Georesources (GEOI) 10-Q 2010 Q3 Quarterly report

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 September 30, 2010

Commission File Number – 0-8041

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  ¨

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	¨

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 November 4, 2010
Common stock, par value $.01 per share	19,723,916 shares

TABLE OF CONTENTS

	PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements.
	Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009.	3
	Consolidated Statements of Income for the Three and Nine Months ended September 30, 2010 and 2009.	5
	Consolidated Statement of Stockholders’ Equity and Comprehensive Income for the Nine Months ended September 30, 2010.	6
	Consolidated Statements of Cash Flows for the Nine Months ended September 30, 2010 and 2009.	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.	35
Item 4.	Controls and Procedures.	36
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings.	37
Item 1A.	Risk Factors.	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	37
Item 3.	Defaults Upon Senior Securities.	37
Item 4.	Reserved.	37
Item 5.	Other Information.	37
Item 6.	Exhibits.	38
	Signatures.	39

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

	September 30, 2010			December 31, 2009
	(unaudited)
ASSETS
Current assets:
Cash	$	12,131		$	12,660
Accounts receivable:
Oil and gas revenues		15,759			14,860
Joint interest billings and other		24,702			13,734
Affiliated partnerships		702			933
Notes receivable		120			120
Derivative financial instruments		5,988			764
Income taxes receivable		—			2,077
Prepaid expenses and other		2,100			2,297
Total current assets		61,502			47,445
Oil and gas properties, successful efforts method:
Proved properties		325,315			285,363
Unproved properties		12,976			10,281
Office and other equipment		1,155			828
Land		96			96
		339,542			296,568
Less accumulated depreciation, depletion and amortization		(66,700	)		(48,182	)
Net property and equipment		272,842			248,386
Equity in oil and gas limited partnerships		2,383			3,532
Derivative financial instruments		1,885			1,360
Deferred financing costs and other		2,704			3,574
	$	341,316		$	304,297

The accompanying notes are an integral part of these statements.

3

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

	September 30, 2010		December 31, 2009
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	3,463	$	6,452
Accounts payable to affiliated partnerships		3,037		8,361
Revenue and royalties payable		12,998		13,928
Income taxes payable		7,201		—
Drilling advances		—		390
Accrued expenses		2,270		1,574
Derivative financial instruments		2,721		4,794
Total current liabilities		31,690		35,499
Long-term debt		85,000		69,000
Deferred income taxes		17,848		15,778
Asset retirement obligations		6,761		6,110
Derivative financial instruments		962		3,233
Stockholders’ equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 19,723,916 in 2010 and 19,705,362 in 2009		197		197
Additional paid-in capital		147,862		146,966
Accumulated other comprehensive income		2,041		(3,288	)
Retained earnings		48,955		30,802
Total stockholders’ equity		199,055		174,677
	$	341,316	$	304,297

The accompanying notes are an integral part of these statements.

4

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except share and per share amounts)

(unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
Revenue:
Oil and gas revenues	$	25,612		$	19,980	$	74,684		$	49,109
Partnership management fees		124			151		423			847
Property operating income		498			398		1,282			1,312
Gain on sale of property and equipment		243			57		388			1,545
Partnership income		429			2,374		1,771			3,834
Interest and other		23			25		1,363			764
Total revenue		26,929			22,985		79,911			57,411
Expenses:
Lease operating expense		5,146			4,395		15,363			13,202
Severance taxes		1,520			1,200		4,843			3,161
Re-engineering and workovers		881			761		1,389			2,057
Exploration expense		163			620		766			988
Impairment of oil and gas properties		—			—		2,743			128
General and administrative expense		2,023			1,951		5,881			5,976
Depreciation, depletion and amortization		6,204			6,310		18,517			15,503
Hedge ineffectiveness		(658	)		111		(974	)		186
(Gain) / loss on derivative contracts		2			83		(2	)		141
Interest		1,391			1,586		3,949			3,549
Total expense		16,672			17,017		52,475			44,891
Income before income taxes		10,257			5,968		27,436			12,520
Income tax expense (benefit):
Current		8,834			356		10,699			(176	)
Deferred		(6,213	)		2,184		(1,416	)		5,292
		2,621			2,540		9,283			5,116
Net income	$	7,636		$	3,428	$	18,153		$	7,404
Net income per share (basic)	$	0.39		$	0.21	$	0.92		$	0.46
Net income per share (diluted)	$	0.38		$	0.21	$	0.90		$	0.46
Weighted average shares outstanding:
Basic		19,723,916			16,241,717		19,719,120			16,241,717
Diluted		20,080,670			16,323,353		20,076,472			16,241,717

The accompanying notes are an integral part of these statements.

5

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY and COMPREHENSIVE INCOME

Nine Months Ended September 30, 2010

(In thousands, except share data)

(unaudited)

	Common Stock				Additional Paid-in		Retained		Accumulated Other Comprehensive
	Shares		Par value		Capital		Earnings		Income (Loss)			Total
Balance, December 31, 2009		19,705,362	$	197	$	146,966	$	30,802	$	(3,288	)	$	174,677
Exercise of employee stock options
Cash exercises		10,500		—		103							103
Cashless exercises		8,054		—		2							2
Comprehensive income:
Net income								18,153					18,153
Change in fair market value of hedged positions, net of taxes of $4,231										6,564			6,564
Hedging gains realized in income, net of taxes of $744										(1,235	)		(1,235	)
Total comprehensive income													23,482
Equity based compensation expense						791							791
Balance, September 30, 2010		19,723,916	$	197	$	147,862	$	48,955	$	2,041		$	199,055

The accompanying notes are an integral part of this statement.

6

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)

	Nine Months Ended September 30,
	2010			2009
Cash flows from operating activities:
Net income	$	18,153		$	7,404
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		18,517			15,503
Proved property impairments		2,743			128
Gain on sale of property and equipment		(388	)		(1,545	)
Accretion of asset retirement obligations		300			271
Unrealized gain on derivative contracts		(305	)		(153	)
Amortization of loss on canceled hedge contract		—			363
Hedge ineffectiveness (gain) loss		(974	)		186
Partnership income		(1,771	)		(3,834	)
Partnership distributions		2,919			1,355
Deferred income taxes		(1,416	)		5,292
Non-cash compensation		793			1,064
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		10,285			(5,348	)
(Increase) decrease in prepaid expense and other		988			(355	)
Decrease in accounts payable and accrued expense		(1,734	)		(7,403	)
Net cash provided by operating activities		48,110			12,928
Cash flows from investing activities:
Proceeds from sale of property and equipment		540			2,660
Additions to property and equipment, net of acreage cost recoveries of $20,230 in 2010 and none in 2009		(65,282	)		(81,619	)
Net cash used in investing activities		(64,742	)		(78,959	)
Cash flows from financing activities:
Proceeds from stock options exercised		103			—
Issuance of long-term debt		16,000			64,000
Net cash provided by financing activities		16,103			64,000
Net increase (decrease) in cash and cash equivalents		(529	)		(2,031	)
Cash and cash equivalents at beginning of period		12,660			13,967
Cash and cash equivalents at end of period	$	12,131		$	11,936
Supplementary information:
Interest paid	$	3,161		$	2,938
Income taxes paid	$	2,629		$	677
Non-cash investing activities
Accounts receivable - acreage cost recoveries	$	20,000		$	—

The accompanying notes are an integral part of these statements.

7

GEORESOURCES, INC. and SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE A: Organization and Basis of Presentation

Description of Operations

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

Consolidated Financial Statements

The unaudited consolidated financial statements include the accounts of GeoResources, Inc. 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’ 2009 Annual Report on Form 10-K and 10-K/A includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in GeoResources’ 2009 Annual Report on Form 10-K and 10-K/A. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Reclassifications

Certain reclassifications have been made to the nine month period ended September 30, 2009 amounts on the Company’s Consolidated Statement of Income to conform to the current presentation of severance tax expense and interest and other income.

Earnings Per Share

Basic net income per common share is computed based on the weighted average shares of common stock outstanding. Net income per share computations reconciling basic and diluted net income for the three and nine months ended September 30, 2010 and 2009 consist of the following (in thousands, except per share data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Numerator:
Net income attributable to common shares	$	7,636	$	3,428	$	18,153	$	7,404
Denominator:
Basic weighted average shares		19,724		16,242		19,719		16,242
Effect of dilutive securities - options		357		81		357		—
Diluted weighted average shares		20,081		16,323		20,076		16,242
Earnings per share
Basic	$	0.39	$	0.21	$	0.92	$	0.46
Diluted	$	0.38	$	0.21	$	0.90	$	0.46

8

For the three month periods ended September 30, 2010 and 2009, options to purchase 110,000 and 25,000 shares of common stock, respectively, were excluded from the dilutive earnings per share calculation because the options’ exercise prices exceeded the average market price of the Company’s common shares during the periods. For the nine month periods ended September 30, 2010 and 2009, options to purchase 77,958 and 710,165 shares of common stock, respectively, were excluded from the dilutive earnings per share calculation because the options’ exercise price exceeded the average market price of the Company’s common shares during the period.

NOTE B: Acquisitions and Dispositions

In January 2009, the Company sold a producing property in Louisiana to an unaffiliated party for $1.6 million, recognizing a gain of $1.3 million.

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. The amount of revenue and net income from the acquisition included in the Company’s Consolidated Statement of Income for the nine month period ended September 30, 2010, was $7,233,000 and $3,916,000, respectively.

On May 29, 2009, effective May 1, 2009, the Company, through 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 “Partnership”) for the acquisition (the “Acquisition”) of certain oil and gas producing properties in the Giddings field, Grimes and Montgomery Counties, Texas (the “Interests”). Under the Purchase Agreement, the Interests were purchased for a cash purchase price of $48.7 million, net of closing adjustments for normal operations activity (the “Purchase Price”). In addition, the Company also acquired rights to certain post closing severance tax refunds which amounted to $2.4 million. The Acquisition increased the Company’s sharing ratio from 2% to 30% in the Partnership. Catena is the general partner in the Partnership. The Partnership distributed to Catena $987,000 of the gross proceeds from the sale. The Acquisition increased the Company’s direct working interest in the properties 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 Statement of Income for the nine months ended September 30, 2010, was $5,714,000 and $419,000, respectively.

9

The following summary presents unaudited pro forma information for the nine months ended September 30, 2009, as if the Acquisition had been consummated at January 1, 2009 (in thousands, except per share amounts):

Total revenue	$	62,264
Income before taxes		15,449
Net income		9,216
Net income per share:
Basic	$	0.57
Diluted	$	0.57
Weighted average shares:
Basic		16,242
Diluted		16,242

On August 29, 2009, the Company, through its subsidiary, Catena, received a distribution of proved undeveloped property and unproved acreage in Giddings Field from SBE Partners LP (“SBE”). The property was recorded at the estimated fair market value of $1.6 million, which exceeded its carrying value in the partnership. In conjunction with the distribution, SBE recorded a gain. The Company, which accounts for SBE as an equity method investment, included its share of the gain, $1,037,000, in the Company’s partnership income during the third quarter of 2009.

In October 2009, the Company initiated a leasing program in Williams County, North Dakota with the objective of establishing a significant operated position in the Bakken trend. In February 2010, the Company entered into agreements with two unaffiliated third parties to jointly develop the project. As part of these agreements, the Company sold working interests totaling 52.5% in approximately 32,000 acres for approximately $16 million. The agreement also provided for up to $10 million ($4.75 million net) of additional joint leasing in a contractually specified area of mutual interest (“AMI”). Cumulatively, the Company and the joint owners have acquired approximately 50,000 leasehold acres (23,750 net) in the prospect. For accounting purposes the Company uses the cost recovery method; under this method proceeds from joint owners have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties. The Company’s net investment in the prospect, after cost recoveries from its joint venture partners, as of September 30, 2010 was $1,819,000.

On July 30, 2010, effective May 1, 2010, the Company closed an acquisition of 40 producing oil and gas wells located in the Giddings field of Central Texas. The purchase price was $16,600,000 plus closing adjustments for normal operations activity. The acquisition was funded through borrowings under the Company’s credit facility. The amount of revenue and net income from the acquisition included in the Company’s Consolidated Statement of Income for the nine month period ended September 30, 2010, was $871,000 and $293,000, respectively.

Had the July 30, 2010 acquisition been consummated at January 1, 2009, total revenues and net income for the nine months ended September 30, 2010 would have been approximately $83,001,000 and $19,076,000, respectively; total revenues and net income for the nine months ended September 30, 2009 would have been approximately $62,444,000 and $8,709,000, respectively.

10

In September 2010, the Company entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford trend of Texas. As part of this agreement, the Company sold a 50% working interest in approximately 20,000 acres for $20 million. For accounting purposes, the Company uses the cost recovery method; under this method proceeds from joint owners are recorded in the balance sheet as a reduction of the carrying value of unproved properties. The purchaser also agreed to pay the drilling costs for the first six wells to be drilled in a contractually specified AMI. The agreement also provides for an additional $20 million ($10 million net) for additional leasing within the AMI. Subsequent to the initial closing, the Company and the joint owners have continued to acquire leases within the AMI pursuant to the terms of the agreements. For the three months ended September 30, 2010, the Company recognized a gain of $236,000 related to this transaction.

NOTE C: Recently Issued Accounting Pronouncements

In March 2010, the FASB amended the derivatives and hedging guidance to clarify the embedded credit derivative scope exception guidance. The amended guidance clarifies that the scope exception applies to contracts that contain an embedded credit derivative that is only in the form of subordination of one financial instrument to the other. As a result, the embedded credit derivative feature within contracts may need to be accounted for separately. The amended guidance was adopted on July 1, 2010 and did not have an effect on the Company’s consolidated financial statements.

NOTE D: Long-term debt

The Company has a $250 million credit facility with a borrowing base at September 30, 2010 of $145 million. The credit facility provides for annual interest rates at (a) LIBOR plus 2.25% to 3.00% or (b) the prime rate plus 1.25% to 2.00%, depending upon the amount borrowed. The credit facility also requires the payment of commitment fees to the lender on the unutilized commitment. The commitment rate is 0.50% per annum. The Company is also required to pay customary letter of credit fees. All of the obligations under the credit facility, and guarantees of those obligations, are secured by substantially all of the Company’s assets.

The credit facility requires the maintenance of certain financial ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at September 30, 2010.

The principal outstanding under the Company’s credit agreement was $85 million and $69 million at September 30, 2010 and December 31, 2009, respectively. The annual interest rate in effect at September 30, 2010 was 2.76% on the entire amount of outstanding principal. The remaining borrowing base capacity under the Second Amended Credit Agreement at September 30, 2010, was $60 million. The maturity date for amounts outstanding under the Seconded Amended Credit Agreement is October 16, 2012.

11

Interest expense for the three months ended September 30, 2010 and 2009 includes amortization of deferred financing costs of $265,000 and $256,000, respectively. Interest expense for the nine months ended September 30, 2010 and 2009 includes amortization of deferred financing costs of $793,000 and $520,000, respectively.

In connection with the initial borrowing from the bank under the credit facility the Company entered into an interest rate swap. The purpose was to protect the Company from undue exposure to interest rate increases. The swap agreement provided a fixed rate of 4.79% on a notional $50 million through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million swap each with a fixed rate of 4.29%. The $40 million swap is accounted for as a cash flow hedge while the $10 million swap is marked-to-market with gains and losses included in the Company’s consolidated statement of income. The fair market value and changes in that value are shown in the tables included in Note G below.

At September 30, 2010 and December 31, 2009, accumulated other comprehensive income included unrecognized losses of $51,000 net of a tax benefit of $30,000, and $772,000, net of a tax benefit of $530,000, 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. For the quarters ended September 30, 2010 and 2009, the Company recognized realized cash settlement losses of $408,000 and $411,000, respectively, related to this swap. For the nine month periods ended September 30, 2010 and 2009, the Company recognized realized cash settlement losses of $1,214,000 and $1,179,000, respectively, related to this swap. Based on the estimated fair market value of the Company’s $40 million derivative contract designated as a hedge at September 30, 2010, the Company expects to reclassify net losses of $81,000 into earnings from accumulated other comprehensive income 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.

12

On April 7, 2010, the Company granted options under the Plan to an outside director to purchase 40,000 shares of common stock. Additionally, on June 1, 2010, the Company granted options under the Plan to purchase 35,000 shares of common stock to key employees. The following is a summary of the terms of these 2010 grants by exercise price:

	Number of Shares Exercisable at:
Vesting Date	$13.79		$15.06		$15.75		$17.50		$17.75		$20.00		Total
Key Employees
August 30, 2010		2,500		—		—		—		—		—		2,500
June 1, 2011		—		1,250		3,750		—		3,750		—		8,750
June 1, 2012		—		1,250		3,750		—		3,750		—		8,750
June 1, 2013		—		—		3,750		—		3,750		—		7,500
June 1, 2014		—		—		3,750		—		3,750		—		7,500
Director
April 7, 2011		—		—		—		5,000		—		5,000		10,000
April 7, 2012		—		—		—		5,000		—		5,000		10,000
April 7, 2013		—		—		—		5,000		—		5,000		10,000
April 7, 2014		—		—		—		5,000		—		5,000		10,000
		2,500		2,500		15,000		20,000		15,000		20,000		75,000

The closing market prices of the Company’s common stock on the date of the April and June 2010 grants were: $17.27 and $13.69, respectively.

The weighted-average fair value of the options granted during the nine months ended September 30, 2010, was $8.52 per share, using the following assumptions:

	April 7, 2010 Grant			June 1, 2010 Grant
Risk-free interest rate		2.14	%		1.91	%
Dividend yield		None			None
Volatility		75	%		74	%
Weighted average expected life of options		4.00			4.57
Estimated forfeiture rate		1	%		1	%

13

A summary of the Company’s stock option activity for the nine months ended September 30, 2010 is as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Fair Value		Weighted Average Remaining Contractual Life (year)		Aggregate Intrinsic Value
Outstanding, December 31, 2009		1,540,000		$	9.40	$	3.34		8.30	$	6,828,000
Granted		75,000		$	17.66	$	8.52			$	—
Exercised		(10,500	)	$	8.79	$	3.68			$	55,000
Canceled/forfeited*		(80,000	)	$	9.25	$	4.48			$	483,000
Outstanding, September 30, 2010		1,524,500		$	9.82	$	3.54		7.61	$	9,607,000
Vested and exercisable		548,250		$	8.90	$	2.97		7.44	$	3,919,000
Vested and expected to vest		1,514,012		$	9.81	$	3.53		7.60	$	9,551,000

* 60,000 unvested options were forfeited and 20,000 vested options were exchanged for 8,054 shares of the Company’s common stock resulting in a cashless exercise of these vested options.

During the nine months ended September 30, 2010, 196,250 options vested with a weighted average exercise price of $10.15. The weighted average grant date fair value of these options was $4.45 per option. At September 30, 2010, there were 976,250 unvested options with a weighted average remaining amortization period of 2.34 years.

The Company recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. For the quarters ended September 30, 2010 and 2009 the Company recognized compensation expense of $299,000 and $403,000, respectively, related to these options. For the nine month periods ended September 30, 2010 and 2009, the Company recognized compensation expense of $793,000 and $1,064,000, respectively, related to these options. As of September 30, 2010, the future pre-tax expense of non-vested stock options is $2,555,000 to be recognized through the second quarter of 2014.

The Company has 613,336 warrants to purchase common stock outstanding at September 30, 2010. The warrants, which were acquired by non-affiliated accredited investors as part of the June 5, 2008 private placement offering, have an exercise price of $32.43 and have a remaining life of 2 years and 8 months.

NOTE F: Income Taxes

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

Uncertain Tax Positions

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

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At September 30, 2010, the Company did not have any uncertain tax positions that would require recognition. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.

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

It is also the Company’s practice to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statements of Income. As of September 30, 2010, the Company did not have any accrued interest or penalties associated with any unrecognized tax liabilities. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statutes of limitations prior to September 30, 2011.

NOTE G: Derivative Financial Instruments

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

At September 30, 2010, accumulated other comprehensive income (loss) consisted of unrecognized gains of $2,092,000, net of taxes of $1,260,000, 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. At December 31, 2009, accumulated other comprehensive income (loss) consisted of unrecognized losses of $2,516,000, net of taxes of $1,727,000. For the three and nine months ended September 30, 2010, the Company recognized net realized cash settlement gains on commodity derivatives of $1,959,000 and $3,193,000, respectively. For the three and nine months ended September 30, 2009, the Company recognized realized cash settlement gains of $2,540,000 and $8,072,000, respectively. Additionally, for the three and nine months ended September 30, 2009, the Company reclassified losses from accumulated other comprehensive income to oil and gas revenues related to a 2009 gas swap contract that was canceled during 2008 of $120,000 and $363,000, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at September 30, 2010, the Company expects to reclassify net gains of $3,369,000 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

During the first quarter of 2010 the Company entered into one new crude oil swap contract. The contract has a term of February 2010 to December 2011 and provides for 10,000 Bbls per month during 2010 and 7,000 Bbls per month during 2011. The swap has fixed prices for 2010 and 2011 of $85.32 and $88.45, respectively.

During the third quarter of 2010, the Company entered into an additional crude oil swap contract. The contract has a term of September 2010 to December 2012 and provides for 10,000 Bbls per month. The swap has a fixed price of $85.05 from September 2010 to December 2011 and a fixed price of $86.85 during 2012.

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Subsequent to the end of the quarter, in October 2010, the Company entered into a crude oil swap contract. The contract has a term of January 2011 to December 2012 and provides for 5,000 Bbls per month during 2011 and 10,000 Bbls per month during 2012. The swap has a fixed price of $85.16 during 2011 and $87.22 during 2012.

At September 30, 2010, 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:
2010		80,500			$	74.710
2010		30,000			$	85.320
2010		30,000			$	85.050
2011		282,000			$	74.370
2011		84,000			$	88.450
2011		120,000			$	85.050
2012		120,000			$	86.850
Natural Gas Contracts (Mmbtu)
Swap contracts
2010		360,000			$	5.155
2010		120,000			$	5.195
2010		120,000			$	6.065
2011		210,000			$	6.065
2011		630,000			$	6.450
2012		150,000			$	6.450
2012		450,000			$	6.415
Costless collar contracts:
2010		321,750	$	7.00	$	9.90
2011		1,079,000	$	7.00	$	9.20

The Company also holds two interest rate swaps, one of which is designated as a cash flow hedge, as discussed in Note D above.

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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):

	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
Derivatives designated as ASC 815 hedges:	Balance Sheet Location	Sept. 30, 2010		Dec. 31, 2009		Balance Sheet Location	Sept. 30, 2010			Dec. 31, 2009
Commodity contracts	Current derivative financial instruments asset	$	5,988	$	764	Current derivative financial instruments liability	$	(2,620	)	$	(3,167	)
Commodity contracts	Long-term derivative financial instruments asset		1,885		1,360	Long-term derivative financial instruments liability		(962	)		(3,233	)
Interest rate swap contract	Current derivative financial instruments asset		—		—	Current derivative financial instruments liability		(81	)		(1,302	)
		$	7,873	$	2,124		$	(3,663	)	$	(7,702	)
	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
Derivatives not designated as ASC 815 hedges:	Balance Sheet Location	Sept. 30, 2010		Dec. 31, 2009		Balance Sheet Location	Sept. 30, 2010			Dec. 31, 2009
Interest rate swap contract	Current derivative financial instruments asset	$	—	$	—	Current derivative financial instruments liability	$	(20	)	$	(325	)
		$	—	$	—		$	(20	)	$	(325	)

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Commodity derivative contracts – The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the three months ended September 30, 2010 and 2009 (in thousands):

	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)						Location of Gain or (Loss) Reclassified from	Amount of Gain or (Loss) Reclassified from OCI into Income  (Effective Portion)
Derivatives designated as ASC 815 hedges:	Sept. 30, 2010			Sept. 30, 2009			OCI into Income (Effective Portion)	Sept. 30, 2010			Sept. 30, 2009
Commodity contracts	$	336		$	777		Oil and gas revenues	$	1,959		$	2,420
Interest rate swap contract		(12	)		(272	)	Interest expense		(408	)		(411	)
	$	324		$	505			$	1,551		$	2,009

	Location of (Gain) or Loss	Amount of (Gain) or Loss Recognized in Income  on Derivative (Ineffective Portion)
Derivatives in ASC 815 Cash Flow Hedging Relationships:	Recognized in Income on Derivative (Ineffective Portion)	Sept. 30, 2010			Sept. 30, 2009
Commodity contracts	Hedge ineffectiveness	$	(658	)	$	111
	Location of (Gain) or Loss Recognized in Income on Derivative	Amount of (Gain) or Loss Recognized in Income on Derivative
Derivatives not designated as ASC 815 hedges:		Sept. 30, 2010			Sept. 30, 2009
Realized cash settlements on interest rate swap	(Gain)/loss on derivative contracts	$	102		$	117
Unrealized (gains) on interest rate swap	(Gain)/loss on derivative contracts		(100	)		(34	)
		$	2		$	83

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The following table summarizes the effects of commodity derivative instruments on the consolidated statements of income for the nine months ended September 30, 2010 and 2009 (in thousands):

	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)					Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
Derivatives designated as ASC 815 hedges:
	Sept. 30, 2010		Sept. 30, 2009				Sept. 30, 2010			Sept. 30, 2009
Commodity contracts	$	10,788	$	(7,256	)	Oil and gas revenues	$	3,193		$	7,709
Interest rate swap contract		7		(566	)	Interest expense		(1,214	)		(1,179	)
	$	10,795	$	(7,822	)		$	1,979		$	6,530

	Location of (Gain) or Loss	Amount of (Gain) or  Loss Recognized in Income on Derivative (Ineffective Portion)
Derivatives in ASC 815 Cash Flow Hedging Relationships:	Recognized in Income on Derivative (Ineffective Portion)	Sept. 30, 2010			Sept. 30, 2009
Commodity contracts	Hedge ineffectiveness	$	(974	)	$	186
	Location of (Gain) or Loss Recognized in Income on Derivative	Amount of (Gain) or Loss Recognized in Income on Derivative
Derivatives not designated as ASC 815 hedges:		Sept. 30, 2010			Sept. 30, 2009
Realized cash settlements on interest rate swap	(Gain)/loss on derivative contracts	$	303		$	294
Unrealized (gains) on interest rate swap	(Gain)/loss on derivative contracts		(305	)		(153	)
		$	(2	)	$	141

Contingent features in derivative instruments – None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s derivative contracts are high credit quality financial institutions.

NOTE H: Fair Value Disclosures

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

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

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

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

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

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of the input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

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

Long-term Debt – The Company’s long-term debt obligation bears interest at floating market rates, so carrying amounts and fair values are approximately equal.

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

The table below presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2010 and December 31, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

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Fair Value of Financial Assets and Liabilities - September 30, 2010

(in thousands)

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balances as of September 30, 2010
Current portion of derivative financial instrument asset(1)		—	$	5,988			—	$	5,988
Long-term portion of derivative financial instrument asset(1)		—		1,885			—		1,885
Current portion of derivative financial instrument liability(2)		—		(2,721	)		—		(2,721	)
Long-term portion of derivative financial instrument liability(1)		—		(962	)		—		(962	)

(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 ($81,000), a $10 million interest rate swap accounted for as a trading security ($20,000) and commodity derivatives accounted for as cash flow hedges ($2,620,000).

Fair Value of Financial Assets and Liabilities - December 31, 2009

(in thousands)

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balances as of December 31, 2009
Current portion of derivative financial instrument asset(1)		—	$	764			—	$	764
Long-term portion of derivative financial instrument asset(1)		—		1,360			—		1,360
Current portion of derivative financial instrument liability(2)		—		(4,794	)		—		(4,794	)
Long-term portion of derivative financial instrument liability(1)		—		(3,233	)		—		(3,233	)

(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 ($1,302,000), a $10 million interest rate swap accounted for as a trading security ($325,000) and commodity derivatives accounted for as cash flow hedges ($3,167,000).

At September 30, 2010, and December 31, 2009, 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.

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Asset Impairments – The Company reviews proved oil and gas properties for impairment at least annually and when events and circumstances indicate a decline in the recoverability of the carrying value of such properties. When events and circumstances indicate a decline in the recoverability of a property, the Company estimates the future cash flows expected in connection with the property and compares such future cash flows to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include significant Level 3 assumptions associated with estimates of future oil and gas production, commodity prices based on commodity futures price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.

The Company recorded asset impairments of $2,743,000 and $128,000 on proved properties during the nine month periods ended September 30, 2010 and 2009, respectively. Impairments were included in impairment expense. The significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis are the Company’s estimate of future natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

Asset Retirement Obligations – The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s asset retirement obligation is presented in Note J.

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

NOTE I: Public Offering of Common Stock

On December 1, 2009, the Company closed a public offering of 3,450,000 shares of common stock at a public offering price of $10.20 per share. The gross proceeds to the Company of $35.2 million were reduced by underwriters’ fees and issue costs of $2.1 million.

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NOTE J: Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. The Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the nine months ended September 30, 2010, are as follows (in thousands):

Asset retirement obligation, January 1, 2010	$	6,110
Accretion expense		300
Additional liabilities incurred		351
Asset retirment obligation, September 30, 2010	$	6,761

NOTE K: Related Party Transactions

Accounts receivable at September 30, 2010, and December 31, 2009, includes $580,000 and $785,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at September 30, 2010, and December 31, 2009, also includes $122,000 and $148,000, respectively, due from OKLA Energy Partners LP. 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 September 30, 2010, and December 31, 2009, includes $2,344,000 and $7,583,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at September 30, 2010, and December 31, 2009, also includes $693,000 and $778,000, respectively, due to OKLA Energy for oil and gas revenues collected on its behalf.

Subsidiaries of the Company operate the majority of the oil and gas properties in which the two limited partnerships have an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and development expenditures on behalf of the partnerships. These revenues are paid monthly to each partnership, which in turn reimburse the Company for the partnership’s share of expenditures. The Company earned partnership management fees during the three months ended September 30, 2010 and 2009 of $124,000, and $151,000 respectively. The Company earned partnership management fees during the nine months ended September 30, 2010 and 2009, of $423,000 and $847,000, respectively

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 net purchase price of $48.7 million. As the General Partner of SBE Partners, Catena received a distribution from the partnership as a result of the sale of $987,000. This acquisition is discussed in Note B above.

NOTE L: Equity Investments

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

OKLA Energy, formed during 2008, holds direct working interests in producing oil and gas properties located throughout Oklahoma. GeoResources’ 2% general partner interest reverts to 35.66% when the limited partner realizes a contractually specified rate of return. The Company recorded losses in

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partnership income related to this investment for the three months periods ended September 30, 2010 and 2009 of $8,000 and $2,000, respectively. The Company recorded losses in partnership income related to this investment for the nine month periods ended September 30, 2010 and 2009 of $18,000 and $13,000, respectively.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings Field in Texas. Previously, GeoResources held a 2% general partner interest which increased after reaching a cumulative payout. As result of the sale of certain properties and subsequent distribution of proceeds by the Partnership, cumulative payout was achieved and the Company’s general partner interest increased to 30%. For further information about the sale see Note B above. The Company recorded partnership income related to this investment for each of the three month periods ended September 30, 2010 and 2009 of $437,000 and $2,376,000, respectively. The Company recorded partnership income related to this investment for the nine month periods ended September 30, 2010 and 2009 of $1,789,000 and $3,847,000, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at September 30, 2010 and December 31, 2009, was $760,000 and $846,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at September 30, 2010 and December 31, 2009 was $1,623,000 and $2,686,000, respectively.

The following is a summary of selected financial information of SBE Partners, LP for the nine months ended September 30, 2010 and 2009 (in thousands):

	Nine Months Ended September 30,
	2010		2009
Summary of Partnership Operations:
Revenues	$	14,939	$	46,797
Income from continuing operations	$	5,147	$	25,293
Net income	$	5,147	$	25,293

NOTE M: Subsequent Events

On October 5, 2010, the Company collected $20,000,000 from the partial sale of unproved properties that at September 30, 2010, was included in receivables.

On October 5, 2010, the Company made a $20,000,000 principal payment on its credit facility. The balance on the Second Amended Credit Agreement after this payment is $65,000,000. The remaining borrowing base capacity under the Second Amended Credit Agreement subsequent to the payment is $80,000,000.

The borrowing base under our Second Amended Credit Agreement is subject to redetermination on May 1 and November 1 of each year. On November 4, 2010, the borrowing base of $145 million was reaffirmed.

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

The following is Management’s Discussion and Analysis of significant factors that have affected certain aspects of our financial position and operating results during the periods included in the accompanying unaudited consolidated financial statements. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K and 10-K/A for the year ended December 31, 2009.

Forward-Looking Information

Certain of the statements in all parts of this document contain “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,” “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 and 10-K/A for the year ended December 31, 2009. 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 of properties, development drilling and exploration activities. As further discussed herein, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to compete effectively for capital, 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.

By design, our business strategy includes multiple basins with geological and geographic diversity. We focus on reducing or maintaining low finding and development, operating and administrative costs on a per unit basis. Also, we have attempted to mitigate downward price volatility by the use of commodity price hedging. Historically the price environment for oil and natural gas has been volatile and management cannot predict that current prices will be available during the life of our current business plan. Following is a brief outline of our current plans:

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

• Continue to expand our acreage positions and drilling inventory;

• Solicit industry or financial partners, on a promoted basis, in order to control the development of large acreage positions, reduce our average cost, increase our return potential and generate operating income;

• Implement re-engineering and development programs within existing fields;

• Selectively divest assets to high-grade our property portfolio;

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While the impact and success of our plans cannot be predicted, 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 consider corporate acquisitions or mergers that will create opportunities for delivering increased shareholder returns to our shareholders by lowering cost structures and more effectively exploiting assets of the combined companies.

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

During 2009 and 2010, we conducted a leasing program in Williams County, North Dakota, with the objective of establishing a significant operated position. To develop the acreage position we entered into a joint venture with two industry partners. In the joint venture we are the operator and hold a 47.5% working interest. We initiated drilling the first well in the prospect on September 25, 2010. As of September 30, 2010, we had acquired approximately 50,000 (23,750 net) leasehold acres.

During 2010, we assembled approximately 23,000 (11,500 net) leasehold acres in the Eagle Ford Trend of South Texas. We hold a 50% working interest and will serve as operator and an industry partner holds the remaining 50%. Pursuant to agreements with our partner, we will continue to acquire acreage within an Area of Mutual Interest (“AMI”), which covers approximately 140,000 acres. We intend to begin drilling on this acreage as soon as is reasonably possible, perhaps by the end of 2010.

In July 2010, we closed an acquisition of 36 operated and 3 non-operated producing oil and gas wells in the Giddings field of Central Texas. The acquisition included approximately 9,700 net acres, which are held by production and prospective in currently productive and deeper formations. The purchase price was $16.6 million plus closing adjustments for normal operations activity. We funded the acquisition through borrowings under our credit facility.

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Results of Operations

Three months ended September 30, 2010, compared to three months ended September 30, 2009

The Company recorded net income of $7,636,000 for the three months ended September 30, 2010 compared to net income of $3,428,000 for the same period in 2009. This $4,208,000 increase resulted primarily from the following factors:

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

Oil and gas sales	$	5,632
Lease operating expenses		(751	)
Production taxes		(320	)
Exploration expense		457
Re-engineering and workovers		(120	)
General and administrative expenses (“G&A”)		(72	)
Depletion, depreciation and amortization expense (“DD&A”)		106
Net interest income (expense)		189
Hedge ineffectiveness		769
Gain (loss) on derivative contracts		81
Gain (loss) on sale of proeprty		186
Other income - net		(1,868	)
Income before income taxes		4,289
Provision for income taxes		(81	)
Increase in net income	$	4,208

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $5,632,000, or 28%. Increases in commodity prices accounted for $3,893,000 of the increase and increased oil production, net of decreased gas production, accounted for the remaining $1,739,000. Increased oil production was attributable primarily to new wells drilled during 2009 and 2010, as well as recent acquisitions, partially offset by normal production declines on previously existing wells. Decreased gas production was attributable primarily to the suspension of drilling of gas wells in the Giddings field due to low natural gas prices and normal production declines. Price and production comparisons are set forth in the following table.

	Percent increase (decrease)			Three Months Ended September 30,
				2010		2009
Oil Production (MBbls)		30	%		276		212
Gas Production (MMcf)		-36	%		1,076		1,678
Barrel of Oil Equivalent (MBOE)		-8	%		455		492
Average Price Oil before Hedge Settlements (per Bbl)		13	%	$	69.53	$	61.65
Average Price Oil after Hedge Settlements (per Bbl)		11	%	$	70.43	$	63.55
Average Price Gas before Hedge Settlements (per Mcf)		55	%	$	4.15	$	2.67
Average Price Gas after Hedge Settlements (per Mcf)		48	%	$	5.74	$	3.87

Lease Operating Expenses. Lease operating expenses (“LOE”) increased from $4,395,000 in the third quarter of 2009 to $5,146,000 for the same period in 2010, an increase of $751,000 or 17%. Our lease operating expenses have increased due to industry wide increases in costs and because oil operations have become a greater part of our overall production.

27

Re-engineering and workovers.Re-engineering and workover costs increased by $120,000, from $761,000 to $881,000. Projects occur in different fields and at different times due to operational matters and therefore when comparing quarterly expenditures, this variance is due to the timing of initiation and the size of individual projects.

Production Taxes. Production taxes increased by $320,000 or 27%, consistent with the increase in oil and gas revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the quarters ended September 30, 2010 and 2009 were 6.43% and 6.83%, respectively, of oil and gas sales before the effects of hedging. The 2010 rate decrease from 2009 was due to the approval of severance tax exemptions on wells in one of our key fields.

Exploration Costs. Our exploration costs were $163,000 for the third quarter of 2010 and $620,000 for the third quarter of 2009. The costs during 2010 were primarily residual costs on an exploratory well deemed to be a dry hole prior to December 31, 2009. The costs incurred during 2009 were primarily geological and geophysical costs.

General and Administrative Expenses. G&A increased by $72,000 due primarily to increases in personnel costs. As our business has expanded we have also expanded our staff and reduced or contained costs in other areas. The total non-cash charges related to stock-based compensation included in G&A expense for the three month periods ended September 30, 2010 and 2009 were $299,000 and $403,000, respectively.

Depreciation, Depletion and Amortization. DD&A expense decreased by $106,000, or 1.7%. DD&A on oil and gas properties is computed on the units-of-production method, with production volumes as the numerator and estimated proved reserve volumes as the denominator. On a unit of production basis, DD&A per BOE increased from $12.83 in 2009 to $13.63 in 2010, increase of 6%.

Interest Income and Expense. Interest expense decreased by $195,000 due to lower average debt levels in the third quarter of 2010 compared to the same period in 2009. For the three months ended September 30, 2010, average outstanding debt was $79,956,000 compared to $101,489,000 for the same period in 2009. Interest income decreased by $6,000 in the third quarter of 2010 compared to the same period of 2009.

Hedge Ineffectiveness. In the third quarter of 2010 the gain from hedge ineffectiveness was $658,000 compared to a loss of $111,000 for the same period in 2009. During the third quarter of 2010, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a gain.

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 swap and the $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 third quarter of 2010, we recognized cash settlement losses on the $10 million swap of $102,000, offset by mark-to-market gains of $100,000. In the third quarter of 2009, we recognized cash settlement losses on the $10 million swap of $117,000, offset by mark-to-market gains of $34,000.

Other Income. Other income decreased by $1,868,000 in the third quarter of 2010 compared to the same period in 2009 due primarily to a decrease in partnership income and partnership management fees. During the third quarter of 2009 we recorded partnership income of $2,374,000 versus income of $429,000 during 2010. The 2009 income included our share of gains associated with the sale of properties by the partnership. Also, as a result of this sale, our interest in SBE Partners, LP increased from 2% to 30% in the second quarter of 2009, as a result of the achievement of limited partner payout prescribed under the reversionary provisions of the partnership agreement. While we expect partnership income to continue to be significant due to our increased interest in SBE Partners we do not expect the partnership to record

28

significant gains similar to those in 2009 on property sales in the future. Since the partnership, subsequent to the sale, held a smaller interest in its properties our partnership management fee decreased by $27,000. These decreases were partially offset by increases in property operating income of $100,000 and miscellaneous income increased by $4,000.

Income Tax Expense. Income tax expense for the third quarter of 2010 was $2,621,000 compared to $2,540,000 for the same period in 2009. Our income tax expense increased due to higher pre-tax earnings, offset by a lower rate. Our effective tax rates during the third quarter of 2010 and 2009 were approximately 26% and 43%, respectively. The lower rate for 2010 is attributable to statutory deductions for excess depletion and domestic production activities, both of which represent permanent differences between financial statement income and taxable income.

Nine months ended September 30, 2010, compared to nine months ended September 30, 2009

The Company recorded net income of $18,153,000 for the nine months ended September 30, 2010 compared to net income of $7,404,000 for the same period in 2009. This $10,749,000 increase resulted primarily from the following factors:

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

Oil and gas sales	$	25,575
Lease operating expenses		(2,161	)
Production taxes		(1,682	)
Exploration expense		222
Re-engineering and workovers		668
General and administrative expenses (“G&A”)		95
Depletion, depreciation and amortization expense (“DD&A”)		(3,014	)
Impairment expense		(2,615	)
Net interest income (expense)		(406	)
Hedge ineffectiveness		1,160
Gain (loss) on derivative contracts		143
Gain (loss) on sale of proeprty		(1,157	)
Other income - net		(1,912	)
Income before income taxes		14,916
Provision for income taxes		(4,167	)
Increase in net income	$	10,749

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Oil and gas sales increased $25,575,000, or 52%. Increased commodity prices accounted for $14,088,000 of the increase and increased production volumes accounted for the remaining $11,487,000. Increased oil production was attributable primarily to new wells drilled during 2009 and 2010, as well as recent acquisitions, partially offset by normal production declines on previously existing wells. Increased gas production was attributable primarily to property interests acquired in the second quarter of 2009 from SBE Partners, LP, as well as to the drilling of new gas wells in 2009, partially offset by normal production declines on previously existing wells. Properties acquired from SBE Partners, LP accounted for gas production of 1,372,000 Mcf during the nine months ended September 30, 2010 versus 965,000 Mcf during the nine months ended September 30, 2009. Price and production comparisons are set forth in the following table.

29

	Percent increase (decrease)			Nine Months Ended September 30,
				2010		2009
Oil Production (MBbls)		30	%		780		601
Gas Production (MMcf)		7	%		3,656		3,430
Barrel of Oil Equivalent (MBOE)		18	%		1,389		1,173
Average Price Oil before Hedge Settlements (per Bbl)		40	%	$	71.78	$	51.45
Average Price Oil after Hedge Settlements (per Bbl)		19	%	$	70.51	$	59.23
Average Price Gas before Hedge Settlements (per Mcf)		39	%	$	4.25	$	3.06
Average Price Gas after Hedge Settlements (per Mcf)		36	%	$	5.39	$	3.95

Lease Operating Expenses. Lease operating expenses increased from approximately $13,202,000 during the nine months ended September 30, 2009 to $15,363,000 for the same period in 2010, an increase of $2,161,000 or 16%. Our lease operating expenditures have increased due primarily to increased production; on a unit-of-production basis, LOE costs have actually decreased by $.19 per BOE, or 1.7%.

Re-engineering and Workover. Re-engineering and workover costs decreased by $668,000 from $2,057,000 to $1,389,000 primarily due to a major re-engineering and workover program concluded in 2009.

Production Taxes. Production taxes increased by $1,682,000 or 53%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the first nine months of 2010 and 2009 were 6.8% and 7.6%, respectively, of oil and gas sales before the effects of hedging. The 2010 rate decrease from 2009 was due to the approval of severance tax exemptions on wells in several of our key fields.

Exploration and Impairment Costs. Our exploration costs were $766,000 for the nine months ended September 30, 2010 and $988,000 for the same period during 2009. We incurred residual costs of $192,000 during 2010 on an exploratory well deemed to be a dry hole prior to December 31, 2009. The remaining $574,000 were geological and geophysical costs. The costs incurred during 2009 were primarily geological and geophysical costs. We recorded non-cash impairments charges of $2,743,000 and $128,000 in 2010 and 2009, respectively, due to the write-down of proved properties. The book value of these properties exceeded our estimate of future undiscounted cash flows which was a direct result of the decline in our estimated of future natural gas prices.

General and Administrative Expenses. G&A decreased $95,000 in the first nine months of 2010 compared to the same period in 2009 due to lower non-cash stock based compensation expense. Included in G&A expense for the nine months ended September 30, 2010 and 2009 are non-cash charges related to our stock-based compensation of $793,000 and $1,064,000, respectively. Although personnel costs have continued to increase, we have managed to contain, or reduce, G&A costs in other areas.

Depreciation, Depletion and Amortization. DD&A expense increased by $3,014,000 or 19% due to higher capitalized costs and higher production. Capitalized costs increased due to acquisitions of additional property interests in both the Giddings field and Bakken Shale and continued successful drilling in the Bakken. On a units-of- production basis, DD&A per BOE increased slightly from $13.22 in 2009 to $13.34 in 2010.

Interest Income and Expense. Interest expense increased by $400,000 due to higher average debt levels and higher amortization of debt acquisition costs in the first nine months of 2010 compared to the same period in 2009. During the first nine months of 2010, our average outstanding debt was approximately of $72,692,000 compared to $68,062,000 for the same period in 2009. Interest income decreased by $6,000 in the first nine months of 2010 compared to the same period of 2009.

30

Hedge Ineffectiveness. For the first nine months of 2010 the gain from hedge ineffectiveness was $974,000, compared to a loss of $186,000 for the same period in 2009. During the nine months ended September 30, 2010, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a gain. During the nine months ended September 30, 2009, our derivatives accounted for as cash flow hedges decreased in value; therefore, the change in the ineffective portion of these derivatives was a loss.

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 nine months ended September 30, 2010, we recognized cash settlement losses on the $10 million swap of $303,000; these losses were offset by mark-to-market gains of $305,000. For the first nine months of 2009, we recognized cash settlement losses on the $10 million swap of $294,000; these losses were offset by mark-to-market gains of $153,000.

Other Income. Other income decreased by $1,912,000 in the first nine months of 2010 compared to the same period in 2009 due to a decrease in partnership income and partnership management fees, offset by an increase in severance tax refunds. During the first nine months of 2009 we recorded partnership income of $3,834,000; during the first nine months of 2010 partnership income decreased by $2,063,000 to $1,771,000. Partnership income in the first nine 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 as well as our share of the gains associated with the sale of properties by the partnership. These decreases were offset by our increased share of revenues and expenses from the partnership. As a result of the sales our interest in SBE Partners, LP increased from 2% to 30% during the second quarter of 2009. While we expect partnership income to continue to be significant due to our increased interest in SBE Partners we do not expect the partnership to record significant gains similar to those in 2009 on property sales in the future. Since the partnership, subsequent to the sale, held a smaller interest in its properties our partnership management fee decreased $424,000. Also contributing to the decrease in other income, property operating income decreased by $30,000 and other income decreased by $27,000 from the nine months ended September 30, 2009, to the nine months ended September 30, 2010. During the first nine months of 2009 we accrued for refunds of severance taxes on qualifying high cost gas wells in Texas of $599,000. During the first nine months of 2010 we recorded severance tax refunds of $1,231,000 related to both high cost gas wells in Texas and certain qualifying oil wells in Louisiana. Also, in the first nine months of 2009 we had a net gain on sales of properties and other assets of $1,545,000 versus $388,000 in the same period of 2010.

Income Tax Expense. Income tax expense for the first nine months of 2010 was $9,283,000 compared to $5,116,000 for the same period in 2009. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the first nine months of 2010 and 2009 was approximately 34% and 41%, respectively. The lower rate for 2010 is attributable to statutory deductions for excess depletion and domestic production activities, both of which represent permanent differences between financial statement income and taxable income.

Impact of Changing Prices and Costs

History has demonstrated that commodity prices can be extremely volatile and unpredictable. Consequently, our revenue and the carrying value of our oil and gas properties are subject to significant change due to changes in oil and gas prices. Oil prices decreased appreciably during the last half of 2008 and into 2009 but recovered somewhat during the last half of 2009 and the first nine months of 2010. The average realized oil price of $70.51 per Bbl, net of hedges, for the nine months ended September 30, 2010, was 19% higher than for the comparable period in 2009. The average realized natural gas price of $5.39 per Mcf, net of hedges, for the nine months ended September 30, 2010, was 36% higher than for the comparable period in 2009. The average realized price for the first nine months of 2010 included the effects of our hedges. Should significant price decreases occur or should prices fail to remain at levels

31

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. Fluctuating gas prices in 2009 caused us to suspend our drilling activities directed in the Giddings field and then restart them resulting in a decline of 15% in our gas production from the fourth quarter 2009 to the first quarter 2010. We recently announced our suspension of those activities again in the current low gas price environment and will restart that drilling activity when natural gas prices recover. We expect a similar level of decline in our natural gas production as we experienced in the first quarter of 2010.

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. With the passage of the Dodd-Frank Act in July 2010 we are not able to determine whether this legislation will adversely impact our hedging strategy as substantive regulation has not yet been proposed and adopted.

Administrative and Operating Costs

We continue to focus on cost-containment efforts regarding lower per-unit administrative and operating costs. However, we must continue to attract and retain competent management, technical and administrative personnel in pursuing our business strategy and fulfilling our contractual obligations.

Liquidity and Capital Resources

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

Credit Facility

As of September 30, 2010, our borrowing base under our credit facility with Wells Fargo Bank was $145 million and our outstanding balance was $85 million pursuant to the Second Amended and Restated Credit Agreement dated July 13, 2009. The borrowing base is subject to redetermination on May 1 and November 1 of each year. On November 4, 2010, our borrowing base of $145 million was reaffirmed. On October 5, 2010, we made a principal payment of $20 million which reduced our outstanding balance under the facility to $65 million.

32

Cash Flows from Operating Activities

For the nine months ended September 30, 2010, our net cash provided by operating activities was $48.1 million, versus $12.9 million in the same period in 2009. 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, assuming commodity prices do not decrease substantially.

Cash Flows from Investing Activities

Cash applied to capital expenditures for the nine months ended September 30, 2010 and 2009, was $65.3 million and $81.6 million, respectively. In addition, cash generated from the sale of properties for the nine months ended September 30, 2010 and 2009 was $540,000 and $2,660,000, respectively. During the first nine months of 2010 capital expenditures of $16 million were financed with borrowings from our credit facility and the remainder with working capital. We expect to spend approximately $15 million to $18 million during the remainder of 2010 and approximately $88 million in 2011.

Capital Spending

We have recently initiated drilling on our operated Bakken acreage in the Williston Basin and, our Bakken non-operated holdings continue to be actively developed. In addition, we are currently planning to spud our first Eagle Ford well late in 2010 or early in the first quarter of 2011. Those projects represent the bulk of our planned expenditures for 2011, as shown in the table below.

We are constantly working to expand our acreage and drilling inventory and therefore actual expenditures could shift toward new opportunities. In addition, factors such as commodity prices and well performance could result in significant changes to our capital spending. Also, the actual timing and amount of expenditures could differ significantly, due to cost increases, demand and supply of services, required regulatory approvals and other factors, all beyond our control.

While industry circumstances may require us to make adjustments, it is our current intent to continue and possibly accelerate our Bakken and Eagle Ford drilling depending on drilling results. To a lesser extent, we intend to drill certain locations in the Austin Chalk and prospects in the Gulf Coast, but those projects could be deferred in favor of increased activity in other areas or so long as low gas prices prevail. Our current estimate of our capital spending for 2011 is as follows.

	($ in Millions)		Percent of Budget
Bakken - operated(1)	$	24.6		28.0	%
Bakken - non-operated(2)	$	21.0		23.9	%
Eagle Ford(3)	$	7.8		8.9	%
Giddings(4)	$	8.3		9.4	%
Louisiana(5)	$	7.8		8.9	%
Acreage and seismic(6)	$	12.0		13.6	%
Other drilling and operations	$	6.5		7.3	%
Total	$	88.0		100.0	%

Notes:

(1) Represents approximately $21.0 million allocated to our operated Bakken drilling project in Williams County, ND. The remainder represents Bakken spacing units we control in eastern Montana. In Williams County, ND, we expect to complete drilling our initial three wells in the first quarter of 2011. We are further planning to resume drilling in the spring or early summer after a reasonable time to complete the wells and evaluate performance. Depending on drilling results, our current plan calls for adding a second rig in the summer.

33

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

(3) Represents our net estimated cost of nine planned wells where we have a 50% working interest.

(4) Three wells in the Giddings field, Texas.

(5) Four wells in the St. Martinville field and one well at Quarantine Bay, Louisiana.

(6) Includes approximately $10.0 million allocated to acreage and $2.0 million allocated to seismic. We have only provided for acreage expenditures where we are the operator and have contractual agreements to pursue additional acreage within certain areas of mutual interest with joint owners. We intend to continue expanding our acreage positions in our focus areas and therefore, with success, our capital spending could exceed the amounts shown above. These potential expenditures cannot be estimated with any precision and, accordingly, are not reflected in the above estimates.

We believe a benefit of our property portfolio is that the vast majority of our acreage is held-by-production and remaining lease terms sufficient to allow for orderly and cost effective development of our acreage. Accordingly, at present we do not believe we are subject to any material lease expirations or significant future incremental carrying costs. In the opinion of management, at present, we have sufficient cash flows and liquidity to fund our projected capital spending and maintain all material mineral leases.

34

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The following is a list of contracts outstanding at September 30, 2010:

Transaction Date

Transaction Type

Beginning

Ending

Price Per Unit

Remaining Annual Volumes

Fair Value Outstanding as of Sept. 30, 2010

(in thousands)

Natural Gas

October-07

Collar

01/01/10

12/31/10

$7.00 - $9.90

321,750 Mmbtu

$

1,002

October-07

Collar

01/01/11

12/31/11

$7.00 - $9.20

1,079,000 Mmbtu

2,793

June-09

Swap

01/01/10

12/31/10

$5.155

360,000 Mmbtu

458

June-09

Swap

01/01/10

12/31/10

$5.195

120,000 Mmbtu

157

December-09

Swap

04/01/10

03/31/11

$6.065

330,000 Mmbtu

677

December-09

Swap

04/01/11

03/31/12

$6.450

780,000 Mmbtu

1,504

December-09

Swap

04/01/12

12/31/12

$6.415

450,000 Mmbtu

654

7,245

Crude Oil

October-07

Swap

01/01/10

12/31/10

$74.71

80,500 Bbls

(479

)

October-07

Swap

01/01/11

12/31/11

$74.37

282,000 Bbls

(2,981

)

January-10

Swap

02/01/10

12/31/10

$85.32

30,000 Bbls

139

January-10

Swap

01/01/11

12/31/11

$88.45

84,000 Bbls

276

August-10

Swap

09/01/10

12/31/11

$85.05

150,000 Bbls

180

August-10

Swap

01/01/12

12/31/12

$86.85

120,000 Bbls

(89

)

(2,954

)

Interest Rate

Oct-07/Dec-09

Swap

10/10/07

10/16/10

4.29375%

$40 Million Notional

30-day LIBOR

(81

)

Oct-07/Dec-09

Swap

12/16/08

10/16/10

4.29375%

$10 Million Notional

30-day LIBOR

(20

)

(101

)

$

4,190

We are exposed to financial risk from changes in interest rates. The long-term debt on our balance sheet of $85,000,000 is the outstanding principal amount under our Second Amended and Restated Credit Agreement which matures in October 2012. Although the agreement provides for a variable interest rate, we fixed the rate for $40 million of that balance until October 2010 through an interest rate swap that we did not renew. In the event interest rates rise significantly, our interest expense will increase significantly as well, thereby adversely affecting our profitability.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our Chief Executive Officer, Chief Financial Officer and other members of management evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of September 30, 2010. 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 September 30, 2010, in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive and principal financial officers to allow timely discussion regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 1- Risk Factors” in our 2009 Annual Report on Form 10-K and 10-K/A, which could materially affect our business, financial condition or future results. The risks described in our 2009 Annual Report on Forms 10-K and 10-K/A may not be the only risks facing our Company. There are no updates to our risk factors as disclosed in our Annual Report on Form 10-K and 10-K/A for the year ended December 31, 2009, except as noted below. 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.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services, especially in emerging plays such as the Bakken trend in North Dakota and the Eagle Ford trend in Texas, could adversely affect our ability to execute our exploration plans on a timely basis or within our budget.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel especially in the Bakken trend in North Dakota and the Eagle Ford trend in Texas could delay or adversely affect our exploration, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

We may experience significant delays between drilling and completion on both our operated and non-operated properties in the Bakken trend.

Industry-wide delays between drilling and completion operations in Bakken trend may continue to climb. Increased delays could delay or adversely affect our exploration, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	None
Item 3.	Defaults Upon Senior Securities	None
Item 4.	Reserved
Item 5.	Other Information	None

37

Item 6. Exhibits

See Exhibit Index following the signature page of this Quarterly Report on Form 10-Q for a list of exhibits filed or furnished with this report, which Exhibit Index is incorporated herein by reference.

38

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.

November 5, 2010

/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)

39

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended September 30, 2010.

10.46	Purchase and Sale Agreement dated June 25, 2009, by and among Hop-Mar Energy, L.P., Sydri Energy Investments I, Ltd., Snyder Energy Investments, Ltd., Woodbine Energy Partners, L.P. (Sellers) and Southern Bay Energy, LLC (Buyer).
10.47	Participation Agreement-Eagle Ford Project entered into September 29, 2010 between Southern Bay Energy, LLC, Southern Bay Operating, LLC and Ramshorn Investments, Inc.
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
32.1	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.
32.2	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.