Georesources (GEOI) 10-Q 2010 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

the Securities Exchange Act of 1934

For the Quarterly Period ended June 30, 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 registrant 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. (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 August 5, 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 June 30, 2010 and December 31, 2009.	3
	Consolidated Statements of Income for the Three and Six Months ended June 30, 2010 and 2009.	5
	Consolidated Statement of Stockholders’ Equity and Comprehensive Income for the Six Months ended June 30, 2010.	6
	Consolidated Statements of Cash Flows for the Six Months ended June 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.	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	34
Item 4.	Controls and Procedures.	35
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings.	36
Item 1A.	Risk Factors.	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	36
Item 3.	Defaults Upon Senior Securities.	36
Item 4.	Reserved.
Item 5.	Other Information.	36
Item 6.	Exhibits.	37
	Signatures.	39

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

	June 30,			December 31,
	2010			2009
	(unaudited)
ASSETS
Current assets:
Cash	$	15,899		$	12,660
Accounts receivable:
Oil and gas revenues		16,261			14,860
Joint interest billings and other		4,149			13,734
Affiliated partnerships		1,062			933
Notes receivable		120			120
Derivative financial instruments		4,703			764
Income taxes receivable		327			2,077
Prepaid expenses and other		2,659			2,297
Total current assets		45,180			47,445
Oil and gas properties, successful efforts method:
Proved properties		302,331			285,363
Unproved properties		19,314			10,281
Office and other equipment		956			828
Land		96			96
		322,697			296,568
Less accumulated depreciation, depletion and amortization		(60,495	)		(48,182	)
Net property and equipment		262,202			248,386
Equity in oil and gas limited partnerships		2,673			3,532
Derivative financial instruments		2,284			1,360
Deferred financing costs and other		3,819			3,574
	$	316,158		$	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)

	June 30,		December 31,
	2010		2009
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	5,337	$	6,452
Accounts payable to affiliated partnerships		3,389		8,361
Revenue and royalties payable		11,441		13,928
Drilling advances		53		390
Accrued expenses		1,862		1,574
Derivative financial instruments		1,522		4,794
Total current liabilities		23,604		35,499
Long-term debt		69,000		69,000
Deferred income taxes		24,522		15,778
Asset retirement obligations		6,353		6,110
Derivative financial instruments		804		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		147,552		146,966
Accumulated other comprehensive income		2,807		(3,288	)
Retained earnings		41,319		30,802
Total stockholders’ equity		191,875		174,677
	$	316,158	$	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 June 30,					Six Months Ended June 30,
	2010			2009		2010			2009
Revenue:
Oil and gas revenues	$	24,343		$	16,829	$	49,072		$	29,129
Partnership management fees		140			398		299			696
Property operating income		393			456		784			914
Gain on sale of property and equipment		—			89		145			1,488
Partnership income		488			1,455		1,342			1,460
Interest and other		1,042			634		1,340			739
Total revenue		26,406			19,861		52,982			34,426
Expenses:
Lease operating expense		5,193			4,417		10,217			8,807
Severance taxes		1,540			1,167		3,323			1,961
Re-engineering and workovers		255			315		508			1,296
Exploration expense		139			288		603			368
Impairment of oil and gas properties		2,743			128		2,743			128
General and administrative expense		2,039			1,930		3,858			4,025
Depreciation, depletion and amortization		5,962			4,725		12,313			9,193
Hedge ineffectiveness		(61	)		26		(316	)		75
(Gain) / Loss on derivative contracts		(17	)		6		(4	)		58
Interest		1,285			1,144		2,558			1,963
Total expense		19,078			14,146		35,803			27,874
Income before income taxes		7,328			5,715		17,179			6,552
Income tax expense (benefit):
Current		912			202		1,865			(532	)
Deferred		1,973			2,014		4,797			3,108
		2,885			2,216		6,662			2,576
Net income	$	4,443		$	3,499	$	10,517		$	3,976
Net income per share (basic)	$	0.23		$	0.22	$	0.53		$	0.24
Net income per share (diluted)	$	0.22		$	0.22	$	0.52		$	0.24
Weighted average shares outstanding:
Basic		19,723,916			16,241,717		19,716,722			16,241,717
Diluted		20,113,189			16,241,717		20,073,598			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

Six Months Ended June 30, 2010

(In thousands, except share data)

(unaudited)

	Common Stock			Additional Paid-in Capital		Retained Earning		Accumulated Other Comprehensive Income (Loss)			Total
	Shares	Par value
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		—		92							92
Cashless exercises	8,054		—		2							2
Comprehensive income:
Net income							10,517					10,517
Change in fair market value of hedged positions, net of taxes of $4,109									6,362			6,362
Hedging gains realized in income, net of taxes of $161									(267	)		(267	)
Total comprehensive income												16,612
Equity based compensation expense					492							492
Balance, June 30, 2010	19,723,916	$	197	$	147,552	$	41,319	$	2,807		$	191,875

The accompanying notes are an integral part of this statement.

6

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)

	Six Months Ended June 30,
	2010			2009
Cash flows from operating activities:
Net income	$	10,517		$	3,976
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		12,313			9,193
Proved property impairments		2,743			128
Gain on sale of property and equipment		(145	)		(1,488	)
Accretion of asset retirement obligations		200			177
Unrealized gain on derivative contracts		(205	)		(119	)
Amortization of loss on canceled hedge contract		—			243
Hedge ineffectiveness (gain) loss		(316	)		75
Partnership income		(1,342	)		(1,460	)
Partnership distributions		2,201			1,284
Deferred income taxes		4,797			3,108
Non-cash compensation		494			661
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		9,805			(7,070	)
(Increase) decrease in prepaid expense and other		(607	)		1,077
Decrease in accounts payable and accrued expense		(8,623	)		(5,855	)
Net cash provided by operating activities		31,832			3,930
Cash flows from investing activities:
Proceeds from sale of property and equipment		425			1,991
Additions to property and equipment, net of cost recoveries of $18,529,000 in 2010 and none in 2009		(29,110	)		(70,218	)
Net cash used in investing activities		(28,685	)		(68,227	)
Cash flows from financing activities:
Proceeds from stock options exercised		92			—
Issuance of long-term debt		—			58,000
Net cash provided by financing activities		92			58,000
Net increase (decrease) in cash and cash equivalents		3,239			(6,297	)
Cash and cash equivalents at beginning of period		12,660			13,967
Cash and cash equivalents at end of period	$	15,899		$	7,670
Supplementary information:
Interest paid	$	2,025		$	1,650
Income taxes paid	$	115		$	478

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 has 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 prior period amounts on the Company’s Consolidated Statement of Income to conform to the current period presentation of severance tax expense and interest and other income for the three and six month periods ended June 30, 2009.

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 six months ended June 30, 2010 and 2009 consist of the following (in thousands, except per share data):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Numerator:
Net income attributable to common shares	$	4,443	$	3,499	$	10,517	$	3,976
Denominator:
Basic weighted average shares		19,724		16,242		19,717		16,242
Effect of diluative securities - options		389		—		357		—
Diluted weighted average shares		20,113		16,242		20,074		16,242
Earnings per share:
Basic	$	0.23	$	0.22	$	0.53	$	0.24
Diluted	$	0.22	$	0.22	$	0.52	$	0.24

8

For the three months ended June 30, 2010 and 2009, options to purchase 95,000 and 1,137,500 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 six month period ended June 30, 2010, options to purchase 110,000 shares of common stock 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. During the six month period ended June 30, 2009, there were not any potentially dilutive securities because the average price of the Company’s common stock was less than the exercise price and associated tax benefits of all the options outstanding.

NOTE B: Acquisitions and Dispositions

Bakken Acquisitions

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 six month period ended June 30, 2010, was $2,756,000 and $1,457,000, respectively.

In October 2009, the Company initiated a leasing program in Williams County, North Dakota with the objective of establishing a significant operated position. As of July 2010, the Company has acquired approximately 50,000 net leasehold acres. The Company has entered into a joint venture with two industry partners in order to develop the acreage. In the joint venture the Company is the operator and holds a 47.5% working interest. The Company’s net investment in the prospect, after cost recoveries from its joint venture partners, as of June 30, 2010 was $489,000.

Giddings Field Acquisition

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 six months ended June 30, 2010, was $4,113,000 and $537,000, respectively.

9

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

Total revenue	$	38,628
Income before taxes		9,514
Net income		5,809
Net income per share:
Basic	$	0.36
Diluted	$	0.36
Weighted average shares:
Basic		16,242
Diluted		16,242

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.

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.

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 is effective at the beginning of the first fiscal quarter beginning after June 15, 2010, with early adoption permitted. The Company expects to adopt the amended guidance during the quarter ending September 30, 2010. The Company does not believe that the adoption of the amended guidance will have a significant effect on its consolidated financial statements.

NOTE D: Long-term debt

The Company has a $250 million credit facility with a borrowing base at June 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 June 30, 2010.

The principal outstanding under the Company’s credit agreement was $69 million at both June 30, 2010 and December 31, 2009. The annual interest rate in effect at June 30, 2010 was 2.85% on the entire amount of outstanding principal. The remaining borrowing base capacity under the Second Amended

10

Credit Agreement at June 30, 2010, was $76 million. The maturity date for amounts outstanding under the Seconded Amended Credit Agreement is October 16, 2012. In July 2010, the Company borrowed an additional $16 million bringing its outstanding balance to $85 million and remaining borrowing base capacity of $60 million.

Interest expense for the three months ended June 30, 2010 and 2009 includes amortization of deferred financing costs of $264,000 and $132,000, respectively. Interest expense for the six months ended June 30, 2010 and 2009 includes amortization of deferred financing costs of $528,000 and $264,000, 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 June 30, 2010 and December 31, 2009, accumulated other comprehensive income included unrecognized losses of $298,000 net of a tax benefit of $179,000, 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 June 30, 2010 and 2009, the Company recognized realized cash settlement losses of $404,000 and $392,000, respectively, related to this swap. For the six month periods ended June 30, 2010 and 2009, the Company recognized realized cash settlement losses of $806,000 and $768,000, 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 June 30, 2010, the Company expects to reclassify net losses of $477,000 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.

11

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 six months ended June 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	%

12

A summary of the Company’s stock option activity for the six months ended June 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		$	56,000
Canceled/forfeited*	(80,000	)	$	9.25	$	4.48		$	483,000
Outstanding, June 30, 2010	1,524,500		$	9.82	$	3.54	7.86	$	6,805,000
Vested and exercisable	545,750		$	8.88	$	2.97	7.68	$	2,864,000
Vested and expected to vest	1,511,566		$	9.81	$	3.53	7.86	$	6,756,000

* 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 six months ended June 30, 2010, 193,750 options vested with a weighted average exercise price of $10.11. The weighted average grant date fair value of these options was $4.45 per option. At June 30, 2010, there were 978,750 unvested options with a weighted average remaining amortization period of 2.53 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 June 30, 2010 and 2009 the Company recognized compensation expense of $275,000 and $396,000, respectively, related to these options. For the six month periods ended June 30, 2010 and 2009, the Company recognized compensation expense of $494,000 and $661,000, respectively, related to these options. As of June 30, 2010, the future pre-tax expense of non-vested stock options is $2,845,000 to be recognized through the second quarter of 2014.

The Company has 613,336 warrants to purchase common stock outstanding at June 30, 2010. The warrants have an exercise price of $32.43 and have a remaining life of 2 years and 11 months.

NOTE F: Income Taxes

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

Uncertain Tax Positions

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

13

At June 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 June 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 June 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 June 30, 2010, accumulated other comprehensive income (loss) consisted of unrecognized gains of $3,105,000, net of taxes of $1,871,000, representing the inception to date change in mark-to-market value of the effective portion of the Company’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 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 six months ended June 30, 2010, the Company recognized a net realized cash settlement gains on commodity derivatives of $1,130,000 and $1,234,000, respectively. For the three and six months ended June 30, 2009, the Company recognized realized cash settlement gains of $2,132,000 and $5,532,000, respectively. Additionally, for the three and six months ended June 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 $121,000 and $243,000, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at June 30, 2010, the Company expects to reclassify net gains of $3,778,000 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.

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At June 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	161,000			$	74.710
2010	60,000			$	85.320
2011	282,000			$	74.370
2011	84,000			$	88.450
Natural Gas Contracts (Mmbtu)
Swap contracts
2010	720,000			$	5.155
2010	240,000			$	5.195
2010	240,000			$	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	643,500	$	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.

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

Derivatives designated as ASC 815 hedges:	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet Location	Jun. 30, 2010		Dec. 31, 2009		Balance Sheet Location	Jun. 30, 2010			Dec. 31, 2009
Commodity contracts	Current derivative financial instruments asset	$	4,703	$	764	Current derivative financial instruments liability	$	(925	)	$	(3,167	)
Commodity contracts	Long-term derivative financial instruments asset		2,284		1,360	Long-term derivative financial instruments liability		(804	)		(3,233	)
Interest rate swap contract	Current derivative financial instruments asset		—		—	Current derivative financial instruments liability		(477	)		(1,302	)
		$	6,987	$	2,124		$	(2,206	)	$	(7,702	)

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	Asset Derivatives					Liability Derivatives
	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
Derivatives not designated as ASC 815 hedges:		Jun. 30, 2010		Dec. 31, 2009			Jun. 30, 2010			Dec. 31, 2009
Interest rate swap contract	Current derivative financial instruments asset	$	—	$	—	Current derivative financial instruments liability	$	(120	)	$	(325	)
		$	—	$	—		$	(120	)	$	(325	)

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

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivative  (Effective Portion)					Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from OCI into Income  (Effective Portion)
	Jun. 30, 2010		Jun. 30, 2009				Jun. 30, 2010			Jun. 30, 2009
Commodity contracts	$	3,984	$	(11,760	)	Oil and gas revenues	$	1,130		$	2,011
Interest rate swap contract		72		(86	)	Interest expense		(404	)		(392	)
	$	4,056	$	(11,846	)		$	726		$	1,619

Derivatives in ASC 815 Cash Flow Hedging Relationships:	Location of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)	Amount of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)
		Jun. 30, 2010			Jun. 30, 2009
Commodity contracts	Hedge ineffectiveness	$	(61	)	$	26
Derivatives not designated as ASC 815 hedges:	Location of (Gain) or Loss Recognized in Income on Derivative	Amount of (Gain) or Loss Recognized in Income on Derivative
		Jun. 30, 2010			Jun. 30, 2009
Realized cash settlements on interest rate swap	Loss on derivative contracts	$	101		$	83
Unrealized (gains) on interest rate swap	Loss on derivative contracts		(118	)		(77	)
		$	(17	)	$	6

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

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivative  (Effective Portion)					Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)	Amount of Gain or (Loss) Reclassified from OCI into Income  (Effective Portion)
	Jun. 30, 2010		Jun. 30, 2009				Jun. 30, 2010			Jun. 30, 2009
Commodity contracts	$	10,452	$	(8,033	)	Oil and gas revenues	$	1,234		$	5,289
Interest rate swap contract		19		(294	)	Interest expense		(806	)		(768	)
	$	10,471	$	(8,327	)		$	428		$	4,521

Derivatives in ASC 815 Cash Flow Hedging Relationships:	Location of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)	Amount of (Gain) or Loss Recognized in Income on Derivative (Ineffective Portion)
		Jun. 30, 2010			Jun. 30, 2009
Commodity contracts	Hedge ineffectiveness	$	(316	)	$	75
Derivatives not designated as ASC 815 hedges:	Location of (Gain) or Loss Recognized in Income on Derivative	Amount of (Gain) or Loss Recognized in Income on Derivative
		Jun. 30, 2010			Jun. 30, 2009
Realized cash settlements on interest rate swap	Loss on derivative contracts	$	201		$	177
Unrealized (gains) on interest rate swap	Loss on derivative contracts		(205	)		(119	)
		$	(4	)	$	58

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

NOTE H: Fair Value Disclosures

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

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

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

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

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

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

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

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

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

The table below presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 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 - June 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 June 30, 2010
Current portion of derivative financial instrument asset(1)	—	$	4,703		—	$	4,703
Long-term portion of derivative financial instrument asset(1)	—		2,284		—		2,284
Current portion of derivative financial instrument liability(2)	—		(1,522	)	—		(1,522	)
Long-term portion of derivative financial instrument liability(1)	—		(804	)	—		(804	)

(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 ($477,000), a $10 million interest rate swap accounted for as a trading security ($120,000) and commodity derivatives accounted for as cash flow hedges ($925,000).

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).

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At June 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.

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

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

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

NOTE I: Public Offering of Common Stock

On 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 six months ended June 30, 2010, are as follows (in thousands):

Asset retirement obligation, January 1, 2010	$	6,110
Accretion expense		200
Additional liabilities incurred		43
Asset retirment obligation, June 30, 2010	$	6,353

NOTE K: Related Party Transactions

Accounts receivable at June 30, 2010, and December 31, 2009, includes $923,000 and $785,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at June 30, 2010, and December 31, 2009, also includes $139,000 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 June 30, 2010, and December 31, 2009, includes $2,690,000 and $7,583,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at June 30, 2010, and December 31, 2009, also includes $699,000 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 June 30, 2010 and 2009 of $140,000, and $398,000 respectively. The Company earned partnership management fees during the six months ended June 30, 2010 and 2009, of $299,000 and $696,000, 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 partnership income related to this investment for the three months periods ended June 30, 2010 and 2009 of $8,000 and $3,000, respectively. The Company recorded losses in partnership income related to this investment for the six month periods ended June 30, 2010 and 2009 of $10,000 and $11,000, respectively.

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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 June 30, 2010 and 2009 of $496,000 and $1,458,000, respectively. The Company recorded partnership income related to this investment for the six month periods ended June 30, 2010 and 2009 of $1,352,000 and $1,471,000, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at June 30, 2010 and December 31, 2009, was $786,000 and $846,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at June 30, 2010 and December 31, 2009 was $1,887,000 and $2,686,000, respectively.

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

	Six Months Ended June 30,
	2010		2009
Summary of Partnership Operations:
Revenues	$	10,796	$	40,854
Income from continuing operations	$	3,656	$	26,119
Net income	$	3,656	$	26,119

NOTE M: Subsequent Events

On July 30, 2010, effective May 1, 2010, the Company closed an acquisition of certain working interests in 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. Prior to June 30, 2010, the Company paid a deposit of $830,000 with the balance of the purchase price paid in cash at closing. The acquisition was funded through borrowings under the Company’s credit facility.

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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, development and exploration activities. As further discussed herein, future growth in assets, earnings, cash flows and share values will be dependent upon our ability to effectively compete for capital, 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 and both natural gas and oil projects. We intend to acquire, discover and develop oil and natural gas reserves and achieve growth. In addition, 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;

• Solicit industry partners in acquisitions, on a promoted basis, in order to diversify, reduce average cost and generate operating fees;

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

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

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

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

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

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

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

In May 2009, we acquired producing wells and acreage in the Bakken Shale trend of the Williston Basin through an existing joint venture where we participate as a non-operator. We acquired a 15% interest in approximately 60,000 net acres, and we also acquired 15% of varying working interests in 59 producing and productive wells. Our share of producing wells and undeveloped locations added approximately 486,000 BOE of proved reserves and numerous prospective locations. Including leasehold acquisitions subsequent to May 2009, we have working interests in the joint venture ranging from 10% to 18% in approximately 106,000 net acres. The acquisition cost was approximately $10.4 million and was funded with borrowings from our senior secured revolving credit facility. As of July 2010, the joint venture was running four drilling rigs on various locations.

In May 2009, we acquired certain producing oil and gas properties in Giddings field, Texas, from an affiliated limited partnership for which we serve as general partner. Prior to the acquisition, we held direct working interests in the properties ranging from 6.5% to 7.8%. We now hold direct working interests ranging from approximately 34% to 37%. The acquired direct working interests totaled an estimated 25 Bcfe of proved reserves, 88% natural gas and 73% developed, with daily production, at the time of the transaction, totaling 10,625 Mcf and 85 Bbls of associated liquids. In addition, we increased our partnership interest from 2% to 30%, amounting to an estimated 13.2 Bcfe net to our interest in the partnership after the transaction. We remain the general partner of the partnership and operator of the properties. The acquisition also provided additional development opportunities and exposure to the potential upside associated with the Yegua, Georgetown and Eagle Ford Shale formations. The interests were purchased for a net cash purchase price of $47.7 million. In addition, we acquired rights to certain post closing severance tax refunds which amounted to $2.4 million. We funded the acquisition with borrowings from our senior secured revolving credit facility.

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In August 2009, we received a distribution of proved undeveloped property and unproved acreage in the Giddings field from an affiliated partnership. The property was recorded at an estimated fair market value of $1.6 million.

In October 2009, we initiated a leasing program in Williams County, North Dakota, with the objective of establishing a significant position where we will serve as operator. As of July 2010, we have acquired approximately 50,000 net leasehold acres. 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 expect the joint venture to drill its first well in the prospect in mid-September 2010.

Subsequent to June 30, 2010, we closed an acquisition of 40 producing oil and gas wells in the Giddings field of Central Texas. The purchase price was $16.6 million plus closing adjustments for normal operations activity. We funded the acquisition through borrowings under our credit facility.

Results of Operations

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

The Company recorded net income of $4,443,000 for the three months ended June 30, 2010 compared to net income of $3,499,000 for the same period in 2009. This $944,000 increase resulted primarily from the following factors:

Net amounts contributing to increase (decrease) in net income (in 000s):
Oil and gas sales	$	7,514
Lease operating expenses		(776	)
Production taxes		(373	)
Exploration expense		149
Re-engineering and workovers		60
General and administrative expenses (“G&A”)		(109	)
Depletion, depreciation and amortization expense (“DD&A”)		(1,237	)
Impairment expense		(2,615	)
Net interest income (expense)		(111	)
Hedge ineffectiveness		87
Gain (loss) on derivative contracts		23
Gain (loss) on sale of property		(89	)
Other income - net		(910	)
Income before income taxes		1,613
Provision for income taxes		(669	)
Increase in net income	$	944

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $7,514,000, or 45%. Increases in commodity prices accounted for $4,499,000 of the increase and increased production volumes accounted for the remaining $3,015,000. Increased oil production was attributable primarily to new wells drilled during 2009 and 2010, 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 and 2010, partially offset by normal production declines on previously existing wells. Properties acquired from SBE Partners, LP accounted for gas production of 460,000 Mcf and total revenues of $1,685,000 in the second quarter of 2010 versus 287,000 Mcf and total revenues of $914,000 during the second quarter of 2009. Price and production comparisons are set forth in the following table.

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	Percent increase (decrease)		Three Months Ended June 30,
			2010		2009
Gas Production (MMcf)	20	%		1,300		1,087
Oil Production (Mbbls)	20	%		255		212
Barrel of Oil Equivalent (MBOE)	20	%		472		393
Average Price Gas Before Hedge Settlements (per Mcf)	16	%	$	3.76	$	3.24
Average Price Oil Before Hedge Settlements (per Bbl)	35	%	$	71.83	$	53.40
Average Realized Price Gas (per Mcf)	24	%	$	4.90	$	3.95
Average Realized Price Oil (per Bbl)	19	%	$	70.48	$	59.28

Lease Operating Expenses. Lease operating expenses (“LOE”) increased from $4,417,000 in the second quarter of 2009 to $5,193,000 for the same period in 2010, an increase of $776,000 or 18%. On a unit-of-production basis, LOE decreased by $0.24 per BOE, or 2%, as a result changes in our property portfolio, re-engineering projects completed during 2009 that either enhanced production or lowered per unit operating costs, as well as our ongoing cost containment measures.

Re-engineering and workovers. Re-engineering and workover costs decreased by $60,000, from $315,000 to $255,000, due to the completion of a major re-engineering and workover program in 2009.

Production Taxes. Production taxes increased by $373,000 or 32%, due to a change in our portfolio of properties. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the quarter ended June 30, 2010 and 2009 were 6.63% and 7.88%, respectively, of oil and gas sales before the effects of hedging. The 2010 rate decreased from 2009 due to the approval of severance tax exemptions on wells in several of our key fields as well as a change in our portfolio of producing properties.

Exploration and Impairment Costs. Our exploration costs were $139,000 for the second quarter of 2010 and $288,000 for the second 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. 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 estimate of future natural gas prices.

General and Administrative Expenses. G&A increased by $109,000 due primarily to increases in personnel costs. As our business has expanded we have also expanded our staff. The total non-cash charges related to stock-based compensation included in G&A expense for the three month periods ended June 30, 2010 and 2009 were $275,000 and $397,000, respectively.

Depreciation, Depletion and Amortization. DD&A expense increased by $1,237,000 or 26%, due to higher capitalized cost and higher production volumes. 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 $12.03 in 2009 to $12.64 in 2010.

Interest Income and Expense. Interest expense increased by $141,000 due to higher average debt levels in the second quarter of 2010 compared to the same period in 2009. For the three months ended June 30, 2010, average outstanding debt was $69,000,000 compared to $63,000,000 for the same period in 2009. Interest income increased by $30,000 in the second quarter of 2010 compared to the same period of 2009.

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Hedge Ineffectiveness. In the second quarter of 2010 the gain from hedge ineffectiveness was $61,000 compared to a loss of $26,000 for the same period in 2009. During the second 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 second quarter of 2010, we recognized cash settlement losses of $101,000, offset by mark-to-market gains of $118,000. In the second quarter of 2009, we recognized cash settlement losses on the $10 million swap of $83,000, offset by mark-to-market gains of $77,000.

Other Income. Other income decreased by $910,000 in the second quarter of 2010 compared to the same period in 2009 due primarily to a decrease in partnership income and partnership management fees offset by an increase in severance tax refunds. During the second quarter of 2009 we recorded partnership income of $1,455,000 versus income of $488,000 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. Since the partnership, subsequent to the sale, held a smaller interest in its properties our partnership management fee decreased by $258,000. Also contributing to the decrease in other income, property operating income decreased by $63,000 and other income decreased by $7,000. During the second quarter of 2009 we accrued for refunds of severance taxes on qualifying high cost gas wells in Texas of $599,000. During the second quarter of 2010 we recorded severance tax refunds of $984,000 related to both high cost gas wells in Texas and certain qualifying oil wells in Louisiana. Additionally, in the second quarter of 2009 we had a net gain on sales of properties and other assets of $89,000; there were not any sales that resulted in a gain in the same period during 2010.

Income Tax Expense. Income tax expense for the second quarter of 2010 was $2,885,000 compared to $2,216,000 for the same period in 2009. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the second quarter of 2010 and 2009 was approximately 39%.

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Six months ended June 30, 2010, compared to six months ended June 30, 2009

The Company recorded net income of $10,517,000 for the six months ended June 30, 2010 compared to net income of $3,976,000 for the same period in 2009. This $6,541,000 increase resulted primarily from the following factors:

Net amounts contributing to increase (decrease) in net income (in thousands):
Oil and gas sales	$	19,943
Lease operating expenses		(1,410	)
Production taxes		(1,362	)
Exploration expense		(235	)
Re-engineering and workovers		788
General and administrative expenses (“G&A”)		167
Depletion, depreciation and amortization expense (“DD&A”)		(3,120	)
Impairment expense		(2,615	)
Net interest income (expense)		(567	)
Hedge ineffectiveness		391
Gain (loss) on derivative contracts		62
Gain (loss) on sale of property		(1,343	)
Other income - net		(72	)
Income before income taxes		10,627
Provision for income taxes		(4,086	)
Increase in net income	$	6,541

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Net revenues from oil and gas sales increased $19,943,000, or 68%. Increased commodity prices accounted for $11,825,000 of the increase and increased production volumes accounted for the remaining $8,118,000. Increased oil production was attributable primarily to new wells drilled during 2009 and 2010, 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 971,000 Mcf and total revenue of $4,113,000 during the six months ended June 30, 2010 versus 287,000 Mcf and total revenues of $914,000 during the six months ended June 30, 2009. Price and production comparisons are set forth in the following table.

	Percent increase (decrease)		Six Months Ended June 30,
			2010		2009
Gas Production (MMcf)	47	%		2,580		1,752
Oil Production (MBbls)	30	%		504		389
Barrel of Oil Equivalent (MBOE)	37	%		934		681
Average Price Gas Before Hedge Settlements (per Mcf)	25	%	$	4.29	$	3.43
Average Price Oil Before Hedge Settlements (per Bbl)	59	%	$	73.01	$	45.88
Average Realized Price Gas (per Mcf)	31	%	$	5.25	$	4.01
Average Realized Price Oil (per Bbl)	24	%	$	70.55	$	56.87

Lease Operating Expenses. Lease operating expenses increased from approximately $8,807,000 during the six months ended June 30, 2009 to $10,217,000 for the same period in 2010, an increase of $1,410,000 or 16%. On a unit-of-production basis, LOE costs decreased by $2.00 per BOE or 15% as a result of acquisition of properties with lower operating costs, re-engineering projects completed during 2009 that either enhanced production or lowered per unit operating costs as well as our ongoing cost containment measures.

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Re-engineering and Workover. Re-engineering and workover costs decreased by $788,000 from $1,296,000 to $508,000 primarily due to a major re-engineering and workover program concluded in 2009.

Production Taxes. Production taxes increased by $1,362,000 or 69%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for the first six months of 2010 and 2009 were 6.95% and 8.22%, 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 as well as a change in our portfolio of producing properties.

Exploration and Impairment Costs. Our exploration costs were $603,000 for the six months ended June 30, 2010 and $368,000 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 $411,000 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 $167,000 in the first six 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 six months ended June 30, 2010 and 2009 are non-cash charges related to our stock-based compensation of $494,000 and $661,000, respectively.

Depreciation, Depletion and Amortization. DD&A expense increased by $3,120,000 or 34% due to higher capitalized costs. Capitalized costs increased due to acquisitions of additional property interests in both the Austin Chalk and Bakken Shale and continued successful drilling in those same areas. On a units of production basis, DD&A per BOE decreased from $13.51 in 2009 to $13.19 in 2010.

Interest Income and Expense. Interest expense increased by $595,000 due to higher average debt levels in the first half of 2010 compared to the same period in 2009. During the first six months of 2010, our average outstanding debt was approximately of $69,000,000 compared to $51,000,000 for the same period in 2009. Interest income increased by $28,000 in the first six months of 2010 compared to the same period of 2009, due to higher average invested cash balances and higher interest rates.

Hedge Ineffectiveness. For the first six months of 2010 the gain from hedge ineffectiveness was $316,000, compared to a loss of $75,000 for the same period in 2009. During the six months ended June 30, 2010, our derivatives accounted for as cash flow hedges increased in value; therefore, the change in the ineffective portion of these derivatives was a gain. During the six months ended June 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 six months ended June 30, 2010, we recognized cash settlement losses of $201,000; these losses were offset by mark-to-market gains of $205,000. For the first six months of 2009, we recognized cash settlement losses on the $10 million swap of $177,000; these losses were offset by mark-to-market gains of $119,000.

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Other Income. Other income decreased by $72,000 in the first six 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 six months of 2009 we recorded partnership income of $1,460,000; during the first six months of 2010 partnership income decreased by $118,000 to $1,342,000. Partnership income in the first six months of 2009 included our share of partnership severance tax refunds of $1,318,000, related to tax exempt well status obtained for certain wells with a high drilling cost 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. Since the partnership, subsequent to the sale, held a smaller interest in its properties our partnership management fee decreased $397,000. Also contributing to the decrease in other income, property operating income decreased by $130,000 and other income decreased by $59,000 from the six months ended June 30, 2009, to the six months ended June 30, 2010. During the first six months of 2009 we accrued for refunds of severance taxes on qualifying high cost gas wells in Texas of $599,000. During the first six 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. In the first six months of 2009 we had a net gain on sales of properties and other assets of $1,488,000 versus $145,000 in the same period of 2010.

Income Tax Expense. Income tax expense for the first half of 2010 was $6,662,000 compared to $2,576,000 for the same period in 2009. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the first six months of 2010 and 2009 was approximately 39%.

Impact of Changing Prices and Costs

Our revenues and the carrying value of our oil and gas properties are subject to significant change due to changes in oil and gas prices. Also, history has demonstrated that commodity prices can be extremely volatile and unpredictable. 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 half of 2010. The average realized oil price of $70.55 per Bbl, net of hedges, for the six months ended June 30, 2010, was 24% higher than for the comparable period in 2009. The average realized natural gas price of $5.25 per Mcf, net of hedges, for the six months ended June 30, 2010, was 31% higher than for the comparable period in 2009. The average realized price for the six months ended June 30, 2010, included the effects of our hedges. Should significant price decreases occur or should prices fail to remain at levels which will facilitate repayment of debt and reinvestment of cash flow to replace current production, we could experience difficulty in developing our assets and continuing our growth. 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 and 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

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(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 June 30, 2010, our borrowing base under our credit facility with Wells Fargo Bank was $145 million and our outstanding balance was $69 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 May 4, 2010, all members of our bank group reaffirmed our borrowing base at $145 million. As of August 5, 2010, our outstanding balance under the facility was $85 million.

Cash Flows from Operating Activities

For the six months ended June 30, 2010, our net cash provided by operating activities was $31.8 million, versus $3.9 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.

Cash Flows from Investing Activities

Cash applied to oil and gas capital expenditures for the six months ended June 30, 2010 and 2009, was $29.1 million and $70.2 million, respectively. In addition, cash generated from the sale of oil and gas properties for the six months ended June 30, 2010 and 2009 was $425,000 and $1,991,000 respectively. Capital expenditures for the first six months of 2010 were financed with working capital. We expect to spend approximately $50 million to $70 million in additional capital expenditures during the remainder of 2010 and 2011.

Capital Budget

We have identified approximately $200 million of diversified exploration and development projects, which are summarized in the table below. With success these projects could be further expanded to include more than $150 million of incremental capital expenditures to fully exploit the properties. The estimates below exclude potential capital expenditures for exploratory and development drilling associated with incremental acreage and seismic purchases subsequent to the second quarter of 2010. From this list of identified projects, we currently have budgeted capital expenditures of $120 million for 2010 and 2011. Actual expenditures could vary materially due to oil and gas prices, impact of increasing costs on estimated

31

rates of return, demand and supply of services, required regulatory approvals and other factors, all beyond our control. While the table includes the bulk of our currently identified projects, we are constantly working to expand our acreage and drilling inventory.

We believe a benefit of our portfolio is that it includes both gas and oil opportunities, much of which are “held by production” and therefore not subject to lease expiration or significant future incremental carrying costs. Accordingly, we have some ability to adjust our capital spending as our financial position and industry circumstances dictate. Generally, we intend to maintain our capital spending within our cash flow, although in certain limited circumstances, we may utilize our borrowing capacity for development or lease saving operations. We do not intend to use our borrowing capacity for exploratory drilling. We may, however, shift our expenditures between geographic areas and projects (such as development versus exploration) in an attempt to maximize cash flow, maximize rates of return and take advantage of regional differences in net commodity prices and service costs. While financial conditions, commodity prices and industry circumstances may require us to make adjustments, it is our current intent to continue our Bakken and Austin Chalk drilling programs and certain other projects in the Gulf Coast, West Texas and the Williston Basin. Currently, however, we have suspended our Austin Chalk gas drilling program and are continuing to emphasize drilling opportunities with oil objectives. We expect to recommence our Austin Chalk drilling program when natural gas prices increase substantially.

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

	($ in Millions)		Percent of District Opportunity
Southern District
Austin Chalk drilling and development(1) (2)	$	50.9	48.3	%
Other development drilling(2)	$	23.6	22.4	%
Exploratory drilling(3)	$	10.8	10.3	%
Acreage, seismic and other(5)	$	16.0	15.2	%
Re-engineering(4)	$	3.0	2.8	%
Waterflood expansion(2)	$	1.0	1.0	%
	$	105.3
Northern District
Bakken Shale drilling(6) (2)	$	57.4	60.6	%
Other development drilling(2)	$	22.6	23.9	%
Acreage, seismic and other(5)	$	10.0	10.6	%
Waterflood and associated drilling(2)	$	3.2	3.4	%
Re-engineering(4)	$	1.5	1.5	%
	$	94.7
Total	$	200.0

Notes:

(1) Horizontal drilling and development program with an affiliated institutional partnership. We currently estimate approximately 20 additional drilling locations, many of which are expected to be dual lateral wells. We also expect to re-enter certain well bores and extend existing laterals or drill additional laterals, none of the possible re-entries are included in the above table as all such opportunities are held by production and have no critical timing.

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

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

(4) Includes activities related to existing fields intended to enhance production and lower operating expenses. These expenditures include replacement, repairs or additional flow lines, facilities, and/or compression as well as the modification of the down-hole lift method and re-completions.

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

(6) The estimates included above relate to both our operated and non-operated positions in the Bakken Shale play of the Williston Basin.

The estimated expenditures included above are based on actual and anticipated contractual commitments and the current advice of other operators, where such information is available.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Transaction Date	Transaction Type	Beginning	Ending	Price Per Unit	Remaining Annual Volumes	Fair Value Outstanding as of June 30, 2010
						(in thousands)
Natural Gas
October-07	Collar	01/01/10	12/31/10	$7.00 -$9.90	643,500 Mmbtu	$	1,420
October-07	Collar	01/01/11	12/31/11	$7.00 -$9.20	1,079,000 Mmbtu		1,999
June-09	Swap	01/01/10	12/31/10	$5.155	720,000 Mmbtu		353
June-09	Swap	01/01/10	12/31/10	$5.195	240,000 Mmbtu		127
December-09	Swap	04/01/10	03/31/11	$6.065	450,000 Mmbtu		521
December-09	Swap	04/01/11	03/31/12	$6.450	780,000 Mmbtu		896
December-09	Swap	04/01/12	12/31/12	$6.415	450,000 Mmbtu		430
							5,746
Crude Oil
October-07	Swap	01/01/10	12/31/10	$74.71	161,000 Bbls		(306	)
October-07	Swap	01/01/11	12/31/11	$74.37	282,000 Bbls		(1,423	)
January-10	Swap	02/01/10	12/31/10	$85.32	60,000 Bbls		514
January-10	Swap	01/01/11	12/31/11	$88.45	84,000 Bbls		727
							(488	)
Interest Rate
Oct-07/Dec-09	Swap	10/10/07	10/16/10	4.29375%	$40 Million Notional
					30-day LIBOR		(477	)
Oct-07/Dec-09	Swap	12/16/08	10/16/10	4.29375%	$10 Million Notional
					30-day LIBOR		(120	)
							(597	)
						$	4,661

We are exposed to financial risk from changes in interest rates. The long-term debt on our balance sheet of $69,000,000 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 have essentially fixed the rate for $40,000,000 of that balance until October 2010 through the use of an interest rate swap included in the table above. 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 June 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 June 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 June 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. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

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

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Item 6. Exhibits

EXHIBIT INDEX

FOR

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

3.1	Amended and Restated Articles of Incorporation dates June 10, 2003, incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-KSB for the year ended December 31, 2003.
3.1(a)	Articles of Amendment to the Articles of Incorporation, incorporated by reference as Annex C to the Registrant’s definitive Proxy Statement dated February 23, 2007, and filed with the Commission on February 23, 2007.
3.1(b)	Articles of Amendment to Articles of Incorporation, dated November 6, 2007. (5)
3.2	Bylaws, as amended March 2, 2004, incorporated by reference to Exhibit 3.2 of Registrant’s Form 10-KSB for the year ended December 31, 2003.
10.15	Agreement and Plan of Merger dated September 14, 2006, among GeoResources, Inc., Southern Bay Energy Acquisition, LLC, Chandler Acquisition, LLC, Southern Bay Oil & Gas, L.P., Chandler Energy, LLC and PICA Energy, LLC (including Amendment No. 1 dated February 16, 2007). Incorporated by reference as Annex A to the Registrant’s Definitive Proxy Statement dated February 23, 2007 and filed with the Commission on February 23, 2007.
10.19	June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090. (3)
10.20	First Amendment to June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated November 10, 2003. (3)
10.21	Assignment and Assumption by Southern Bay Energy, L.L.C. of June 7, 2001 Lease Agreement by and between AROC, Inc. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 19, 2005. (3)
10.22	Unconditional Guaranty of June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 19, 2005. (3)
10.23	Second Amendment to June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 19, 2005. (3)
10.24	Third Amendment to June 7, 2001 Lease Agreement by and between Southern Bay Energy, L.L.C. and BGK Texas Property Management, Inc. for 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated April 9, 2007. (3)
10.26	January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street Building, Suite 860, 475 17th Street, Denver, Colorado 80202. (3)
10.27	First Amendment to January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated September 28, 2001. (3)
10.28	Second Amendment to January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated October 23, 2002. (3)
10.29	Third Amendment to January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated June 28, 2004. (3)

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10.30	Credit Agreement dated September 26, 2007 between the Registrant and Wachovia Bank National Association. (2)
10.31	Limited Partner Interest Purchase and Sale Agreement dated October 16, 2007 between the Registrant and TIFD III-X, LLC. (2)
10.32	Amended and Restated Credit Agreement dated October 16, 2007 between the Registrant and Wachovia Bank National Association. (2)
10.33	Amended and Restated Credit Agreement dated October 16, 2007 between the Registrant and Wachovia Bank National Association. (2)
10.34	Form of Purchase Agreement. (4)
10.35	Form of Warrant. (4)
10.36	Form of Registration Rights Agreement. (4)
10.37	Agreement of Limited Partnership for OKLA Energy Partners LP dated May 20, 2008. (6)
10.38	Lease Agreement by and between Southern Bay Energy, L.L.C. and Cypress Court Operating Associates, L.P. for office space at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated September 25, 2008. (7)
10.39	Purchase and Sale Agreement between SBE Partners LP and Catena Oil and Gas LLC, dated May 29, 2009. (8)
10.40	Consent and Amendment No. 1 to Agreement of Limited Partnership of SBE Partners LP as of May 29, 2009. (8)
10.41	Second Amended and Restated Credit Agreement between the Registrant and Wachovia Bank, National Association as Administrative Agent dated July 13, 2009. (8)
10.42	Consent, Distribution Agreement, and Amendment No. 2 to Agreement of Limited Partnership of SBE Partners LP. (9)
10.43	First Amendment to Lease Agreement by and between Southern Bay Energy, L.L.C. and Cypress Court Operating Associates, Limited Partnership for office space at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated January 29, 2010. (10)
10.44	Exploration and Development Agreement-New Home II Project, between G3 Energy, LLC and Resolute Northern Rockies, LLC, effective February 2, 2010. (1)
10.45	Amendment to Exploration and Development Agreement-New Home II Project, between G3 Energy, LLC and Resolute Northern Rockies, LLC, effective February 2, 2010. (1)
14.1	Code of Business Conduct and Ethics adopted March 2, 2004, incorporated by reference to Exhibit 14.1 of Registrant’s Form 10-KSB for fiscal year ended December 31, 2003.
21.1	Subsidiaries of the Registrant. (3)
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
32.1	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)
32.2	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)

(1) Filed herewith.

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

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

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

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

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

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

(8) Filed with the Registrant’s Form 10-Q for the quarter ended June 30, 2009.

(9) Filed with the Registrant’s Form 10-Q for the quarter ended September 30, 2009.

(10) Filed with the Registrant’s Form 10-K for the year ended December 31, 2009.

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SIGNATURES

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

	GEORESOURCES, INC.
August 6, 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