the Company uses the cost recovery method; under this method proceeds from joint owners are recorded in the balance sheet as a reduction of the carrying value of unproved properties. The purchaser also agreed to pay 100% of the drilling costs for the first six wells to be drilled in a contractually specified area of mutual interest (“AMI”). The agreement also provides for an additional $20 million for additional joint leasing within the AMI ($10 million net to each entity). Subsequent to the initial closing, the Company and the joint owners have continued to acquire leases within the AMI pursuant to the terms of the agreement.

In July 2010, the Company closed an acquisition of producing oil and gas properties located in the Giddings field of central Texas. The purchase price was $16.6 million plus closing adjustments for normal operating activity. The acquisition included approximately 9,700 net acres and was funded through borrowings under the Company’s credit facility.

NOTE C: Recently Issued Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, companies are also required to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. We will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012 and are currently evaluating the provisions of this update.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU issued authoritative guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. The ASU expands existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place, and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the

interrelationships between those inputs. Entities will also be required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

Other amendments include clarifying the highest and best use and valuation premise for nonfinancial assets, net risk position fair value measurement option for financial assets and liabilities with offsetting positions in market risks or counterparty credit risk, premiums and discounts in fair value measurement, and fair value of an instrument classified in a reporting entity’s shareholders’ equity.

ASU 2011-04 is effective during interim and annual periods beginning after December 15, 2011, and therefore will become effective for the Company on January 1, 2012 for the quarter ending March 31, 2012. Other than the disclosure requirements, ASU 2011-04 is not expected to have a significant impact on the Company’s consolidated financial statements.

NOTE D: Long-term Debt

The Company has a $250 million credit facility with a borrowing base at June 30, 2011 of $145 million. The credit facility provides for annual interest rates at (a) LIBOR plus 2.25% to 3.00% or (b) the prime rate plus 1.25% to 2.00%, 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 0.50% per annum. The Company is also required to pay customary letter of credit fees. All of the obligations under the credit facility, and guarantees of those obligations, are secured by substantially all of the Company’s assets.

The credit facility requires the maintenance of certain financial ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at June 30, 2011.

The Company has no principal outstanding under the Company’s credit facility at June 30, 2011. In the first quarter of 2011, the Company used certain net proceeds from the public offering of our common stock, discussed in Note I, to pay our outstanding indebtedness under the credit facility. The principal outstanding under the Company’s credit agreement was $87 million at December 31, 2010. The maturity date for amounts outstanding under the Second Amended Credit Agreement is October 16, 2012.

Interest expense for the three months ended June 30, 2011 and 2010 includes amortization of deferred financing costs of $269,000 and $264,000, respectively. Interest expense for the six months ended June 30, 2011 and 2010 includes amortization of deferred financing costs of $533,000 and $528,000, respectively.

In connection with the initial borrowing from the bank under the credit facility the Company entered into an interest rate swap. The purpose was to protect the Company from undue exposure to interest rate increases. The swap agreement provided a fixed rate of 4.79% on a notional $50 million through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million swap each with a fixed rate of 4.29%. The $40 million swap is accounted for as a cash flow hedge while the $10 million swap is marked-to-market with gains and losses included in the Company’s Consolidated Statement of Income. These swaps expired in October 2010.

For the three and six months ended June 30, 2010, the Company recognized realized cash settlement losses of $404,000 and $806,000, respectively, related to this swap.

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. 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.

The options granted under the Plan can be designated as either incentive options or nonqualified options. The following is a summary of the terms of the June 2011 option grants by exercise price:


	Number of Shares Exercisable at:
Vesting Date	$23.00		$27.00

Director
June 6, 2012		5,000		5,000
June 6, 2013		5,000		5,000
June 6, 2014		5,000		5,000
June 6, 2015		5,000		5,000


		20,000		20,000

The closing market price of the Company’s common stock on the date of the June 2011 grants was $21.57.

The weighted-average fair value of the options granted during the six months ended June 30, 2011, was $11.50 per share, using the following assumptions:


	June 7, 2011 Grant

Risk-free interest rate		1.58	%
Dividend yield		None
Volatility		67	%
Weighted average expected life of options		5.00
Estimated forfeiture rate		1	%

A summary of the Company’s stock option activity for the six months ended June 30, 2011 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, 2010		1,494,350		$	9.70	$	3.49		7.34	$	18,701,164

Granted		40,000		$	25.00	$	11.50			$	—
Exercised		(569,864	)	$	9.25	$	2.90			$	10,630,205
Canceled/forfeited		—

Outstanding, June 30, 2011		964,486		$	10.60	$	4.18		7.05	$	11,568,854


Vested and exercisable		348,236		$	9.41	$	3.53		6.64	$	4,553,354

Vested and expected to vest		958,360		$	10.59	$	4.17		7.05	$	11,510,192

During the six months ended June 30, 2011, 175,000 options vested with a weighted average exercise price of $10.15. The weighted average grant date fair value of these options was $4.81 per option. At June 30, 2011, there were 616,250 unvested options outstanding with a weighted average remaining amortization period of 2.21 years.

Compensation expense is 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 June 30, 2011 and 2010 the Company recognized compensation expense of $273,000 and $275,000, respectively, related to these options. For the six month periods ended June 30, 2011 and 2010, the Company recognized compensation expense of $562,000 and $494,000, respectively, related to these options. As of June 30, 2011, the future pre-tax expense of non-vested stock options is $2.1 million to be recognized through the second quarter of 2015.

In addition to the stock option grants discussed above, during the second quarter of 2011, the Company granted certain officers, employees and directors 157,500 restricted stock units. Each restricted stock unit represents a contingent right to receive one share of the Company’s common stock upon vesting. Compensation cost, determined by multiplying the number of restricted stock units granted by the closing market price of our stock on the grant date, is recognized over the respective vesting periods on a straight-line basis. For the three and six months ended June 30, 2011, compensation expense related to restricted stock units was $248,000, respectively. We have an assumed forfeiture rate of 1%. Future compensation costs associated with unvested restricted stock units at June 30, 2011 totaled approximately $4.3 million. The weighted average vesting period related to unvested restricted stock units at June 30, 2011 was approximately 2.8 years

A summary of the Company’s restricted stock unit activity for the six months ended June 30, 2011 is as follows:


	Shares		Fair Values (1)
Outstanding, December 31, 2010		—		—
Granted		157,500	$	28.65
Vested		—		—
Forfeited		—		—

Outstanding, June 30, 2011		157,500	$	28.65

(1)	Represents the weighted average grant date market value

The Company also had 613,336 warrants to purchase common stock outstanding at June 30, 2011. The warrants have an exercise price of $32.43 and have a remaining life of 1 year and 11 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 June 30, 2011, the Company did not have any uncertain tax positions that would require recognition. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.

The Company files a consolidated federal income tax return and various combined and separate filings in several state and local jurisdictions.

It is also the Company’s practice to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statements of Income. As of June 30, 2011, the Company did not have any accrued interest or penalties associated with any unrecognized tax liabilities. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statutes of limitations prior to June 30, 2012.

NOTE G: Derivative Financial Instruments

The Company enters into various crude oil and natural gas hedging contracts, primarily costless collars and swaps, in an effort to manage its exposure to product price volatility. Historically, prices

received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has designated its commodity derivative contracts as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.

At June 30, 2011, accumulated other comprehensive income (loss) consisted of unrecognized losses of $2.2 million, net of taxes of $1.3 million, representing the inception to date change in mark-to-market value of the effective portion of the Company’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2010, accumulated other comprehensive income (loss) consisted of unrecognized losses of $3.0 million, net of taxes of $1.8 million. For the three and six months ended June 30, 2011, the Company recognized realized cash settlement losses of $1.8 million and $2.5 million, respectively. For the three and six months ended June 30, 2010, the Company recognized net realized cash settlement gains on commodity derivatives of $1.1 million and $1.2 million, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at June 30, 2011, the Company expects to reclassify net losses of $2.4 million from accumulated other comprehensive income into earnings during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

During the first quarter of 2011 the Company entered into one additional natural gas swap contract, three crude oil collars, and two crude oil swaps. The natural gas swap has a term of January 2012 to March 2013 and with a volume amount of 75,000 MMBTUs per month. The swap has a fixed price of $4.85 per MMBTU. The first crude oil collar has a term of February 2011 through December 2011 with a volume amount of 5,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $106.08 per Bbl on this contract. The second crude oil collar has a term of January 2012 through December 2012 and provides for 10,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $110.00 per Bbl. The third crude oil collar has a term of March 2011 through December 2011 and provides for 5,000 Bbls per month. The floor price is $100.00 per Bbl and the ceiling price is $114.00 per Bbl. The first crude oil swap has a term of January 2012 through December 2012 and provides for 10,000 Bbls per month. The swap has a fixed price of $103.95 per Bbl. The second crude oil swap has a term of January 2013 through December 2013 and provides for 10,000 Bbls per month. The swap has a fixed price of $101.85 per Bbl.

During the second quarter of 2011, the Company entered into one additional crude oil swap. The crude oil swap has a term of May 2011 through December 2011 and provides for 6,250 Bbls per month. The swap has a fixed price of $110.00 per Bbl.

At June 30, 2011, 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:
2011		141,000			$	74.37
2011		42,000			$	88.45
2011		60,000			$	85.05
2011		30,000			$	85.16
2011		37,500			$	110.00
2012		120,000			$	86.85
2012		120,000			$	87.22
2012		120,000			$	103.95
2013		120,000			$	101.85

Costless collar contracts
2011		30,000	$	85.00	$	106.08
2011		30,000	$	100.00	$	114.00
2012		120,000	$	85.00	$	110.00

Natural Gas Contracts (Mmbtu)
Swap contracts
2011		420,000			$	6.450
2012		150,000			$	6.450
2012		450,000			$	6.415
2012		900,000			$	4.850
2013		225,000			$	4.850

Costless collar contracts:
2011		539,502	$	7.00	$	9.20

In 2010, the Company held two interest rate swaps, one of which is designated as a cash flow hedge, as discussed in Note D above. These swaps expired in October 2010.

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	Jun. 30, 2011		Dec. 31, 2010		Balance Sheet Location	Jun. 30, 2011			Dec. 31, 2010

Commodity contracts	Current derivative financial instruments asset	$	2,741	$	4,282	Current derivative financial instruments liability	$	(5,134	)	$	(7,433	)

Commodity contracts	Long-term derivative financial instruments asset		464		851	Long-term derivative financial instruments liability		(1,441	)		(1,650	)


		$	3,205	$	5,133		$	(6,575	)	$	(9,083	)

Commodity derivative contracts – The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the three months ended June 30, 2011 and 2010 (in thousands):


Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)				Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
Derivatives designated as ASC 815 hedges:	Jun. 30, 2011		Jun. 30, 2010			Jun. 30, 2011			Jun. 30, 2010

Commodity contracts	$	6,920	$	3,984	Oil and gas revenues	$	(1,772	)	$	1,130

Interest rate swap contract		—		72	Interest expense		—			(404	)


	$	6,920	$	4,056		$	(1,772	)	$	726


	Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
Derivatives in ASC 815 Cash Flow Hedging Relationships:		Jun. 30, 2011		Jun. 30, 2010

Commodity contracts	Hedge ineffectiveness	$	1,561	$	61


Derivatives not designated as ASC 815 hedges:	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
Derivatives not designated as ASC 815 hedges:		Jun. 30, 2011		Jun. 30, 2010

Realized cash settlements on interest rate swap	Loss on derivative contracts	$	—	$	(101	)

Unrealized gains on interest rate swap	Gain on derivative contracts		—		118


		$	—	$	17

The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the six months ended June 30, 2011 and 2010 (in thousands):


Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)					Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
Derivatives designated as ASC 815 hedges:	Jun. 30, 2011			Jun. 30, 2010			Jun. 30, 2011			Jun. 30, 2010

Commodity contracts	$	(1,288	)	$	10,452	Oil and gas revenues	$	(2,510	)	$	1,234

Interest rate swap contract		—			19	Interest expense		—			(806	)


	$	(1,288	)	$	10,471		$	(2,510	)	$	428


Derivatives in ASC 815 Cash Flow Hedging Relationships:	Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
Derivatives in ASC 815 Cash Flow Hedging Relationships:		Jun. 30, 2011			Jun. 30, 2010

Commodity contracts	Hedge ineffectiveness	$	(641	)	$	316


Derivatives not designated as ASC 815 hedges:	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
Derivatives not designated as ASC 815 hedges:		Jun. 30, 2011			Jun. 30, 2010

Realized cash settlements on interest rate swap	Loss on derivative contracts	$	—		$	(201	)

Unrealized gains on interest rate swap	Gain on derivative contracts		—			205


		$	—		$	4

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.

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 Company’s interest rate swaps are valued using the counterparty’s marked-to-market statement, which can be validated using modeling techniques that include market inputs such as publically available interest rate yield curves, and is designated as Level 2 within the valuation hierarchy.

The table below presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

Fair Value of Financial Assets and Liabilities - June 30, 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 June 30, 2011
Current portion of derivative financial instrument asset ⁽¹⁾		—	$	2,741			—	$	2,741

Long-term portion of derivative financial instrument asset ⁽¹⁾		—		464			—		464

Current portion of derivative financial instrument liability ⁽¹⁾		—		(5,134	)		—		(5,134	)

Long-term portion of derivative financial instrument liability ⁽¹⁾		—		(1,441	)		—		(1,441	)

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

Fair Value of Financial Assets and Liabilities - December 31, 2010

(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, 2010
Current portion of derivative financial instrument asset ⁽¹⁾		—	$	4,282			—	$	4,282

Long-term portion of derivative financial instrument asset ⁽¹⁾		—		851			—		851

Current portion of derivative financial instrument liability ⁽¹⁾		—		(7,433	)		—		(7,433	)

Long-term portion of derivative financial instrument liability ⁽¹⁾		—		(1,650	)		—		(1,650	)

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

At June 30, 2011, and December 31, 2010, the Company did not have any assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3. Also, there were no transfers between Level 1 and Level 2 as of June 30, 2011 and December 31, 2010.

Asset Impairments – The Company reviews proved oil and gas properties for impairment at least annually and when events and circumstances indicate a potential decline in the recoverability of the carrying value of such properties. When events and circumstances indicate a 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 on proved or unproved properties during the three and six month periods ended June 30, 2011. During the three and six month periods ended June 30, 2010, the Company recorded asset impairments of $2.7 million on proved properties. Impairments were included in impairment expense. The significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis are 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.

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 plugging costs and reserve lives. 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 deducting the underwriters’ discount and other offering expenses.

NOTE J: Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. The Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the six months ended June 30, 2011, are as follows (in thousands):


Asset retirement obligation, January 1, 2011	$	7,052

Accretion expense		224
Additional liabilities incurred		158
Obligations on sold properties		(464	)

Asset retirement obligation, June 30, 2011	$	6,970

NOTE K: Related Party Transactions

Accounts receivable at June 30, 2011, and December 31, 2010, includes $658,000 and $753,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at June 30, 2011, and December 31, 2010, also includes $136,000 and $219,000, respectively, due from OKLA Energy Partners LP (“OKLA Energy”). Both of these partnerships are oil and gas limited partnerships for which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued management fees. Accounts payable at June 30, 2011, and December 31, 2010, includes $2.2 million and $2.3 million, respectively, due to SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at June 30, 2011, and December 31, 2010, also includes $870,000 and $654,000, 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 June 30, 2011 and 2010 of $131,000, and $140,000 respectively. The Company earned partnership management fees during the six months ended June 30, 2011 and 2010, of $242,000 and $299,000, 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 partnership income of $10,000 and $9,000, respectively, for the three and six months ended June 30, 2011. The Company recorded losses in partnership income of $8,000 and $10,000, respectively, related to this investment for the three and six months ended June 30, 2010.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings field in Texas. Previously, GeoResources held a 2% general partner interest which increased after reaching a cumulative payout. As result of the sale of certain properties and subsequent distribution of proceeds by the partnership, cumulative payout was achieved and the Company’s general partner interest increased to 30%. The Company recorded partnership income related to this investment for each of the three month periods ended June 30, 2011 and 2010 of $495,000 and $496,000, respectively. The Company recorded partnership income related to this investment for the six month periods ended June 30, 2011 and 2010 of $906,000 and $1.4 million, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at June 30, 2011 and December 31, 2010, was $703,000 and $709,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at June 30, 2011 and December 31, 2010 was $2.0 million and $1.6 million, respectively.

The following is a summary of selected financial information of SBE Partners, LP for the six months ended June 30, 2011 and 2010 (in thousands):


	Six Months Ended June 30,
	2011		2010

Summary of Partnership Operations:
Revenues	$	8,040	$	10,796
Income from continuing operations	$	2,933	$	3,656
Net income	$	2,933	$	3,656

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, 2010.

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 reform, and changes in state, federal and foreign income taxes;

•

the effect of oil and natural gas derivatives activities;

•

conditions in the capital markets; and

•

other risks, described in Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2010, as may be supplemented and updated from time to time in our other SEC filings.

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

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 and exploration activities. Historically, we have shifted 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 trend of North Dakota and Montana and the Eagle Ford 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:

•

Accelerate the development of our acreage positions in the Bakken and Eagle Ford trends;

•

Expand our acreage positions and drilling inventory in our focus areas;

•

Solicit industry partners, on a promoted basis, where we can retain operations and control large acreage positions in order to diversify, enhance economics and generate operating fees;

•

Generate additional exploration and development projects;

•

Acquire oil and gas properties with producing reserves and development and exploration potential, within our focus areas;

•

Selectively divest assets to high-grade our producing property portfolio and to lower corporate wide “per-unit” operating and administrative costs, and focus attention on existing fields and new projects with greater development and exploitation potential; and

•

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

While the impact and success of our plans cannot be predicted with accuracy, management’s goal is to increase shareholder value by sourcing and investing in exploration and development projects with attractive full-cycle risk-adjusted economics.

In addition to our fundamental business strategy, we intend to pursue corporate acquisitions and mergers. We believe that a corporate acquisition or merger could potentially accelerate growth, increase market visibility and 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 asset coverage in our core focus areas, (2) the opportunity to increase our earnings and cash flow on a per share basis, (3) development and exploration potential, and (4) realization of 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 at lower costs.

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

In September 2010, we entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford shale trend of Texas. As part of this agreement, we sold a 50% working interest in approximately 20,000 acres for $20 million. The purchaser also agreed to pay 100% of the drilling costs for the first six wells to be drilled in a contractually specified area of mutual interest (“AMI”). The agreement also provides for an additional $20 million for additional joint leasing within the AMI ($10 million net to each entity). Subsequent to the initial closing, the Company and the joint owners have continued to acquire leases within the AMI pursuant to the terms of the agreement.

In July 2010, we closed an acquisition of producing oil and gas properties located in the Giddings field of central Texas. The purchase price was $16.6 million plus closing adjustments for normal operations activity. The acquisition included approximately 9,700 net acres and was funded through borrowings under our credit facility.

Results of Operations

Three months ended June 30, 2011, compared to three months ended June 30, 2010

The Company recorded net income of $8.8 million for the three months ended June 30, 2011 compared to net income of $4.4 million for the same period in 2010. The increase resulted primarily from the following factors:


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

Oil and gas sales	$	4,949
Lease operating expenses		(554	)
Production taxes		(358	)
Exploration expense		15
Re-engineering and workovers		(454	)
General and administrative expenses (“G&A”)		(923	)
Depletion, depreciation and amortization expense (“DD&A”)		(386	)
Impairment expense		2,743
Interest Expense		833
Hedge ineffectiveness		1,500
Gain (loss) on derivative contracts		(17	)
Gain (loss) on sale of property		1
Other income - net		(476	)

Income before income taxes		6,873
Provision for income taxes		(2,537	)

Increase in net income	$	4,336

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $4.9 million, or 20%. Increased commodity prices accounted for an increase of $5.7 million and decreased production volumes accounted for a decrease in revenues of $742,000. As previously reported, in 2010 we suspended drilling of natural gas wells in the Austin Chalk Trend (Giddings field) due to low natural gas prices. Oil production from many of our new wells drilled in the first half of 2011 was delayed due to adverse weather conditions in North Dakota and Montana, as well as significant delays in obtaining services and equipment. Price and production comparisons are set forth in the following table.


	Percent increase (decrease)			Three Months Ended June 30,
	Percent increase (decrease)			2011		2010

Gas Production (MMcf)		-23	%		1,004		1,300
Oil Production (Mbbls)		4	%		265		255
Barrel of Oil Equivalent (MBOE)		-8	%		432		472
Average Price Gas Before Hedge Settlements (per Mcf)		9	%	$	4.08	$	3.76
Average Price Oil Before Hedge Settlements (per Bbl)		42	%	$	101.78	$	71.83
Average Realized Price Gas (per Mcf)		7	%	$	5.24	$	4.90
Average Realized Price Oil (per Bbl)		29	%	$	90.71	$	70.48

Lease Operating Expenses. Lease operating expenses (“LOE”) increased from $5.2 million in the second quarter of 2010 to $5.8 million for the same period in 2011, an increase of $554,000, or 11%, primarily as a result of price increases for well service costs caused by high demand. Also, LOE has increased as a result of additional wells added during the last 12 months.

Production Taxes. Production taxes increased by $358,000 or 23%, as a result of increased revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the quarters ended June 30, 2011 and 2010 were 6.11% and 6.63%, respectively, of oil and gas sales before the effects of hedging. The 2011 rate decreased from 2010 due to the approval of severance tax exemptions on wells in several of our key fields as well as to a change in our portfolio of producing properties.

Exploration and Impairment Costs. Our exploration costs were $124,000 for the second quarter of 2011 and $139,000 for the second quarter of 2010. The costs during 2010 were primarily residual costs associated with an exploratory well deemed to be a dry hole prior to December 31, 2009. The costs incurred during 2011 were primarily geological and geophysical costs. We recorded non-cash impairment charges of $2.7 million in 2010, due to the write-down of proved properties, and none in 2011. The book value of these properties, at the time of measurement, exceeded our estimate of future undiscounted cash flows which was a direct result of the decline in our estimate of future natural gas prices.

General and Administrative Expenses. G&A increased by $923,000 or 45%, due primarily to increases in personnel costs. As our business has expanded, we have also expanded our staff. The total non-cash charges related to stock-based compensation included in G&A expense for the three month periods ended June 30, 2011 and 2010 were $522,000 and $275,000, respectively. The increase in share-based compensation was due to the issuance of restricted stock units to management and key employees during the second quarter of 2011.

Depreciation, Depletion and Amortization. DD&A expense increased by $386,000 or 6%, due to higher capitalized costs. DD&A on oil and gas properties is computed on the units-of-production method, with production volumes as the numerator and estimated proved reserve volumes as the denominator. On a unit of production basis, DD&A per BOE increased from $12.64 in 2010 to $14.69 in 2011.

Interest Expense. Interest expense decreased by $833,000 or 65%, due to lower average debt levels in the second quarter of 2011 compared to the same period in 2010. Our debt was fully extinguished in January 2011. For the three months ended June 30, 2010, average outstanding debt was $69 million. Interest expense for the three months ended June 30, 2011, was comprised primarily of fees associated with our bank credit agreement.

Hedge Ineffectiveness. In the second quarter of 2011 the gain from hedge ineffectiveness was $1.6 million compared to a gain of $61,000 for the same period in 2010. During the second quarter of 2011, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a gain.

Other Income. Other income decreased by $476,000 in the second quarter of 2011 compared to the same period in 2010 primarily as a result of a decrease in severance tax refunds offset by an increase in property operating income. During the second quarter of 2010, we recorded severance tax refunds of $984,000 versus $208,000 in the second quarter of 2011. This decrease was offset by an increase in property operating income of $239,000 as a result of operating properties in the Bakken area in the second quarter of 2011.

Income Tax Expense. Income tax expense for the second quarter of 2011 was $5.4 million compared to $2.9 million for the same period in 2010, or a 88% increase. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the second quarter of 2011 and 2010 was approximately 38% and 39%, respectively.

Six months ended June 30, 2011, compared to six months ended June 30, 2010

The Company recorded net income of $15.1 million for the six months ended June 30, 2011 compared to net income of $10.5 million for the same period in 2010. This $4.6 million increase resulted primarily from the following factors:


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

Oil and gas sales	$	6,834
Lease operating expenses		(549	)
Production taxes		(196	)
Exploration expense		247
Re-engineering and workovers		(595	)
General and administrative expenses (“G&A”)		(1,704	)
Depletion, depreciation and amortization expense (“DD&A”)		385
Impairment expense		2,743
Interest expense		1,520
Hedge ineffectiveness		(957	)
Gain (loss) on derivative contracts		(4	)
Gain (loss) on sale of property		592
Other income - net		(889	)

Income before income taxes		7,427
Provision for income taxes		(2,852	)

Increase in net income	$	4,575

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $6.8 million, or 14%. Commodity prices accounted for $9.0 million in increased revenue and decreased production volumes accounted for a $2.2 million decrease in oil and gas revenues. As previously reported, in 2010 we temporarily suspended drilling of natural gas wells in the Austin Chalk (Giddings field) due to low natural gas prices. Oil production from many of our new wells drilled in the first half of 2011 was delayed due to adverse weather conditions in North Dakota and Montana, as well as significant delays in obtaining services and equipment. Price and production comparisons are set forth in the following table.


	Percent increase (decrease)			Six Months Ended June 30,
	Percent increase (decrease)			2011		2010

Gas Production (MMcf)		-22	%		2,015		2,580
Oil Production (MBbls)		2	%		515		504
Barrel of Oil Equivalent (MBOE)		-9	%		851		934
Average Price Gas Before Hedge Settlements (per Mcf)		-5	%	$	4.06	$	4.29
Average Price Oil Before Hedge Settlements (per Bbl)		34	%	$	97.53	$	73.01
Average Realized Price Gas (per Mcf)		-1	%	$	5.22	$	5.25
Average Realized Price Oil (per Bbl)		25	%	$	88.12	$	70.55

Lease Operating Expenses. Lease operating expenses (“LOE”) increased from $10.2 million for the six months ended June 30, 2010 to $10.8 million for the same period in 2011, an increase of $549,000, or 5.4%, primarily as a result of price increases for well service costs caused by high demand. Also, LOE has increased as a result of additional wells added during the last 12 months.

Production Taxes. Production taxes increased by $196,000 or 6%, due to increased production revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the first six months of 2011 and 2010 were 6.02% and 6.95%, respectively, of oil and gas sales before the effects of hedging. The 2011 rate decrease from 2010 was due to the approval of severance tax exemptions on wells in several of our key fields as well as a change in our portfolio of producing properties.

Exploration and Impairment Costs. Our exploration costs were $356,000 for the six months ended June 30, 2011 and $603,000 for the same period during 2010, a decrease of 41%. These costs are primarily geological and geophysical costs. We recorded non-cash impairment charges of $2.7 million in 2010, due to the write-down of proved properties and none in 2011. The book value of these properties, at the time of measurement, exceeded our estimate of future undiscounted cash flows which was a direct result of the decline in our estimate of future natural gas prices.

General and Administrative Expenses. G&A increased $1.7 million in the first six months of 2011, or 44%, compared to the same period in 2010 due primarily to increases in personnel costs. As our business has expanded, we have also expanded our staff. The total non-cash charges related to stock-based compensation included in G&A expense for the six months ended June 30, 2011 and 2010 was $810,000 and $494,000, respectively. The increase in share-based compensation was due to the issuance of restricted stock units to management and key employees during the second quarter of 2011.

Depreciation, Depletion and Amortization. DD&A expense decreased by $385,000 or 3%, due to higher estimated reserves at June 30, 2011 and lower production as compared to the prior year. On a units of production basis, DD&A per BOE increased from $13.19 in 2010 to $14.02 in 2011.

Interest Expense. Interest expense decreased by $1.5 million due to lower average debt levels in the first half of 2011 compared to the same period in 2010. Our debt was fully extinguished in January 2011. For the six months ended June 30, 2010, average outstanding debt was $69 million. Interest expense for the six months ended June 30, 2011, was comprised primarily of fees associated with our bank credit agreement.

Hedge Ineffectiveness. For the first six months of 2011 the loss from hedge ineffectiveness was $641,000, compared to a gain of $316,000 for the same period in 2010. During the six months ended June 30, 2011, our natural gas derivatives, accounted for as cash flow hedges, decreased in value; therefore, the change in the ineffective portion of these derivatives was a loss. During the six months ended June 30, 2010, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a gain.

Other Income. Other income decreased by $889,000 in the first six months of 2011 compared to the same period in 2010, or 24%, due primarily to a decrease in severance tax refunds. During the first six months of 2011 we recorded severance tax refunds of $266,000 related to high cost gas wells in Texas. During the first six months of 2010 we recorded severance tax refunds of $1.2 million related to both high cost gas wells in Texas and certain qualifying oil wells in Louisiana.

Income Tax Expense. Income tax expense for the first half of 2011 was $9.5 million compared to $6.7 million for the same period in 2010, an increase of 43%. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the first six months of 2011 and 2010 was approximately 39%.

Impact of Changing Prices and Costs

Our revenues and the carrying value of our oil and gas properties are subject to significant change due to changes in oil and gas prices. The oil and gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices. Material changes in prices also impact the current revenue stream, estimates of future reserves, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Oil prices decreased appreciably during the last half of 2008 and into 2009 but recovered during the last half of 2009 through the second quarter of 2011. Our average realized oil price of $88.12 per Bbl, net of hedges, for the six months ended June 30, 2011, was 25% higher than for the comparable period in 2010. Our average realized natural gas price of $5.22 per Mcf, net of hedges, for the six months ended June 30, 2011, was 1% lower than for the comparable period in 2010. The average realized prices for the six months ended June 30, 2011, included the effects of our hedges. 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.

Low natural gas prices in 2009 caused us to suspend our drilling activities directed in the Giddings field and then restart them resulting in a decline of 15% in our gas production from the fourth quarter 2009 to the first quarter 2010. In the second quarter of 2010 we announced our suspension of those activities again in the current low gas price environment, which resulted in declines in our natural gas production of 23% for the quarter ended June 30, 2011 as compared to the same period in 2010 and a 22% production decline for the six months ended June 30, 2011 compared to the same period in 2010. We plan to restart drilling activity when natural gas prices recover. We expect a similar level of decline in our natural gas production in the second half of 2011 as we experienced in the first half of 2011.

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 sufficient cash flow to fund capital development projects and additional acquisitions;

(3)

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

(4)

Allow certain anticipated production volumes to float, particularly in months with high price potential.

We believe that commodity speculation and trading activities are inappropriate for us, but we do believe appropriate management of future realized prices through cash flow hedging is an integral part of managing our business strategy.

Administrative and Operating Costs

We continue to focus on cost-containment efforts regarding lower per-unit administrative and operating costs. However, we must continue to attract and retain competent management, technical and administrative personnel in pursuing our business strategy and fulfilling our contractual obligations. In seeking to grow our business, we have expanded our staff. As a result our general and administrative expenses increased significantly in 2011 to date as compared to 2010.

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 June 30, 2011, our borrowing base under our credit facility with Wells Fargo Bank was $145 million and we did not have any outstanding indebtedness. The borrowing base is subject to redetermination on May 1 and November 1 of each year. On May 4, 2011, all members of our bank group reaffirmed our borrowing base at $145 million. We have no outstanding debt under the credit facility as of August 7, 2011.

Cash Flows from Operating Activities

For the six months ended June 30, 2011, our net cash provided by operating activities was $38.3 million, versus $31.8 million in the same period in 2010. We believe that we have sufficient liquidity and capital resources to execute our business plans over the next twelve months and for the foreseeable future. We expect to fund our planned capital program through our existing credit facility, working capital and projected cash flows.

Cash Flows from Investing Activities

Cash used for oil and gas capital expenditures for the six months ended June 30, 2011 and 2010, was $42.4 million and $29.1 million, respectively. In addition, cash generated from the sale of oil and gas properties for the six months ended June 30, 2011 and 2010 was $345,000 and $425,000, respectively. Capital expenditures for the first six months of 2011 were financed with working capital. We expect to spend approximately $245 million in additional capital expenditures during the remainder of 2011 and 2012.

Capital Budget

As summarized below, we estimate our capital budget for 2011 will total $114.0 million. Through June 30, 2011 we had expended approximately $42 million of the budget. While the table includes the bulk of our currently identified drilling for 2011, we are constantly working on developing and acquiring new opportunities. 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 experienced increases in drilling and development costs and continue to expand our portfolio of drilling and development projects and therefore we expect to revise our capital budget for 2011 and 2012 during the third quarter 2011.

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. These projects represent the bulk of our planned capital expenditures for 2011, as set forth in the table below. However, we continue evaluating whether to shift our expenditures between geographic areas and projects in an attempt to maximize cash flow and take advantage of regional differences in net commodity prices and service costs or other matters we deem important.

While industry circumstances may require us to make capital expenditure adjustments, our capital budget reflects our current intent to accelerate our Bakken and Eagle Ford drilling 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 the Gulf Coast, 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 are subject to significant change as we continue to technically and economically evaluate existing and alternative projects, as we further expand our portfolio, and as industry conditions dictate. Estimated expenditures are also subject to significant change. There can be no assurance that all of the projects identified and summarized in the table below will remain competitive or viable and therefore certain projects may be sold or abandoned 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 material mineral leases. Our current estimate of our capital expenditures for 2011 is as follows:


	($ in Millions)		Percent of Capital Budget

Bakken - operated ⁽¹⁾	$	29.5		26	%
Bakken - non-operated ⁽²⁾		21.0		18	%
Eagle Ford ⁽³⁾		15.8		14	%
Giddings Field ⁽⁴⁾		8.3		7	%
Louisiana ⁽⁵⁾		7.8		7	%
Acreage and seismic ⁽⁶⁾		25.0		22	%
Other drilling operations		6.6		6	%

Total	$	114.0		100	%

Notes:

(1)

Includes approximately $26.0 million allocated to our operated Bakken drilling project in Williams County, North Dakota. The remaining $3.5 million represents planned drilling on Bakken spacing units we control in eastern Montana. In Williams County, North Dakota, we completed drilling and completion of our initial four wells in the first half of 2011. We recently contracted a second drilling rig which is currently drilling in Williams County.

(2)	Represents continuation of our non-operated program in the Bakken. Approximately $17.5 million represents activities in Mountrail County, North Dakota and $3.5 million represents planned drilling in eastern Montana.

(3)

Represents our net estimated cost of drilling 13 planned wells with an industry partner where we have a 50% carried interest in six wells at no cost to us. We completed drilling our first three Eagle Ford wells in the second quarter of 2011. We plan to contract a second rig to drill in our Eagle Ford area in the fourth quarter of 2011.

(4)	Represents our net estimated cost of drilling three wells in the Giddings Field, Texas.

(5)	Represents our net estimated cost of drilling seven wells in the St. Martinville Field and one well at Quarantine Bay, Louisiana.

(6)	Includes approximately $22.0 million allocated to additional acreage and $3.0 million allocated to seismic activities. We intend to continue expanding our acreage positions in our focus areas and therefore, with success, our capital spending could exceed the amounts shown above.

Pending success, continuing favorable industry and economic conditions and availability of equipment and services among other factors, our current estimate of capital expenditures for 2012 is approximately $173.0 million, largely directed toward continued Bakken and expanded Eagle Ford drilling and incremental acreage acquisitions.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The following is a list of contracts outstanding at June 30, 2011:

Transaction Date

Transaction
Type

Beginning

Ending

Price Per
Unit

Remaining
Annual Volumes

Fair Value
Outstanding
as of
June 30, 2011

(in thousands)

Natural Gas

October-07

Collar

01/01/11

12/31/11

$7.00 - $9.20

539,502 Mmbtu

1,374

December-09

Swap

04/01/11

03/31/12

$6.450

570,000 Mmbtu

1,105

December-09

Swap

04/01/12

12/31/12

$6.415

450,000 Mmbtu

726

January-11

Swap

01/01/12

03/31/13

$4.850

1,125,000 Mmbtu

)

3,203

Crude Oil

October-07

Swap

01/01/11

12/31/11

$74.37

141,000 Bbls

(3,174

)

January-10

Swap

01/01/11

12/31/11

$88.45

42,000 Bbls

(358

)

August-10

Swap

09/01/10

12/31/11

$85.05

60,000 Bbls

(707

)

August-10

Swap

01/01/12

12/31/12

$86.85

120,000 Bbls

(1,570

)

October-10

Swap

01/01/11

12/31/11

$85.16

30,000 Bbls

(349

)

October-10

Swap

01/01/12

12/31/12

$87.22

120,000 Bbls

(1,524

)

January-11

Collar

02/01/11

12/31/11

$85.00 - $106.08

30,000 Bbls

(34

)

January-11

Collar

01/01/12

12/31/12

$85.00 - $110.00

120,000 Bbls

(122

)

March-11

Collar

03/01/11

12/31/11

$100.00 - $114.00

30,000 Bbls

114

March-11

Swap

01/01/12

12/31/12

$103.95

120,000 Bbls

524

March-11

Swap

01/01/13

12/31/13

$101.85

120,000 Bbls

137

April-11

Swap

05/01/11

12/31/11

$110.00

37,500 Bbls

490

(6,573

)

(3,370

)

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our Chief Executive Officer, Chief Financial Officer and other members of management evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of June 30, 2011. Based upon their evaluation of these disclosure controls and procedures, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of June 30, 2011, in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive and principal financial officers to allow timely discussion regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2011, 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

We are not a party to, nor are any of our properties subject to, any material pending legal proceedings. We know of no material legal proceedings contemplated or threatened against the Company.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A- Risk Factors” in our Annual Report for the year ended December 31, 2010 on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2010 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. *Reserved*

Item 5. *Other Information*		None

Item 6. Exhibits

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended June 30, 2011.


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

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

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

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

101.INS		XBRL Instance Document. (1)

101.SCH		XBRL Schema Document. (1)

101.CAL		XBRL Calculation Linkbase Document. (1)

101.DEF		XBRL Definition Linkbase Document. (1)

101.LAB		XBRL Label Linkbase Document. (1)

101.PRE		XBRL Presentation Linkbase Document. (1)

(1)	Filed herewith

SIGNATURES

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


		GEORESOURCES, INC.
August 8, 2011

		/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)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company