- Quarterly Report (10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period ended June 30, 2009

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

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 ¨ No x

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):


Larger accelerated filer ¨	Accelerated filer x	Non-accelerated filer ¨	Smaller reporting company ¨
		(Do not check if a smaller reporting company)

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, 2009
Common stock, par value $.01 per share		16,241,717 shares

TABLE OF CONTENTS


PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	3

	Consolidated Statements of Income for Three Months and Six Months ended June 30, 2009 and 2008	5

	Consolidated Statement of Stockholders’ Equity and Comprehensive Income (Loss) for the Six Months ended June 30, 2009	6

	Consolidated Statements of Cash Flows for the Six Months ended June 30, 2009 and 2008	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	37

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

Item 3.	Defaults Upon Senior Securities	38

Item 4.	Submission of Matters to a Vote of Security Holders	38

Item 5.	Other Information	38

Item 6.	Exhibits	39

	Signatures	41

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	June 30, 2009			December 31, 2008
	(unaudited)
ASSETS
Current assets:
Cash	$	7,670		$	13,967
Accounts receivable
Oil and gas revenues		11,038			11,439
Joint interest billings and other		14,200			7,172
Affiliated partnerships		2,374			2,905
Notes receivable		120			120
Derivative financial instruments		2,385			8,200
Income taxes receivable		3,139			2,165
Prepaid expenses and other		3,722			3,923

Total current assets		44,648			49,891

Oil and gas properties, successful efforts method:
Proved properties		268,686			204,536
Unproved properties		7,310			2,409
Office and other equipment		763			1,025
Land		96			96

		276,855			208,066
Less accumulated depreciation, depletion and amortization		(34,946	)		(26,486	)

Net property and equipment		241,909			181,580

Equity in oil and gas limited partnerships		3,442			3,266
Derivative financial instruments		346			6,409
Deferred financing costs and other		1,606			2,388

	$	291,951		$	243,534

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, 2009			December 31, 2008
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	6,314		$	10,750
Accounts payable to affiliated partnerships		8,333			10,310
Revenue and royalties payable		14,189			11,701
Drilling advances		239			2,169
Accrued expenses		1,506			1,506
Derivative financial instruments		3,483			1,572

Total current liabilities		34,064			38,008

Long-term debt		98,000			40,000
Deferred income taxes		16,078			17,868
Asset retirement obligations		5,624			5,418
Derivative financial instruments		502			1,245
Stockholders’ equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 16,241,717		162			162
Additional paid-in capital		113,184			112,523
Accumulated other comprehensive (loss) income		(666	)		7,283
Retained earnings		25,003			21,027

Total stockholders’ equity		137,683			140,995

	$	291,951		$	243,534

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,
	2009		2008			2009			2008
Revenue:
Oil and gas revenues	$	16,829	$	25,118		$	29,129		$	47,581
Partnership management fees		398		522			696			834
Property operating income		456		357			914			671
Gain on sale of property and equipment		89		1,551			1,488			1,961
Partnership income		1,455		429			1,460			655
Interest and other		35		228			140			450

Total revenue		19,262		28,205			33,827			52,152
Expenses:
Lease operating expense		4,417		5,789			8,807			11,580
Severance taxes		568		2,428			1,362			4,317
Re-engineering and workovers		315		984			1,296			1,682
Exploration expense		288		502			368			502
Impairment of oil and gas properties		128		—			128			—
General and administrative expense		1,930		1,861			4,025			3,645
Depreciation, depletion and amortization		4,725		3,573			9,193			7,450
Hedge ineffectiveness		26		(582	)		75			937
Loss on derivative contracts		6		—			58			—
Interest		1,144		1,314			1,963			2,883

Total expense		13,547		15,869			27,275			32,996
Income before income taxes		5,715		12,336			6,552			19,156
Income tax expense (benefit):
Current		202		1,330			(532	)		2,759
Deferred		2,014		3,216			3,108			4,383

		2,216		4,546			2,576			7,142

Net income	$	3,499	$	7,790		$	3,976		$	12,014

Net income per share (basic)	$	0.22	$	0.51		$	0.24		$	0.80

Net income per share (diluted)	$	0.22	$	0.50		$	0.24		$	0.79

Weighted average shares outstanding:
Basic		16,241,717		15,214,494			16,241,717			14,958,939

Diluted		16,241,717		15,504,668			16,241,717			15,145,777

The accompanying notes are an integral part of these statements

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY and COMPREHENSIVE INCOME (LOSS)

Six Months Ended June 30, 2009

(In thousands except share data)

(unaudited)


				Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total
	Common Stock
	Shares	Par Value
Balance, December 31, 2008	16,241,717	$	162	$	112,523	$	21,027	$	7,283		$	140,995
Comprehensive income (loss):
Net income							3,976					3,976
Change in fair market value of hedged positions, net of taxes of $3,175									(5,152	)		(5,152	)
Net realized hedging gains charged to income, net of taxes of $1,724									(2,797	)		(2,797	)

Total comprehensive income (loss)												(3,973	)

Equity based compensation expense					661							661

Balance, June 30, 2009	16,241,717	$	162	$	113,184	$	25,003	$	(666	)	$	137,683

The accompanying notes are an integral part of this statement.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands, except share and per share amounts)

(unaudited)


	Six Months Ended June 30,
	2009			2008
Cash flows from operating activities:
Net income	$	3,976		$	12,014
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		9,193			7,450
Unproved property impairments		—			483
Proved property impairments		128			—
Gain on sale of property and equipment		(1,488	)		(1,961	)
Accretion of asset retirement obligations		177			216
Unrealized gain on derivative contracts		(119	)		—
Amortization of loss on canceled hedge contract		243			—
Hedge ineffectiveness loss		75			937
Partnership income		(1,460	)		(655	)
Partnership distributions		1,284			194
Deferred income taxes		3,108			4,383
Non-cash compensation		661			298
Changes in assets and liabilities:
Increase in accounts receivable		(7,070	)		(13,534	)
Decrease in notes receivable		215			480
Decrease (increase) in prepaid expense and other		862			(623	)
Increase (decrease) in accounts payable and accrued expense		(5,855	)		17,006

Net cash provided by operating activities		3,930			26,688
Cash flows from investing activities:
Proceeds from sale of property and equipment		1,991			20,432
Additions to property and equipment		(70,218	)		(33,311	)
Investment in oil and gas limited partnership		—			(978	)

Net cash used in investing activities		(68,227	)		(13,857	)
Cash flows from financing activities:
Issuance of common stock		—			32,317
Issuance of long-term debt		58,000			—
Reduction of long-term debt		—			(46,000	)

Net cash provided by (used in) financing activities		58,000			(13,683	)

Net decrease in cash and cash equivalents		(6,297	)		(852	)

Cash and cash equivalents at beginning of period		13,967			24,430

Cash and cash equivalents at end of period	$	7,670		$	23,578

Supplementary information:
Interest paid	$	1,650		$	2,831
Income taxes paid	$	478		$	4,210

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE A: Organization and Basis of Presentation

Description of Operations

GeoResources, Inc. (“GeoResources” or the “Company”) operates a single business segment engaged in the acquisition, development and production of, and exploration for, crude oil, natural gas and related products primarily in Texas, Louisiana, Oklahoma, North Dakota, Montana and Colorado.

Consolidated Financial Statements

The unaudited consolidated financial statements include the accounts of GeoResources and its subsidiaries, all of which are wholly owned. 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’ 2008 Annual Report on Form 10-K/A includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there has been no material changes to the information disclosed in the notes to the consolidated financial statements included in GeoResources’ 2008 Annual Report on Form 10-K/A. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Earnings Per Share

Basic net income per common share is calculated by dividing net income by the weighted average number of common shares outstanding during each period. Diluted net income per common share is calculated by dividing net income by the weighted average number of common shares outstanding and other dilutive securities. The only securities considered potentially dilutive are the Company’s stock options. During the three and six month periods ended June 30, 2009, there were not any potentially dilutive securities because the average price of the Company’s common stock was less than the exercise price and associated tax benefits of the options outstanding.

NOTE B: Acquisitions and Dispositions

Bakken Acquisition

In May 2009, the Company closed an acquisition, through an existing joint venture partner, of producing wells and acreage in the Bakken Shale trend of the Williston Basin. The Company acquired a 15% interest in approximately 60,000 net acres, and also acquired 15% of varying working interests in 59 producing and productive wells. The Company’s net acquisition cost was approximately $10.4 million, subject to closing adjustments for normal operations activity and other customary purchase price adjustments. The Company funded the acquisition with borrowings from its senior secured revolving credit facility.

Giddings Field Acquisition

On May 29, 2009, effective May 1, 2009, the Company, though its subsidiary, Catena Oil and Gas LLC (“Catena”), entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with an affiliated limited partnership, SBE Partners LP (the “Seller”) for the acquisition (the “Acquisition”) of certain oil and gas producing properties in Giddings Field, Grimes and Montgomery Counties, Texas (the “Interests”). Under the Purchase Agreement, the Interests were purchased for a net cash purchase price of $48.4 million,

subject to adjustments at closing for normal operations activity and other customary purchase price adjustments (the “Purchase Price”). The Acquisition increased the Company’s partnership sharing ratio from 2% to 30% in the Seller. Catena is the general partner of the Seller. The Acquisition increased the Company’s direct working interests in the Interests from a range of 6.5% to 7.8% to a range of 34% to 37%. The Company funded the Purchase Price with borrowings from its senior secured revolving credit facility. The Purchase Agreement contains representations and warranties, covenants, and indemnifications that are customary for oil and gas producing property acquisitions.

The amount of revenue and net income from the Acquisition included in the Company’s consolidated income statement for the six months ended June 30, 2009 was $1,153,000 and $314,000, respectively.

The following summary presents unaudited pro forma information for the six month periods ended June 30, 2009 and 2008, as if the Acquisition had been consummated at January 1, 2008 (in thousands except share and per share amounts):


	June 30,
	2009		2008
Total revenue	$	38,628	$	68,627
Income before taxes		9,514		32,238
Net income		5,809		20,321
Net income per share:
Basic	$	0.36	$	1.36
Diluted	$	0.36	$	1.34
Weighted average shares:
Basic		16,241,717		14,958,939
Diluted		16,241,717		15,145,777

Other Acquisitions and Sales

In January 2009, the Company sold a producing property located in Louisiana to an unaffiliated party for $1.6 million. The Company recognized a gain of $1.3 million in conjunction with this sale.

NOTE C: Recently Issued Accounting Pronouncements

On December 31, 2008, the SEC published the revised rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in existing oil and gas rules to make them consistent with the petroleum resources management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used in determining reserves. To determine reserves, companies must use a 12-month average price. The Company is required to comply with the amended disclosure requirement for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on its disclosures, operating results, financial position and cash flows.

In December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS 141R”). SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements, the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance

for recognizing and measuring goodwill acquired in business combinations and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company adopted SFAS 141R effective January 1, 2009, and has applied its provisions prospectively to the acquisitions completed during the first six months of 2009.

In April 2009, the FASB issued Staff Position 141R-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP FAS 141R-1”). FSP FAS 141R-1 amends SFAS 141R and addresses application issues regarding the accounting and disclosure provisions for contingencies. The FSP replaces the guidance in SFAS 141R on the initial recognition and measurement of assets and liabilities arising from contingencies acquired or assumed in a business combination with guidance similar to that in FASB Statement 141, before the 2007 revision. The FSP also amends Statement 141R’s subsequent guidance for contingent assets and liabilities recognized at the acquisition date and amends the disclosure requirements for contingencies. The FSP is effective for business combinations with an acquisition date that is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company adopted FSP FAS 141R-1 effective January 1, 2009, and has applied its provisions to the acquisitions completed during the first six months of 2009.

In April 2009, the FASB issued Staff Position 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”), to provide additional guidance on estimating fair value when the volume and level of activity for an asset or liability have significantly decreased. The FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. The FSP emphasizes that, regardless of whether the volume or level of activity for an asset or liability have decreased significantly and regardless of which valuation technique was used, the objective of fair value measurement under FASB Statement 157, Fair Value Measurements , remains the same; that is to estimate the price that would be received to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date under current market conditions. The FSP also requires expanded disclosures. Also in April 2009, the FASB issued FSP No. 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1”), increases the frequency of fair disclosures. FSP FAS 157-4 and FSP FAS 107-1 are effective for interim and annual periods ending after June 15, 2009 and must be applied prospectively. The Company adopted FSP FAS 157-4 and FSP FAS 107-1 effective June 30, 2009. The adoption of FSP FAS 157-4 and FSP FAS 107-1 did not have a material effect the Company’s valuation of its financial assets and liabilities and the related disclosures.

In May 2009, the Financial Accounting Standards Board issued Statement 165, Subsequent Events , to incorporate the accounting and disclosure requirements for subsequent events into U.S. generally accepted accounting principles. Statement 165 introduces new terminology, defines a date through which management must evaluate subsequent events, and lists the circumstances under which an entity must recognize and disclose events or transactions occurring after the balance sheet date. The Company adopted Statement 165 as of June 30, 2009, which was the required effective date.

In June 2009, the Financial Accounting Standards Board issued FASB Statement 167, Amendments to FASB Interpretation No. 46(R) , to improve how enterprises account for and disclose their involvement with variable interest entities (VIE’s), which are special purpose entities, and other entities whose equity at risk is insufficient or lack certain characteristics. Among other things, Statement 167 changes how an entity determines whether it is the primary beneficiary of a variable interest entity (VIE) and whether that VIE should be consolidated. The new Statement requires an entity to provide significantly more disclosures about its involvement with VIEs. As a result, the Company must comprehensively review its involvement with VIEs and potential VIEs, including entities previously considered to be qualifying special purpose entities, to determine the effect on the Company’s consolidated financial statements and related disclosures. Statement 167 is effective as of the beginning of a reporting entity’s first annual reporting period that begins after November 15, 2009, and for interim periods within the first annual reporting period. Earlier application is not permitted. The Company is in the process of evaluating the impact Statement 167 will have on its consolidated financial statements and related disclosures.

In June 2009, the FASB issued SFAS No. 168, The “FASB Accounting Standards Codification” and Hierarchy of Generally Accepted Accounting Principles (“SFAS 168”). This standard replaces SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles , and establishes only two levels of GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (the “Codification”) was not intended to change or alter existing GAAP, and it therefore will not have any impact on the Company’s consolidated financial statements other than to modify certain existing disclosures. The Codification will become the source of authoritative, nongovernmental GAAP, except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfather, non-SEC accounting literature not included in the Codification will become non-authoritative. SFAS 168 is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. The Company will begin to use new guidelines and numbering system prescribed by the Codification when referring to GAAP in the third quarter of fiscal 2009.

NOTE D: Long-term Debt

On October 16, 2007, the Company entered into an Amended and Restated Credit Agreement (“Amended Credit Agreement”) with Wachovia Bank (the “Bank”) as Administrative agent, Issuing Bank, Sole Lead Arranger and Sole Bookrunner. The Amended Credit Agreement provided for financing of up to $200 million to the Company. The initial borrowing base of the Amended Credit Agreement was $110 million, subject to redetermination on April 1 and October 1 of each year. On September 30, 2008, the borrowing base was reduced to $95 million due to the sales of certain of the Company’s non-core oil and gas properties. On November 5, 2008, the borrowing base was increased to $100 million and on April 6, 2009, the $100 million borrowing base was reaffirmed by the Bank.

On July 13, 2009, the Company entered into a Second Amended and Restated Credit Agreement (“Second Amended Credit Agreement”). The Second Amended Credit Agreement increased the facility from $200 million to $250 million and extended the term of the agreement to October 16, 2012. The initial borrowing base of the facility is $135 million The Second Amended Credit Agreement provides for interest rates at (a) LIBOR plus 2.25% to 3.00% or (b) the prime lending rate plus 1.25% to 2.00%, depending upon the amount borrowed. The agreement also requires the payment of commitment fees to the lender in respect of the unutilized commitments. 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 Second Amended Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets.

The Second Amended Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and lease back transactions, pay dividends and distributions or repurchase its capital stock, engage in mergers or consolidations, make significant changes to management, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the Second Amended Credit Agreement 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, 2009.

The principal outstanding under the Second Amended Credit Agreement was $98 million at June 30, 2009 and $40 million at December 31, 2008. The annual interest rate in effect at June 30, 2009 was 3.07% on the entire amount of outstanding principal. The remaining borrowing capacity under the Second Amended Credit Agreement, as of August 5, 2009, was $34 million. The maturity date for amounts outstanding under this agreement is October 16, 2012.

Interest expense for the three months ended June 30, 2009 and 2008, included amortization of deferred financing costs of $132,000 and $119,000, respectively. Interest expense for the six months ended June 30, 2009 and 2008, included amortization of deferred financing costs of $264,000 and $239,000, respectively.

In October 2007, the Company entered into an interest rate swap agreement with the Bank, providing a fixed rate of 4.79% on a notional $50,000,000 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 annual interest rate of 4.29%. The $40 million swap is accounted for as a cash flow hedge while the $10 million swap is accounted for as a trading security. The fair market value of these swaps at June 30, 2009, was a liability of $2,224,000 of which $1,722,000 is classified as a current liability. The fair market value of the two swaps at December 31, 2008 was a liability of $2,817,000 of which $1,572,000 was classified as a current liability. The Company also recognized a net loss of $6,000 on the $10 million swap during the three months ended June 30, 2009. This loss was due to cash settlement losses of $83,000 which were offset by a mark-to-market gain of $77,000. During the six months ended June 30, 2009, the Company recognized a net loss of $58,000 on the $10 million swap. This loss was due to cash settlement losses of $177,000 which were offset by a mark-to-market gain of $119,000.

At June 30, 2009 and December 31, 2008, accumulated other comprehensive income included unrecognized losses of $1,101,000, net of a tax benefit of $678,000, and $1,394,000, net of a tax benefit of $859,000, respectively. These unrecognized losses represent the inception to date change in mark-to-market value of the Company’s $40 million interest rate swap, designated as a hedge, as of the balance sheet date. For the three months ended June 30, 2009, the Company recognized realized cash settlement losses of $455,000 related to the $40 million swap. For the six months ended June 30, 2009, the Company recognized realized cash settlement losses of $768,000 related to the swap. Based on the estimated fair market value of the Company’s $40 million derivative contract designated as a hedge at June 30, 2009, the Company expects to reclassify net losses of $1.4 million into earnings from accumulated other comprehensive income (loss) during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

NOTE E: Stock Options, Performance Awards and Stock Warrants

In March 2007, the shareholders of the Company approved the GeoResources, Inc, Amended and Restated 2004 Employees’ Stock Incentive Plan (the “Plan”), which authorizes the issuance of options and other stock-based incentives to officers, employees, directors and consultants of the Company to acquire up to 2,000,000 shares of the Company’s common stock at prices which may not be less than the stock’s fair market value on the date of grant. The options can be designated as either incentive options or nonqualified options.

On February 3, 2009, and March 26, 2009, the Company granted options under the Plan to officers and other employees to purchase 300,000 and 225,000 shares of common stock, respectively. Also on February 3, 2009, the Company granted options to outside directors to purchase 200,000 shares of common stock. The following is a summary of the terms of these grants by exercise price:


	Number of Shares Exercisable at
Vesting Date	$8.50	$10.00	Total
Officers and Employees
February 3, 2010	65,625	65,625	131,250
February 3, 2011	65,625	65,625	131,250
February 3, 2012	65,625	65,625	131,250
February 3, 2013	65,625	65,625	131,250
Directors
February 3, 2010	25,000	25,000	50,000
February 3, 2011	25,000	25,000	50,000
February 3, 2012	25,000	25,000	50,000
February 3, 2013	25,000	25,000	50,000

Total	362,500	362,500	725,000

The closing market prices of the Company’s common stock on the date of the February and March 2009 grants were $7.62 and $7.16, respectively.

The options, if not exercised, will expire 10 years from the date of grant.

A summary of the Company’s stock option activity for the six months ended June 30, 2009 is as follows:


	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (year)	Aggregate Intrinsic Value
Outstanding, December 31, 2008	790,000	$	9.39	8.81	158,750
Granted	725,000	$	9.25
Exercised	—	$	—
Forfeited	—	$	—

Outstanding, June 30, 2009	1,515,000	$	9.32	8.78	1,669,875

Exercisable at June 30, 2009:	—

The Company accounts for these stock options under the provisions of Statement of Financial Accounting Standards No. 123R, “Share Based Payment” and accordingly, recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. For the three months ended June 30, 2009 and 2008, the Company recognized compensation expense of $396,000 and $149,000, respectively, related to these options. For the six months ended June 30, 2009 and 2008, the Company recognized compensation expense of $661,000 and $298,000, respectively, related to these options. As of June 30, 2009, the future pre-tax expense of non-vested stock options is $3,467,000 to be recognized through the first quarter of 2013.

The weighted-average fair value of the options granted during the six months ended June 30, 2009, was $4.36 per share, using the following assumptions:


Risk-free interest rate	1.25	%
Dividend yield	None
Volatility	87	%
Expected life of option	4 Years

In measuring compensation associated with these options, an annual pre-vesting forfeiture rate of 1% was used.

NOTE F: Income Taxes

The Company accounts for income taxes under the provision of SFAS No. 109, Accounting for Income Taxes , which provides for an asset and liability approach in accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

FIN 48 – Uncertain Tax Positions

The Company also accounts for income taxes under the provisions of FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, and FSP FIN 48-1, which provide that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. FIN 48 prescribes a benefit recognition model with 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. FIN 48 also requires that the amount of interest expense recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return.

The Company did not have any uncertain tax positions and there was no effect on its financial condition or results of operations as a result of implementing FIN 48. 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.

The Company’s continuing practice is to recognize estimated interest and penalties, if any, related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in its Consolidated Statement of Income. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current quarter. 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, 2010.

NOTE G: Derivative Financial Instruments

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

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

On October 17, 2008, the Company paid $2,975,000 to cancel its 2009 natural gas swaps that were previously accounted for as cash flow hedges. At the time of cancelation, accumulated other comprehensive income (loss) contained $482,000 of acquisition to date mark-to-market losses on the effective portion of these commodity derivative contracts. As a result of the cancelation of the swaps, the amounts recorded in accumulated other comprehensive income (loss) as of the date of cancelation remained in accumulated other comprehensive income (loss) and will be reclassified into earnings during 2009 as the original hedged transactions affect earnings. During the three and six month periods ended June 30, 2009, the Company reclassified into earnings from other comprehensive income (loss) $121,000 and $243,000 of losses, respectively. The Company expects to reclassify into earnings $239,000 of losses from accumulated other comprehensive income (loss) related the canceled swaps during the next twelve months. The remainder of the cost to cancel was previously recognized as part of a prior acquisition or through ineffectiveness charges.

At June 30, 2009, accumulated other comprehensive income (loss) consisted of unrecognized gains of $435,000, net of taxes of $268,000, representing the inception to date change in mark-to-market value of the effective portion of the Company’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2008, accumulated other comprehensive income (loss) consisted of unrecognized gains of $8,677,000, net of taxes of $5,348,000. For the three and six months ended June 30, 2009, the Company recognized realized net cash settlement gains on commodity derivatives of $2,131,000 and $5,532,000, respectively. The Company also reclassified losses related to the swap contracts canceled during 2008 of $121,000 and $243,000, respectively, for the three and six months ended June 30, 2009. For the three and six months ended June 30, 2008, the Company recognized realized net cash settlement losses on commodity derivatives of $5,840,000 and $7,926,000, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at June 30, 2009, the Company expects to reclassify net gains of $624,000 into earnings from accumulated other comprehensive income (loss) during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially. The Company also expects to reclassify losses of $239,000 related to the commodity swaps canceled during 2008, into earnings from accumulated other comprehensive income (loss).

During the first quarter of 2009 the Company entered into two natural gas swap contracts and one crude oil fixed price forward sale contract. The natural gas swaps have fixed prices of $4.86 and $4.87 per MMBTU. The term of the contracts is from April 2009 to March 2010 and each contract is for 50,000 MMBTUs per month. The fixed price crude oil contract is directly associated with the Company’s Williston Basin production. Under this agreement the Company will sell 9,000 Bbls per month from April 2009 to March 2010 at a price of $43.85. During the second quarter of 2009, the Company entered into two additional natural gas swap contracts. The natural gas swaps have fixed prices of $5.16 and $5.20 per MMBTU. The term of the contracts is from July 2009 to December 2010. The $5.16 contract is for 180,000 MMBTUs per month for the remaining six months of 2009 and 120,000 MMBTUs per month during 2010. The $5.20 contract is for 70,000 MMBTUs per month for the remaining six months of 2009 and 40,000 MMBTUs per month during 2010.

At June 30, 2009, 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:
2009	184,000			$	76.00
2010	322,000			$	74.71
2011	282,000			$	74.37
Forward sales contracts:
2009	54,000			$	43.85
2010	27,000			$	43.85
Natural Gas Contracts (Mmbtu)
Swap contracts
2009	300,000			$	4.86
2009	300,000			$	4.87
2009	1,080,000			$	5.16
2009	420,000			$	5.20
2010	150,000			$	4.86
2010	150,000			$	4.87
2010	1,440,000			$	5.16
2010	480,000			$	5.20
Costless collars contracts:
2009	137,765	$	7.00	$	10.75
2010	1,287,000	$	7.00	$	9.90
2011	1,079,000	$	7.00	$	9.20

The fair market value of these hedge contracts at June 30, 2009, was a net asset of $970,000 of which $2,385,000 was classified as a current asset, $346,000 was classified as a long-term asset and $1,761,000 was classified as a current liability. The fair market value of the Company’s hedge contracts at December 31, 2008, was an asset of $14,609,000, of which $8,200,000 was classified as a current asset. During the three and six months ended June 30, 2009, the Company recognized a loss of $26,000 and $75,000, respectively, due to hedge ineffectiveness on these hedge contracts. During the three months ended June 30, 2008, the Company recognized a gain of $582,000 due to hedge ineffectiveness. During the six months ended June 30, 2008, the Company recognized a loss of $937,000 due to hedge ineffectiveness.

The Company has also entered into an interest rate swap designated as a cash flow hedge as discussed in Note D above.

SFAS 161 – Effective January 1, 2009, the Company adopted Financial Accounting Standard Board (“FASB”) Statement No. 161, Disclosure about Derivative Instruments and Hedging Activities – an amendment to FASB Statement No. 133 (“SFAS 161”). SFAS 161 expands interim and annual disclosures about derivative and hedging activities that are intended to better convey the purpose of derivative use and the risks managed. The adoption of SFAS 161 did not have an impact on the Company’s consolidated financial statements, other than additional disclosures which are set forth below.

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 SFAS 133 hedges:	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet Location	Jun. 30, 2009		Dec. 31, 2008		Balance Sheet Location	Jun. 30, 2009			Dec. 31, 2008
Commodity contracts	Current derivative financial instruments asset	$	2,385	$	8,200	Current derivative financial instruments liability	$	(1,761	)	$	—
Commodity contracts	Long-term derivative financial instruments asset		346		6,409	Long-term derivative financial instruments liability		—			—
Interest rate swap contract	Current derivative financial instruments asset		—		—	Current derivative financial instruments liability		(1,377	)		(1,258	)
Interest rate swap contract	Long-term derivative financial instruments asset		—		—	Long-term derivative financial instruments liability		(402	)		(996	)

		$	2,731	$	14,609		$	(3,540	)	$	(2,254	)


Derivatives not designated as SFAS 133 hedges:	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet Location	Jun. 30, 2009		Dec. 31, 2008		Balance Sheet Location	Jun. 30, 2009			Dec. 31, 2008
Interest rate swap contract	Current derivative financial instruments asset	$	—	$	—	Current derivative financial instruments liability	$	(345	)	$	(314	)
Interest rate swap contract	Long-term derivative financial instruments asset		—		—	Long-term derivative financial instruments liability		(100	)		(249	)

		$	—	$	—		$	(445	)	$	(563	)

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, 2009 and 2008 (in thousands):


Derivatives designated as SFAS 133 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 SFAS 133 hedges:	Jun. 30, 2009			Jun. 30, 2008				Jun. 30, 2009			Jun. 30, 2008
Commodity contracts	$	(11,760	)	$	(59,878	)	Oil and gas revenues	$	2,011		$	(5,840	)
Interest rate swap contract		(86	)		(220	)	Interest expense		(392	)		(36	)

	$	(11,846	)	$	(60,098	)		$	1,619		$	(5,876	)


Derivatives in SFAS 133 cash flow hedging relationships:	Location of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)	Amount of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)
		Jun. 30, 2009			Jun. 30, 2008
Commodity contracts	Hedge ineffectiveness	$	26		$	(582	)


Derivatives not designated as SFAS 133 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 SFAS 133 hedges:		Jun. 30, 2009			Jun. 30, 2008
Realized cash settlements on interest rate swap	Loss on derivative contracts	$	83		$	—
Unrealized (gains) on commodity contracts	Loss on derivative contracts		(77	)		—

		$	6		$	—

The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the six months ended June 30, 2009 and 2008 (in thousands):


Derivatives designated as SFAS 133 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 SFAS 133 hedges:	Jun. 30, 2009			Jun. 30, 2008				Jun. 30, 2009			Jun. 30, 2008
Commodity contracts	$	(8,033	)	$	(74,000	)	Oil and gas revenues	$	5,289		$	(7,926	)
Interest rate swap contract		(294	)		(164	)	Interest expense		(768	)		19

	$	(8,327	)	$	(74,164	)		$	4,521		$	(7,907	)


Derivatives in SFAS 133 cash flow hedging relationships:	Location of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)	Amount of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)
		Jun. 30, 2009			Jun. 30, 2008
Commodity contracts	Hedge ineffectiveness	$	75		$	937


Derivatives not designated as SFAS 133 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 SFAS 133 hedges:		Jun. 30, 2009			Jun. 30, 2008
Realized cash settlements on interest rate swap	Loss on derivative contracts	$	177		$	—
Unrealized (gains) on commodity contracts	Loss on derivative contracts		(119	)		—

		$	58		$	—

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

SFAS 157 – Effective January 1, 2008, the Company adopted FASB Statement No. 157, Fair Value Measurements (“SFAS 157”), which 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. The implementation of SFAS 157 did not cause a change in the method of calculating fair value assets or liabilities. The primary impact from adoption was additional disclosures.

Fair Value Hierarchy – SFAS 157 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. The table below presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

Cash, Cash Equivalents, Accounts Receivable and Payable and Revenue Royalties – 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.

Derivative Assets and Liabilities - June 30, 2009

(in thousands)


	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)	Balance as of June 30, 2009
Current portion of derivative financial instrument asset ⁽¹⁾	—	$	2,385		—	$	2,385
Long-term portion of derivative financial instrument asset ⁽¹⁾	—		346		—		346
Current portion of derivative financial instrument liability ⁽²⁾	—		(3,483	)	—		(3,483	)
Long-term portion of derivative financial instrument liability ⁽³⁾	—		(502	)	—		(502	)

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

(2)	Includes a $40 million interest rate swap accounted for as a cash flow hedge ($1,377,000), a $10 million interest rate swap accounted for as a trading security ($345,000) and a commodity derivative accounted for as a cash flow hedge ($1,761,000).

(3)	Includes a $40 million interest rate swap accounted for as a cash flow hedge ($402,000) and a $10 million interest rate swap accounted for as a trading security ($100,000).

Derivative Assets and Liabilities - December 31, 2008

(in thousands)


	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)	Balance as of December 31, 2008
Current portion of derivative financial instrument asset ⁽¹⁾	—	$	8,200		—	$	8,200
Long-term portion of derivative financial instrument asset ⁽¹⁾	—		6,409		—		6,409
Current portion of derivative financial instrument liability ⁽²⁾	—		(1,572	)	—		(1,572	)
Long-term portion of derivative financial instrument liability ⁽³⁾	—		(1,245	)	—		(1,245	)

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

(2)	Includes a $40 million interest rate swap accounted for as a cash flow hedge ($1,258,000) and a $10 million interest rate swap accounted for as a trading security ($314,000).

(3)	Includes a $40 million interest rate swap accounted for as a cash flow hedge ($996,000) and a $10 million interest rate swap accounted for as a trading security ($249,000).

At June 30, 2009, and December 31, 2008, the Company did not have any assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3.

Asset Impairments – In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company reviews proved oil and gas properties for impairment when events and circumstances indicate a significant decline in the recoverability of the carrying value of such properties. When events and circumstances indicate a significant decline in the recoverability of a property, the Company estimates the future cash flows expected in connection with the property and compares such future cash flows to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.

The Company recorded asset impairments of $128,000 on proved properties during the three and six months ended June 30, 2009. During the three and six months ended June 30, 2008, the Company recorded impairments of $483,000 on unproved properties. The 2009 impairments were included in impairment expense while the 2008 impairments, due to the nature of the expenses, were included in exploration expense. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis 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.

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 I.

Business Combinations – In accordance with SFAS 141R, B usiness 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 strips 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: 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. In accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), 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, 2009, are as follows (in thousands):


Asset retirement obligation, January 1, 2009	$	5,418
Additional liabilities incurred	$	216
Accretion expense		177
Disposals of properties		(187	)

Asset retirement obligation, June 30, 2009	$	5,624

NOTE J: Related Party Transactions

Accounts receivable at June 30, 2009, and December 31, 2008, included $2,208,000 and $2,311,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at June 30, 2009, and December 31, 2008, also included $166,000 and $594,000, 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, 2009, and December 31, 2008, included $7,873,000 and $9,333,000, respectively, due to SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at June 30, 2009, and December 31, 2008, also included $460,000 and $977,000, respectively, due to OKLA Energy for oil and gas revenues collected on its behalf.

The Company earned partnership management fees during the three months ended June 30, 2009 and 2008, of $398,000, and $522,000, respectively. The Company earned partnership management fees during the six months ended June 30, 2009 and 2008, of $696,000 and $834,000, respectively.

Subsidiaries of the Company operate the majority of 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 each partnership’s behalf. These revenues are paid monthly to each partnership, which in turn reimburses the Company for the partnership’s share of expenditures.

In May 2009, the Company, through its subsidiary, Catena, entered into a Purchase and Sale Agreement with an affiliated limited partnership, SBE Partners. Catena purchased the properties for $49,340,000. As the General Partner of SBE Partners, Catena received a distribution from the partnership as a result of the sale of $987,000. The net purchase price for the properties was $48,353,000. This acquisition is discussed in Note B above.

The following is a summary of selected financial information of SBE Partners, LP for the six months ended June 30, 2009 and 2008 (in thousands):


	Six Months Ended June 30,
	2009		2008
Summary of Partnership operations:
Revenues	$	40,854	$	44,018
Income from continuing operations	$	26,119	$	27,699
Net income	$	26,119	$	27,699
The Company’s equity in Partnership net income	$	1,471	$	639

NOTE K: Subsequent Events

The Company evaluated its June 30, 2009 financial statements for subsequent events through August 6, 2009, the date the financial statements were issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements.

Item 2.

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

The following is Management’s Discussion and Analysis (“MD&A”) 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/A for the year ended December 31, 2008.

Forward-Looking Information

Certain of the statements in all parts of this document, contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by words such as “may,” “will,” “expect,” “anticipate,” “estimate” or “continue,” or comparable words. All statements other than statements of historical facts included in this report, including, without limitation, statements regarding our business strategy, plans, objectives, expectations, intent, and beliefs of management, related to current or future operations are forward-looking statements. Such statements are based on certain assumptions and analyses made by management in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes to be appropriate. The forward-looking statements included in this report are subject to a number of material risks and uncertainties including assumptions about the pricing of oil and gas, assumptions about operating costs, operations continuing as in the past or as projected by independent or Company engineers, the ability to generate and take advantage of acquisition opportunities and numerous other factors. A detailed discussion of important factors that could cause actual results to differ materially from the Company’s expectations are discussed herein and in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2008. Forward-looking statements are not guarantees of future performance and actual results; therefore, developments and business decisions may differ materially from those envisioned by such forward-looking statements.

General Overview

We are an independent oil and gas company engaged in the acquisition and development of oil and gas reserves through an active and diversified program which includes purchases of reserves, re-engineering, development and exploration activities. As further discussed herein, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to effectively compete for capital and 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.

We continue to implement our business strategy to acquire, discover and develop oil and gas reserves and achieve continued growth. Management continues to focus on reducing operating and administrative costs on a per unit basis. In addition, we have attempted to mitigate downward price volatility by the use of commodity price hedging. The current volatile price environment for oil and natural gas is significant, and management cannot predict the prices that will be available during the life of our current business plan. Following is a brief outline of our current plans:

(1)

Acquire oil and gas properties with significant producing reserves and development and exploration potential;

(2)

Solicit industry or institutional partners to participate, on a promoted basis, in acquisitions or projects where the capital commitments or risks exceed our existing financial capability, in order to manage our financial position, diversify opportunities, reduce average cost and generate operating fees;

(3)

Implement re-engineering and development programs within existing fields;

(4)

Pursue exploration projects and increase direct participation over time. Solicit industry partners, on a promoted basis, for internally generated projects;

(5)

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

(6)

Continue activities directed toward reducing per-unit operating and general and administrative costs on a long-term sustained basis; and

(7)

Obtain additional capital through the issuance of equity securities and/or through reasonable debt financing.

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

In addition to our fundamental business strategy, we intend to actively pursue corporate acquisitions or mergers. Management believes that opportunities may become available to acquire corporate entities or otherwise effect business combinations, particularly as a result of recent commodity prices and the contraction in equity and debt financing markets. We intend to consider any such opportunities which may become available and are beneficial to stockholders. The primary financial considerations in the evaluation of any such potential transaction will include, but are not limited to: (1) the ability of small capitalization oil and gas companies to gain recognition and favor in the public markets, (2) share appreciation potential, (3) shareholder liquidity, and (4) capital formation and cost of capital to effect growth.

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

Bakken Acquisition

In May 2009, we closed an acquisition of producing wells and acreage in the Bakken Shale trend of the Williston Basin. The acquisition was made through an existing joint venture. We acquired a 15% interest in approximately 60,000 net acres, and also acquired 15% of varying working interests in 59 producing and productive wells. Our share of producing wells and undeveloped locations added approximately 486,000 barrel of oil equivalent (“BOE”) of proved reserves and numerous prospective locations. We now have working interest in the area ranging from 10% to 15% in approximately 100,000 net acres. Of those total acres, approximately 59,000 net acres are located in Mountrail County, with the remainder located in adjacent North Dakota counties and Richland County, Montana. The acquisition cost was approximately $10.4 million, subject to closing adjustments for normal operations activity and other customary purchase price adjustments. We funded the acquisition with borrowings from our senior secured revolving credit facility.

Giddings Field Acquisition

In May 2009, we entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with an affiliated limited partnership for which we serve as the general partner, SBE Partners LP (the “Seller”) for the acquisition (the “Acquisition”) of certain oil and gas producing properties in Giddings Field, Grimes and Montgomery Counties, Texas (the “Interests”). Prior to the acquisition, we had direct working interests in the properties ranging from about 6.5% to 7.8%. After the acquisition, we hold direct working interests in the producing wells ranging from approximately 34% to 37%. The acquired direct working interests total an estimated 25 Bcfe of proved reserves, 88% natural gas and 73% developed, with daily production, at the time of the acquisition, totaling 10,625 Mcf and 85 Bbls of associated liquids. In addition, we immediately increased our partnership sharing ratio from 2% to 30%, amounting to approximately 13.2 Bcfe. Furthermore, our share of the partnership’s daily production, subsequent to the acquisition, amounts to 5,618 Mcf and 45 Bbls of associated liquids. We will remain the general partner of the affiliated partnership and operator of the properties. The acquisition also provides additional development opportunities and exposure to the upside associated with the Eagleford Shale and other prospective targets. Under the Purchase Agreement, the Interests were purchased for a net cash purchase price of $48.4 million, subject to adjustments at closing for normal operations activity and other customary purchase price adjustments (the “Purchase Price”). We funded the Purchase Price with borrowings from our senior secured revolving credit facility. The Purchase Agreement contains representations and warranties, covenants, and indemnifications that are customary for oil and gas producing property acquisitions.

In January 2009, we sold a producing property located in Louisiana to an unaffiliated party for $1.6 million. We recognized a gain of $1.3 million in conjunction with this sale.

Results of Operations

Three months ended June 30, 2009, compared to three months ended June 30, 2008

The Company recorded net income of $3,499,000 for the three months ended June 30, 2009 compared to net income of $7,790,000 for the same period in 2008. This $4,291,000 decrease resulted primarily from the following factors:

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


Oil and gas sales	$	(8,289	)
Lease operating expenses		1,372
Production taxes		1,860
Exploration expense		214
Re-engineering and workovers		669
General and administrative expenses (“G&A”)		(69	)
Depletion, depreciation and amortization expense (“DD&A”)		(1,152	)
Impairment expense		(128	)
Net interest income (expense)		(23	)
Hedge ineffectiveness		(608	)
Gain (loss) on derivative contracts		(6	)
Gain (loss) on sale of property		(1,462	)
Other income - net		1,001

Income before income taxes		(6,621	)
Provision for income taxes		2,330

Net decrease	$	(4,291	)

The following discussion applies to the above changes.

Oil and Natural Gas Sales . Net revenues from oil and gas sales decreased $8,289,000, or 33%. Revenue decreased by $2,090,000 due to properties sold in 2008. The remaining decrease of $6,199,000 resulted primarily from decreases in commodity prices, offset by increases in production volumes. Properties purchased in May 2009 accounted for increased volumes of approximately 341,000 Mcf of gas and approximately 6,000 barrels of oil. Price and production comparisons are set forth in the following table.


	Percent increase (decrease)		Three Months Ended June 30,
	Percent increase (decrease)		2009		2008
Gas Production (MMcf)	51	%		1,087		719
Oil Production (MBbls)	14	%		212		186
Barrel of Oil Equivalent (MBOE)	29	%		393		305
Average Price Gas Before Hedge Settlements (per Mcf)	-71	%	$	3.24	$	11.05
Average Price Oil Before Hedge Settlements (per Bbl)	-57	%	$	53.40	$	124.09
Average Realized Price Gas (per Mcf)	-59	%	$	3.95	$	9.74
Average Realized Price Oil (per Bbl)	-39	%	$	59.28	$	97.66

Lease Operating Expenses. Lease operating expenses decreased from approximately $5,789,000 in the second quarter of 2008 to $4,417,000 for the same period in 2009, a decrease of $1,372,000 or 24%. On a unit-of-production basis, barrel of oil equivalent (“BOE”) costs decreased by $7.74 or 41% as a result of acquisition of properties with lower operating costs, divestitures of properties with higher operating costs, re-engineering projects completed during 2008 that either enhanced production or lowered per unit operating costs, and reductions in costs for materials, services and rigs during 2009.

Re-engineering and Workover . Re-engineering and workover costs decreased by $669,000 from $984,000 to $315,000, due to completion of projects associated with 2007 and 2008 acquistions and the divestiture of certain properties.

Production Taxes . Production taxes decreased by $1,860,000 or 77%, due to decreased revenues as well as from a nonrecurring refund of $599,000 resulting from regulatory state tax exemption received on certain Austin Chalk wells with high drilling costs. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the quarter ended June 30, 2009 and 2008 were 3.8% and 7.8%, respectively, of oil and gas sales before the effects of hedging. The 2009 rate decreased from 2008 due to a change in our portfolio of producing properties, production tax exemptions and the nonrecurring refund.

General and Administrative Expenses. G&A increased $69,000 due to overall business expansion and salary increases offset by cost reduction efforts. Included in G&A expense for the three months ended June 30, 2009 and 2008, are non-cash charges related to our stock-based compensation of $397,000 and $149,000, respectively.

Depreciation, Depletion and Amortization . DD&A expense increased by $1,152,000 or 32% due to higher capitalized costs. Capitalized costs increased due to acquisition and successful drilling and development activities, including additional property interests acquired in both the Giddings Field, Texas and the Bakken Shale trend in North Dakota.

Interest Income and Expense . Interest expense decreased by $170,000 due to lower average debt levels in the second quarter of 2009 compared to the same period in 2008. During the second quarter of 2009, our average outstanding debt was approximately of $63,000,000 compared to $86,000,000 for the same period in 2008. Interest income decreased by $193,000 in the second quarter of 2009 over the same period of 2008, due to on average lower invested cash balances and lower interest rates.

Hedge Ineffectiveness . In the second quarter of 2009 the loss from hedge ineffectiveness was $26,000, compared to gain from hedge ineffectiveness of $582,000 for the same period in 2008. In the second, third and fourth quarters of 2008 our realized price was more consistent with the market benchmark used for hedging; therefore, the cumulative ineffectiveness charge was reduced and we recorded a gain on hedge ineffectiveness for the year. In the second quarter of 2009, the differential between the market benchmark used for hedging and the prices we realized on our sales of oil and gas increased slightly and given that the commodity hedges increased in value during the first six months of the year, the inception-to-date ineffectiveness decreased and we recorded an expense.

Loss on Derivative Contracts . In December 2008, we split a $50 million notional value interest rate swap that was previously accounted for as a cash flow hedge. The swap was split into a $10 million notional amount swap and a $40 million notional amount swap. We continued hedge accounting for the $40 million swap and accounted for the $10 million swap as a trading security. In the second quarter of 2009, we recognized cash settlement losses on the $10 million swap of $83,000. These losses were offset by mark-to-market gains of $77,000.

Other Income . Other income increased by $1,001,000 in the second quarter of 2009 compared to the same period in 2008 due to an increase in partnership income of $1,026,000, partially offset by $124,000 lower partnership management fees. Partnership income in the second quarter of 2009 included our share of partnership severance tax refunds of $1,318,000, related to tax exempt well status obtained for certain wells with a high drilling cost. Additionally, property operating income increased by $99,000.

In the second quarter 2009 we had a net gain on sales of properties and other assets of $89,000 versus $1,551,000 in the same period of 2008.

Income Tax Expense . Income tax expense for the second quarter of 2009 was $2,216,000 compared to $4,546,000 for the same period in 2008. Our income tax expense decreased due to lower pre-tax earnings. Our effective tax rate during the second quarter of 2009 was approximately 39% versus 37% in the same period during 2008. Our effective tax rate increased as a result of the qualified stock options; the expense related to these options is not deductible in determining taxable income.

Six months ended June 30, 2009, compared to six months ended June 30, 2008

The Company recorded net income of $3,976,000 for the six months ended June 30, 2009 compared to net income of $12,014,000 for the same period in 2008. This $8,038,000 decrease resulted primarily from the following factors:

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


Oil and gas sales	$	(18,452	)
Lease operating expenses		2,773
Production taxes		2,955
Exploration expense		134
Re-engineering and workovers		386
General and administrative expenses (“G&A”)		(380	)
Depletion, depreciation and amortization expense (“DD&A”)		(1,743	)
Impairment expense		(128	)
Net interest income (expense)		610
Hedge ineffectiveness		862
Gain (loss) on derivative contracts		(58	)
Gain (loss) on sale of property		(473	)
Other income - net		910

Income before income taxes		(12,604	)
Provision for income taxes		4,566

Net decrease	$	(8,038	)

The following discussion applies to the above changes.

Oil and Natural Gas Sales . Net revenues from oil and gas sales decreased $18,452,000, or 39%. This decrease resulted primarily from lower commodity prices, partially offset by increases in production volumes. Properties sold in 2008 accounted for a decrease in revenue of $5,478,000. Price and production comparisons are set forth in the following table. Properties acquired in May 2009 accounted for increased volumes of approximately 341,000 Mcf of gas and approximately 6,000 barrels of oil.


	Percent increase (decrease)		Six Months Ended June 30,
	Percent increase (decrease)		2009		2008
Gas Production (MMcf)	15	%		1,752		1,528
Oil Production (MBbls)	1	%		389		385
Barrel of Oil Equivalent (MBOE)	6	%		681		640
Average Price Gas Before Hedge Settlements (per Mcf)	-63	%	$	3.43	$	9.30
Average Price Oil Before Hedge Settlements (per Bbl)	-57	%	$	45.88	$	107.11
Average Realized Price Gas (per Mcf)	-54	%	$	4.01	$	8.68
Average Realized Price Oil (per Bbl)	-36	%	$	56.87	$	89.01

Lease Operating Expenses. Lease operating expenses decreased from approximately $11,580,000 in the second quarter of 2008 to $8,807,000 for the same period in 2009, a decrease of $2,773,000 or 24%. On a unit-of-production basis, BOE costs decreased by $5.16 or 29% as a result of acquisition of properties with lower operating costs, divestitures of properties with higher operating costs, re-engineering projects completed during 2008 that either enhanced production or lowered per unit operating costs, and reductions in costs for materials, services and rigs during 2009

Re-engineering and Workover . Re-engineering and workover costs decreased by $386,000 from $1,682,000 to $1,296,000, due to completion of projects associated with 2007 and 2008 acquistions and the divestiture of certain properties.

Production Taxes . Production taxes decreased by $2,955,000 or 68%, due to decreased production volumes and revenues as well as from a nonrecurring refund of $599,000 resulting from a regulatory state tax exemption received on Austin Chalk wells with high drilling costs. 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 2009 and 2008 were 5.7% and 7.8%, respectively, of oil and gas sales before the effects of hedging. The 2009 rate decreased compared to 2008 as a result of a change in our portfolio of producing properties, production tax exemptions and the nonrecurring refund.

General and Administrative Expenses. G&A increased $380,000 in the first six months of 2009 compared to the same period in 2008 due to overall business expansion and salary increases offset by cost reduction efforts. Included in G&A expense for the six months ended June 30, 2009 and 2008 are non-cash charges related to our stock-based compensation of $661,000 and $298,000, respectively.

Depreciation, Depletion and Amortization . DD&A expense increased by $1,743,000 or 23% due to higher capitalized costs. Capitalized costs increased due to acquisitions of additional property interests in both the Austin Chalk and Bakken Shale and continued successful drilling in those same areas.

Interest Income and Expense . Interest expense decreased by $920,000 due to lower average debt levels in the first half of 2009 compared to the same period in 2008. During the first six months of 2009, our average outstanding debt was approximately of $51,000,000 compared to $88,000,000 for the same period in 2008. Interest income decreased by $310,000 in the first six months of 2009 compared to the same period of 2008, due to on average lower invested cash balances cash balances and lower interest rates.

Hedge Ineffectiveness . For the first six months of 2009 the loss from hedge ineffectiveness was $75,000, compared to a loss of $937,000 for the same period in 2008 In the second, third and fourth quarters of 2008 our realized price was more consistent with the market benchmark used for hedging; therefore, the cumulative ineffectiveness charge was reduced and we recorded a gain on hedge ineffectiveness for the year. In the first six months of 2009, the differential between the market benchmark used for hedging and the prices we realized on our sales of oil and gas increased slightly and given that the commodity hedges increased in value during the first six months of the year, the inception-to-date ineffectiveness decreased and we recorded an expense.

Loss on Derivative Contracts . In December 2008, we split a $50 million notional value interest rate swap that was previously accounted for as a cash flow hedge. The swap was split into a $10 million notional amount swap and a $40 million notional amount swap. We continued hedge accounting for the $40 million swap and accounted for the $10 million swap as a trading security. For the first six months of 2009, we recognized cash settlement losses on the $10 million swap of $177,000. These losses were offset by mark-to-market gains of $119,000.

Other Income . Other income increased by $910,000 in the first six months of 2009 compared to the same period in 2008 due to an increase in partnership income of $805,000, partially offset by lower partnership management fees. Partnership income in the first six months of 2009 included our share of partnership severance tax refunds of $1,318,000, related to tax exempt well status obtained for certain wells with a high drilling cost. Additionally, property operating income increased by $243,000.

In the first six months of 2009 we had a net gain on sales of properties and other assets of $1,488,000 versus $1,961,000 in the same period of 2008.

Income Tax Expense . Income tax expense for the first half of 2009 was $2,576,000 compared to $7,142,000 for the same period in 2008. Our income tax expense decreased due to lower pre-tax earnings. Our effective tax rate during the first six months of 2009 was approximately 39% versus 37% in the same period during 2008. Our effective tax rate increased as a result of the qualified stock options; the expense related to these options is not deductible in determining taxable income.

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. As demonstrated historically, prices are volatile and unpredictable. Oil prices increased appreciably during 2007 and again during the first and second quarters of 2008 but retreated somewhat during the third quarter of 2008 and dropped significantly since then before rising somewhat during the summer of 2009. Average realized oil prices of $56.87 per Bbl, net of hedges, for the six months ended June 30, 2009, were 36% lower than for the comparable period in 2008. Average realized natural gas prices of $4.01 per Mcf, net of hedges, for the six months ended June 30, 2009, were 54% lower than for the comparable period in 2008. The average realized prices for the six months ended June 30, 2009, included the effects of our hedges. Should significant, further price decreases occur or should prices fail to remain at levels which will facilitate repayment of debt and reinvestment of cash flow to replace current production, we could experience difficulty in developing our assets and continuing our growth.

Hedging Activities

In an attempt to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing, we have and will likely continue to enter into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. Management believes our hedging strategy will result in greater predictability of internally generated funds, which can be dedicated to capital development projects and corporate obligations.

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

(1)

Secure and maintain favorable debt financing terms;

(2)

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

(3)

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

(4)

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

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

Administrative and Operating Costs

We continue to focus on cost-containment efforts in seeking to 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 fulfill our contractual obligations.

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 costs.

Credit Facility

The borrowing base under our credit facility is currently $135 million. As of June 30, 2009, the outstanding principal balance was $98 million. As of August 5, 2009, the outstanding principal balance was $101 million, leaving unused borrowing capacity of $34 million. For the six months ended June 30, 2009, the weighted average annual interest rate in effect was 3.6%.

Cash Flows from Operating Activities

For the six months ended June 30, 2009, our net cash provided by operating activities was $3.9 million, compared to $26.7 million for the same period in 2008. We reduced our net current liabilities by $11.8 million and incurred unfavorable commodity price changes. We believe that we can continue to generate cash flows sufficient to allow us to continue with our planned capital program which will replace our reserves and increase our production.

Cash Flows from Investing Activities

Cash applied to oil and gas capital expenditures for the six months ended June 30, 2009 and 2008, was $70.2 million and $33.3 million, respectively. In 2009, we also realized cash of $2.0 million from the sale of properties compared to $20.4 million during the same period during 2008. Capital expenditures for 2009 were financed with debt of $58 million and working capital of $12.2 million. We expect to spend approximately $60 to $64 million in capital expenditures during the remainder of 2009 thru 2010.

Capital Budget

We previously reported an inventory of identified projects totaling approximately $83 million of capital expenditures. We continue to expand our portfolio of projects and in addition our acquisitions have further increased our expected drilling and development expenditures. Accordingly, at present we have identified approximately $110 million of diversified exploration and development projects, which are summarized in the table below. The table does not include all contemplated projects but is a representative of the bulk of such projects and represents a diversified group of exploration and development opportunities as well as planned expenditures for seismic and acreage in focused areas. A benefit of our portfolio is that it includes both gas and oil opportunities, much of which are “held by production” and therefore not subject to lease expiration or significant future carrying costs. Accordingly, we have some ability to adjust our capital spending as our financial position and industry circumstances dictate. Generally, we are committed to limit our capital spending to our cash flows, although in certain limited circumstances, we may utilize our borrowing capacity for development or lease saving operations. We do not intend to use our borrowing capacity for exploratory drilling. We may shift our expenditure between regions and projects (such as development versus exploration) in an attempt to maximize cash flow and take advantage of regional differences in net commodity prices and service costs. Furthermore, our budget may be accelerated or deferred, pending commodity prices, drilling and service rig availability and cost, and adequate staffing to effectively manage activities and control costs. While financial conditions and industry circumstances may require us to make adjustments, it is our current intent to continue our Bakken and Austin Chalk drilling programs and certain other projects in the Gulf Coast, West Texas and the Williston Basin. Given commodity price volatility, even our Bakken and Austin Chalk programs could be temporarily deferred. 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.

Inventory of Planned Exploration and Development Projects


	($ Millions)		Percent of District Opportunity
Southern District
Austin Chalk drilling and development ^{(1) (2)}	$	26.8	45	%
Other development drilling ⁽²⁾		14.6	24	%
Exploratory drilling ⁽³⁾		8.2	14	%
Acreage, seismic and other ⁽⁵⁾		5.5	9	%
Re-engineering and workover ⁽⁴⁾		3.7	6	%
Waterflood expansion		1.2	2	%

		60.0
Northern District
Bakken Shale drilling ⁽⁷⁾	$	20.5	41	%
Other development drilling ⁽²⁾		12.0	24	%
Horizontal development drilling ^{(2) (6)}		11.0	22	%
Acreage, seismic and other ⁽⁵⁾		3.0	6	%
Waterflood and associated drilling		2.5	5	%
Re-engineering and workover ⁽⁴⁾		1.0	2	%

		50.0

Total	$	110.0

Notes:

(1)

Horizontal drilling and development program with an affiliated institutional partnership. At present, we believe we have at least 14 additional drilling locations, the majority of which are expected to be dual laterals wells. We also expect to re-enter numerous well bores and extend existing laterals or drill additional laterals. None of the possible re-entries are included in the above table as all such opportunities are held by production and have no critical timing.

(2)	Includes both proved undeveloped and non-proved reserve potential.

(3)	Principally South Louisiana and the Texas Gulf Coast.

(4)

Includes activities related to existing fields intended to enhance production and lower operating expenses. These expenditures include replacement, repairs or additional flowlines, facilities, and/or compression as well as the modification of the down-hole lift method, recompletions and side-track drilling.

(5)	Potential expenditures associated with further expansion of acreage and prospect inventory generally within close proximity of our existing fields.

(6)	Includes eight horizontal development wells or additional lateral wells within existing fields where we have interests ranging from 66% to 100%.

(7)

Our participating working interests vary based on acreage contributed to the approved drilling units. On wells operated by our joint venture partner we expect our working interests to range from 4% to 10%. We expect to participate in 40-50 wells in the next 18-24 months. In addition, due to nominal acreage contributions to drilling units operated by others we will likely have interests in numerous wells below that working interest range, with many being 1% or less. While not material financially, management has generally elected to participate in all such drilling within this focus area primarily to collect valuable technical data related to the drilling operations and reservoir characteristics. Also, it includes one Bakken Shale test well in Montana where our working interest presently is 50%.

The projects and timing of 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 above will remain viable and therefore certain projects may be sold or abandoned by us.

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. 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. We use a Revolving Credit Facility, which has a floating interest rate. We are exposed to market risk from changes in interest rates. We enter into interest rate swaps to mitigate our exposure to interest rate changes. While the use of these swaps may limit the benefit of falling interest rates, they also limit the adverse effects of increasing interest rates.

The following is a list of contracts outstanding at June 30, 2009:

Transaction

Date

Transaction
Type

Beginning

Ending

Price Per
Unit ⁽¹⁾

Remaining

Annual Volumes

Fair Value
Outstanding
as of
June 30, 2009

(in thousands)

Natural Gas

October-07

Collar

01/01/09

12/31/09

$7.00 - $10.75

206,645 Mmbtu

878

October-07

Collar

01/01/10

12/31/10

$7.00 - $9.90

1,287,000 Mmbtu

1,328

October-07

Collar

01/01/11

12/31/11

$7.00 - $9.20

1,079,000 Mmbtu

605

February-09

Swap

04/01/09

03/31/10

$4.86

600,000 Mmbtu

March-09

Swap

04/01/09

03/31/10

$4.87

600,000 Mmbtu

June-09

Swap

07/01/09

12/31/10

$5.16

2,520,000 Mmbtu

216

June-09

Swap

07/01/09

12/31/10

$5.20

900,000 Mmbtu

169

3,281

Crude Oil

October-07

Swap

01/01/09

12/31/09

$76.00

184,000 Bbls

740

October-07

Swap

01/01/10

12/31/10

$74.71

322,000 Bbls

(204

)

October-07

Swap

01/01/11

12/31/11

$74.37

282,000 Bbls

(1,085

)

March-09

Forward Sale

04/01/09

03/31/10

$43.85

81,000 Bbls

(1,762

)

(2,311

)

Interest Rate

Oct-07/Dec-09

Swap

10/10/07

10/16/10

4.29375%

$40 Million Notional

30-day LIBOR

(1,779

)

Oct-07/Dec-09

Swap

12/16/08

10/16/10

4.29375%

$10 Million Notional

30-day LIBOR

(445

)

(2,224

)

(1,254

)

(1)	Price per unit is per Mmbtu for natural gas, per barrel for crude oil, and annual interest rate for interest rate swaps.

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 management evaluated, with the participation of our Chief Executive Officer and our Chief Financial Officer, 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, 2009. 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, 2009 to ensure 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 Securities and Exchange Commission (the “SEC”), and to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions 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, 2009, 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 2008 Annual Report on Form 10-K/A, which could materially affect our business, financial condition or future results. The risks described in our 2008 Annual Report on Form 10-K/A 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. Submission of Matters to a Vote of Security Holders*		None

*Item 5. Other Information*		None

Item 6.

Exhibits

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended June 30, 2009.



3.1		Amended and Restated Articles of Incorporation dates June 10, 2003, incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-KSB for the year ended December 31, 2003.

3.1(a)		Articles of Amendment to the Articles of Incorporation, incorporated by reference as Annex C to the Registrant’s definitive Proxy Statement dated February 23, 2007, and filed with the Commission on February 23, 2007.

3.1(b)		Articles of Amendment to Articles of Incorporation, dated November 6, 2007. (5)

3.2		Bylaws, as amended March 2, 2004, incorporated by reference to Exhibit 3.2 of Registrant’s Form 10-KSB for the year ended December 31, 2003.

10.15		Agreement and Plan of Merger dated September 14, 2006, among GeoResources, Inc., Southern Bay Energy Acquisition, LLC, Chandler Acquisition, LLC, Southern Bay Oil & Gas, L.P., Chandler Energy, LLC and PICA Energy, LLC (including Amendment No. 1 dated February 16, 2007). Incorporated by reference as Annex A to the Registrant’s Definitive Proxy Statement dated February 23, 2007 and filed with the Commission on February 23, 2007.

10.19		June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090. (3)

10.20		First Amendment to June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated November 10, 2003. (3)

10.21		Assignment and Assumption by Southern Bay Energy, L.L.C. of June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 19, 2005. (3)

10.22		Unconditional Guaranty of June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 19, 2005. (3)

10.23		Second Amendment to June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 19, 2005. (3)

10.24		Third Amendment to June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 9, 2007. (3)

10.26		January 31, 2000 Office Building Lease by and between 475-17 ^th Street, CO. and Collis P. Chandler III for 475 17th Street Building, Suite 860, 475 17th Street, Denver, Colorado 80202. (3)

10.27		First Amendment to January 31, 2000 Office Building Lease by and between 475-17 ^th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated September 28, 2001. (3)

10.28		Second Amendment to January 31, 2000 Office Building Lease by and between 475-17 ^th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated October 23, 2002. (3)

10.29		Third Amendment to January 31, 2000 Office Building Lease by and between 475-17 ^th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated June 28, 2004. (3)



10.30		Credit Agreement dated September 26, 2007 between the Registrant and Wachovia Bank National Association. (2)

10.31		Limited Partner Interest Purchase and Sale Agreement dated October 16, 2007 between the Registrant and TIFD III-X, LLC. (2)

10.32		Amended and Restated Credit Agreement dated October 16, 2007 between the Registrant and Wachovia Bank National Association. (2)

10.33		Amended and Restated Credit Agreement dated October 16, 2007 between the Registrant and Wachovia Bank National Association. (2)

10.34		Form of Purchase Agreement. (4)

10.35		Form of Warrant. (4)

10.36		Form of Registration Rights Agreement. (4)

10.37		Agreement of Limited Partnership for OKLA Energy Partners LP dated May 20, 2008. (6)

10.38		Lease Agreement by and between Southern Bay Energy, L.L.C. and Cypress Court Operating Associates, L.P. for office space at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated September 25, 2008. (7)

10.39		Purchase and Sale Agreement between SBE Partners LP and Catena Oil and Gas LLC, dated May 29, 2009. (1)

10.40		Consent and Amendment No. 1 to Agreement of Limited Partnership of SBE Partners LP as of May 29, 2009. (1)

10.41		Second Amended and Restated Credit Agreement between the Registrant and Wachovia Bank, National Association as Administrative Agent dated July 13, 2009. (1)

14.1		Code of Business Conduct and Ethics adopted March 2, 2004, incorporated by reference to Exhibit 14.1 of Registrant’s Form 10-KSB for fiscal year ended December 31, 2003.

21.1		Subsidiaries of the Registrant. (3)

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)

(1)	Filed herewith.

(2)	Filed with the Registrant’s Form 10-QSB for the quarter ended September 30, 2007.

(3)	Filed with the Registrant’s Form 10-QSB for the quarter ended June 30, 2007.

(4)	Filed with the Registrant’s Form 8-K on June 11, 2008.

(5)	Filed with the Registrant’s Form 10-KSB for the year ended December 31, 2007.

(6)	Filed with the Registrant’s Form 10-Q for the quarter ended June 30, 2008.

(7)	Filed with the Registrant’s Form 10-Q for the quarter ended September 30, 2008.

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 6, 2009
				/s/ Frank A. Lodzinski
				Frank A. Lodzinski
				Chief Executive Officer (Principal Executive Officer)

				/s/ Howard E. Ehler
				Howard E. Ehler
				Chief Financial Officer (Principal Accounting Officer)