- Quarterly Report (10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period ended March 31, 2010

Commission File Number – 0-8041

LOGO

GEORESOURCES, INC.

(Exact name of registrant as specified in its charter)


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

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

(281) 537-9920

(Registrant’s telephone number, including area code)

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

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

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

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

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


Class of equity		Outstanding at May 6, 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 March 31, 2010 and December 31, 2009.	3

	Consolidated Statements of Income for the Three Months ended March 31, 2010 and 2009.	5

	Consolidated Statement of Stockholders’ Equity and Comprehensive Income for the Three Months ended March 31, 2010.	6

	Consolidated Statements of Cash Flows for the Three Months ended March 31, 2010 and 2009.	7

	Notes to Consolidated Financial Statements.	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	29

Item 4.	Controls and Procedures.	30

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.	31

Item 1A.	Risk Factors.	31

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	31

Item 3.	Defaults Upon Senior Securities.	31

Item 4.	Reserved	31

Item 5.	Other Information.	31

Item 6.	Exhibits.	32

	Signatures.	35

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	March 31, 2010			December 31, 2009
	(unaudited)
ASSETS

Current assets:

Cash	$	18,010		$	12,660
Accounts receivable:
Oil and gas revenues		15,845			14,860
Joint interest billings and other		4,098			13,734
Affiliated partnerships		1,402			933
Notes receivable		120			120
Derivative financial instruments		5,409			764
Income taxes receivable		1,239			2,077
Prepaid expenses and other		1,990			2,297


Total current assets		48,113			47,445


Oil and gas properties, successful efforts method:
Proved properties		294,451			285,363
Unproved properties		13,510			10,281
Office and other equipment		850			828
Land		96			96

		308,907			296,568

Less accumulated depreciation, depletion and amortization		(54,534	)		(48,182	)

Net property and equipment		254,373			248,386


Equity in oil and gas limited partnerships		3,011			3,532

Derivative financial instruments		2,713			1,360

Deferred financing costs and other		3,293			3,574

	$	311,503		$	304,297

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	March 31, 2010		December 31, 2009
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable	$	5,725	$	6,452
Accounts payable to affiliated partnerships		3,828		8,361
Revenue and royalties payable		11,826		13,928
Drilling advances		77		390
Accrued expenses		1,499		1,574
Derivative financial instruments		4,473		4,794


Total current liabilities		27,428		35,499


Long-term debt		69,000		69,000

Deferred income taxes		21,298		15,778

Asset retirement obligations		6,229		6,110

Derivative financial instruments		2,497		3,233

Stockholders’ equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 19,712,862 in 2010 and 19,705,362 in 2009		197		197
Additional paid-in capital		147,249		146,966
Accumulated other comprehensive income		729		(3,288	)
Retained earnings		36,876		30,802


Total stockholders’ equity		185,051		174,677

	$	311,503	$	304,297

The accompanying notes are an integral part of these statements.

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except share and per share amounts)

(unaudited)


	Three Months Ended March 31,
	2010			2009
Revenue:
Oil and gas revenues	$	24,729		$	12,300
Partnership management fees		159			298
Property operating income		391			458
Gain on sale of property and equipment		145			1,399
Partnership income		854			5
Interest and other		298			105


Total revenue		26,576			14,565

Expenses:
Lease operating expense		5,024			4,390
Severance taxes		1,783			794
Re-engineering and workovers		253			981
Exploration expense		464			80
General and administrative expense		1,819			2,095
Depreciation, depletion and amortization		6,351			4,468
Hedge ineffectiveness		(255	)		49
Loss on derivative contracts		13			52
Interest		1,273			819


Total expense		16,725			13,728

Income before income taxes		9,851			837

Income tax expense (benefit):
Current		953			(734	)
Deferred		2,824			1,094

		3,777			360

Net income	$	6,074		$	477


Net income per share (basic)	$	0.31		$	0.03


Net income per share (diluted)	$	0.30		$	0.03

Weighted average shares outstanding:
Basic		19,710,362			16,241,717

Diluted		20,004,083			16,241,717

The accompanying notes are an integral part of these statements

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY and COMPREHENSIVE INCOME

Three Months Ended March 31, 2010

(In thousands, except share data)

(unaudited)


	Common Stock			Additional Paid-in Capital		Retained Earning		Accumulated Other Comprehensive Income (Loss)			Total
	Shares	Par value		Additional Paid-in Capital		Retained Earning		Accumulated Other Comprehensive Income (Loss)			Total
Balance, December 31, 2009	19,705,362	$	197	$	146,966	$	30,802	$	(3,288	)	$	174,677

Exercise of employee stock options	7,500		—		64							64

Comprehensive income:
Net income							6,074					6,074
Change in fair market value of hedged positions, net of taxes of $2,584									3,831			3,831
Net realized hedging losses charged to income, net of taxes of $112									186			186

Total comprehensive income												10,091


Equity based compensation expense					219							219


Balance, March 31, 2010	19,712,862	$	197	$	147,249	$	36,876	$	729		$	185,051

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands, except share and per share amounts)

(unaudited)


	Three Months Ended March 31,
	2010			2009
Cash flows from operating activities:
Net income	$	6,074		$	477
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		6,351			4,468
Gain on sale of property and equipment		(145	)		(1,399	)
Accretion of asset retirement obligations		98			61
Unrealized gain on derivative contracts		(87	)		(42	)
Amortization of loss on canceled hedge contract		—			122
Hedge ineffectiveness loss		(255	)		49
Partnership income		(854	)		(5	)
Partnership distributions		1,375			122
Deferred income taxes		2,824			1,094
Non-cash compensation		219			265
Changes in assets and liabilities:
Decrease in accounts receivable		9,020			1,660
Decrease (increase) in prepaid expense and other		587			(1,360	)
Decrease in accounts payable and accrued expense		(7,750	)		(9,378	)

Net cash (used in) provided by operating activities		17,457			(3,866	)

Cash flows from investing activities:
Proceeds from sale of property and equipment		503			2,015
Additions to property and equipment		(12,674	)		(5,057	)

Net cash used in investing activities		(12,171	)		(3,042	)

Cash flows from financing activities:
Proceeds from stock options exercised		64			—

Net cash provided by financing activities		64			—


Net increase (decrease) in cash and cash equivalents		5,350			(6,908	)


Cash and cash equivalents at beginning of period		12,660			13,967


Cash and cash equivalents at end of period	$	18,010		$	7,059


Supplementary information:
Interest paid	$	997		$	694
Income taxes paid	$	115		$	25

The accompanying notes are an integral part of these statements.

GEORESOURCES, INC. and SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE A: Organization and Basis of Presentation

Description of Operations

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

Consolidated Financial Statements

The unaudited consolidated financial statements include the accounts of GeoResources, Inc. 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 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. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Earnings Per Share

Basic net income per common share is computed based on the weighted average shares of common stock outstanding. Net income per share computations to reconcile basic and diluted net income for the three months ended March 31, 2010 and 2009 consist of the following (in thousands, except per share data):


	2010		2009

Numerator:
Net income available for common shares	$	6,074	$	477

Denominator:
Basic weighted average shares		19,710		16,242
Effect of dilutive securities - options		294		—

Diluted weighted average shares		20,004		16,242

Earnings per share
Basic	$	0.31	$	0.03

Diluted	$	0.30	$	0.03

For the periods ended March 31, 2010 and 2009, options to purchase 50,000 and 1,515,000, respectively, were excluded from the dilutive earnings per share calculation because the options’ exercise prices exceeded the average market price of the common shares during the periods.

NOTE B: Acquisitions and Dispositions

Bakken Acquisition

In May 2009, the Company closed an acquisition, through an existing joint venture partner, of producing wells and acreage in the Bakken Shale trend of the Williston Basin. The Company acquired a 15% interest in approximately 60,000 net acres, and also acquired 15% of varying working interests in 59 producing and productive wells. The Company’s net acquisition cost was approximately $10.4 million, subject to closing adjustments for normal operations activity and other customary purchase price adjustments. The Company funded the acquisition with borrowings from its senior secured revolving credit facility. The amount of revenue from the acquisition included in the Company’s Consolidated Statement of Income for the three months ended March 31, 2010, was $1,421,000.

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 April 2010, the Company has acquired approximately 47,000 net leasehold acres. The Company intends to develop the acreage position with two industry partners while retaining a 47.5% working interest. The Company’s net investment in the prospect as of March 31, 2010 was $2.9 million.

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 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 three months ended March 31, 2010, was $2,316,000 and $1,137,000, respectively.

The following summary presents unaudited pro forma information for the three months ended March 31, 2009, as if the Acquisition had been consummated at January 1, 2009 (in thousands, except per share amounts):


Total revenue	$	17,687

Income before taxes		1,413

Net income		835

Net income per share:
Basic	$	0.05
Diluted	$	0.05

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 January 2010, the FASB issued guidance that clarifies and requires new disclosures about fair value measurements. The clarifications and requirements to disclose the amounts and reasons for significant transfers between Level 1 and Level 2, as well as significant transfers in and out of Level 3 of the fair value hierarchy, were adopted by the Company in the first quarter of 2010. Note H, Fair Value Disclosures, reflects the amended disclosure requirements. The new guidance also requires that purchases, sales, issuances, and settlements be presented gross in the Level 3 reconciliation. The requirement is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years, with early adoption permitted. The Company adopted the guidance that required gross presentation on January 1, 2010. Since this new guidance only amends the disclosures requirements, it did not impact the Company’s consolidated balance sheet, statement of income or statement of cash flows.

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 March 31, 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 March 31, 2010.

The principal outstanding under the Company’s credit agreement was $69 million at both March 31, 2010 and December 31, 2009. The annual interest rate in effect at March 31, 2010 was 2.74% on the entire amount of outstanding principal. The remaining borrowing base capacity under the Second Amended Credit Agreement at March 31, 2010, was $76 million. The maturity date for amounts outstanding under the Seconded Amended Credit Agreement is October 16, 2012.

Interest expenses for the three months ended March 31, 2010 and 2009 includes amortization of deferred financing costs of $264,000 and $132,000, respectively.

In connection with the initial borrowing from the bank under the credit facility the Company entered into an interest rate swap. The purpose of entering into an interest rate swap was to protect the Company from undue exposure to interest rate increases. In October 2007, the Company entered into an interest rate swap agreement, providing a fixed rate of 4.79% on a notional $50,000,000 through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million swap each with a fixed 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 March 31, 2010 and December 31, 2009, accumulated other comprehensive income included unrecognized losses of $595,000 net of a tax benefit of $358,000, and $1,302,000, 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 March 31, 2010 and 2009, the Company recognized realized cash settlement losses of $402,000 and $470,000, 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 March 31, 2010, the Company expects to reclassify net losses of $953,000 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.

A summary of the Company’s stock option activity for the three months ended March 31, 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	—
Exercised	(7,500	)	$	8.60	$	3.52
Forfeited	—

Outstanding, March 31, 2010	1,532,500		$	9.40	$	3.34	8.05	$	9,200,000


Vested and exercisable	556,250		$	8.59	$	2.96	7.97	$	3,717,000

Vested and expected to vest	1,517,865		$	9.40	$	3.33	8.05	$	9,117,000

During the three months ended March 31, 2010, 181,250 options vested with a weighted average exercise price of $9.25. The weighted average grant date fair value of these options was $4.36 per option. At March 31, 2010, there were 976,250 unvested options with a weighted average remaining amortization period of 2.46 years.

The Company recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. For the quarters ended March 31, 2010 and 2009 the Company recognized compensation expense of $219,000 and $265,000, respectively,

related to these options. As of March 31, 2010, the future pre-tax expense of non-vested stock options is $2,750,000 to be recognized through the fourth quarter of 2013.

The Company has 613,336 warrants to purchase common stock outstanding at March 31, 2010. The warrants have an exercise price of $32.43 and have a remaining life of 3 years and 2 months.

NOTE F: Income Taxes

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

Uncertain Tax Positions

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

At March 31, 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 is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statements of Income. As of March 31, 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 March 31, 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 also limit future revenues from favorable price movements.

At March 31, 2010, accumulated other comprehensive income (loss) consisted of unrecognized gains of $1,324,000, net of taxes of $798,000, 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 quarter ended March 31, 2010, the Company recognized a net realized cash settlement gain on commodity derivatives of $104,000. For the quarter ended March 31, 2009, the Company recognized realized cash settlement gains of $3,401,000 and reclassified losses related to a 2009 gas swap contract that was canceled during 2008 of $122,000. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at March 31, 2010, the Company expects to reclassify net gains of $2,127,000 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 calls 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.

At March 31, 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	241,500			$	74.710
2010	90,000			$	85.320
2011	282,000			$	74.370
2011	84,000			$	88.450

Natural Gas Contracts (Mmbtu)
Swap contracts
2010	1,080,000			$	5.155
2010	360,000			$	5.195
2010	360,000			$	6.065
2011	210,000			$	6.065
2011	630,000			$	6.450
2012	150,000			$	6.450
2012	450,000			$	6.415

Costless collars contracts:
2010	965,250	$	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	Mar. 31, 2010		Dec. 31, 2009		Balance Sheet Location	Mar. 31, 2010			Dec. 31, 2009

Commodity contracts	Current derivative financial instruments asset	$	5,409	$	764	Current derivative financial instruments liability	$	(3,282	)	$	(3,167	)

Commodity contracts	Long-term derivative financial instruments asset		2,713		1,360	Long-term derivative financial instruments liability		(2,497	)		(3,233	)

Interest rate swap contract	Current derivative financial instruments asset		—		—	Current derivative financial instruments liability		(953	)		(1,302	)

		$	8,122	$	2,124		$	(6,732	)	$	(7,702	)


Derivatives not designated as ASC 815 hedges:	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet Location	Mar. 31, 2010		Dec. 31, 2009		Balance Sheet Location	Mar. 31, 2010			Dec. 31, 2009

Interest rate swap contract	Current derivative financial instruments asset	$	—	$	—	Current derivative financial instruments liability	$	(238	)	$	(325	)

		$	—	$	—		$	(238	)	$	(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 March 31, 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)
Derivatives designated as ASC 815 hedges:	Mar. 31, 2010			Mar. 31, 2009				Mar. 31, 2010			Mar. 31, 2009

Commodity contracts	$	6,468		$	3,727		Oil and gas revenues	$	104		$	3,279

Interest rate swap contract		(53	)		(208	)	Interest expense		(402	)		(376	)


	$	6,415		$	3,519			$	(298	)	$	2,903


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)
		Mar. 31, 2010			Mar. 31, 2009
		Mar. 31, 2010			Mar. 31, 2009

Commodity contracts	Hedge ineffectiveness	$	(255	)	$	49


Derivatives not designated as ASC 815 hedges:	Location of (Gain) or Loss Recognized in Income on Derivative	Amount of (Gain) or Loss Recognized in Income on Derivative
Derivatives not designated as ASC 815 hedges:		Mar. 31, 2010			Mar. 31, 2009

Realized cash settlements on interest rate swap	Loss on derivative contracts	$	100		$	94

Unrealized (gains) on commodity contracts	Loss on derivative contracts		(87	)		(42	)


		$	13		$	52

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

NOTE H: Fair Value Disclosures

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

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

•

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

•

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

•

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

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

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

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

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

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

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

Current portion of derivative financial instrument asset ⁽¹⁾	—	$	5,409		—	$	5,409

Long-term portion of derivative financial instrument asset ⁽¹⁾	—		2,713		—		2,713

Current portion of derivative financial instrument liability ⁽²⁾	—		(4,473	)	—		(4,473	)

Long-term portion of derivative financial instrument liability ⁽¹⁾	—		(2,497	)	—		(2,497	)

(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 ($953,000), a $10 million interest rate swap accounted for as a trading security ($238,000) and commodity derivatives accounted for as cash flow hedges ($3,282,000).

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

(in thousands)


	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)	Balances as of December 31, 2009

Current portion of derivative financial instrument asset ⁽¹⁾	—	$	764		—	$	764

Long-term portion of derivative financial instrument asset ⁽¹⁾	—		1,360		—		1,360

Current portion of derivative financial instrument liability ⁽²⁾	—		(4,794	)	—		(4,794	)

Long-term portion of derivative financial instrument liability ⁽¹⁾	—		(3,233	)	—		(3,233	)

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

(2)	Includes a $40 million interest rate swap accounted for as a cash flow hedge ($1,302,000), a $10 million interest rate swap accounted for as a trading security ($325,000) and commodity derivatives accounted for as cash flow hedges ($3,167,000).

At March 31, 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 annually and when events and circumstances indicate a significant decline in the recoverability of the carrying value of such properties. When events and circumstances indicate a significant decline in the recoverability of a property, the Company estimates the future cash flows expected in connection with the property and compares such future cash flows to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include significant Level 3 assumptions associated with estimates of future oil and gas production, commodity prices based on commodity futures price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The Company did not record any asset impairments during the three month periods ended March 31, 2010 or 2009.

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.

NOTE J: Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. The Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the three months ended March 31, 2010, are as follows (in thousands):


Asset retirement obligation, January 1, 2010	$	6,110

Accretion expense		98
Additional liabilities incurred		21


Asset retirement obligation, March 31, 2010	$	6,229

NOTE K: Related Party Transactions

Accounts receivable at March 31, 2010, and December 31, 2009, includes $1,218,000 and $785,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at March 31, 2010, and December 31, 2009, also includes $184,000 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 March 31, 2010, and December 31, 2009, includes $3,021,000 and $7,583,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts payable at March 31, 2010, and December 31, 2009, also includes $807,000 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 March 31, 2010 and 2009 of $159,000, and $298,000 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 March 31, 2010 and 2009 of $2,000 and $8,000, respectively.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings Field in Texas. Previously, GeoResources held a 2% general partner interest which increased after reaching a cumulative payout. As result of the sale of certain properties and subsequent distribution of proceeds by the Partnership cumulative payout was achieved and the Company’s general partner interest increased to 30%. For further information about the sale see Note B above. The Company recorded partnership income related to this investment for each of the three month periods ended March 31, 2010 and 2009 of $856,000 and $13,000, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at March 31, 2010 and December 31, 2009, was $820,000 and $846,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at March 31, 2010 and December 31, 2009 was $2,191,000 and $2,686,000, respectively.

The following is a summary of selected financial information of SBE Partners, LP for the three months ended March 31, 2010 and 2009 (in thousands):


	Three Months Ended March 31,
	2010		2009

Summary of Partnership Operations:
Revenues	$	5,943	$	11,839
Income from continuing operations	$	2,583	$	3,476
Net income	$	2,583	$	3,476

Item 2.

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

The following is Management’s Discussion and Analysis of significant factors that have affected certain aspects of our financial position and operating results during the periods included in the accompanying unaudited consolidated financial statements. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 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 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 and acquire, discover and develop commercial quantities of oil and gas reserves that can be produced at a profit, and assemble an oil and gas reserve base with a market value exceeding its acquisition, development and production costs.

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 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. The current volatile price environment for oil and natural gas is significant, and management cannot predict the prices that will be available during the life of our current business plan. Following is a brief outline of our current plans:

•

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;

•

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 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 with accuracy, management’s goal is to replace production and further increase our reserve base at an acquisition or finding cost that will yield attractive rates of return and increase shareholder value.

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

Oil and Gas Properties

We use the Successful Efforts method of accounting for oil and gas operations. Under this method, costs to acquire oil and gas properties, drill successful exploratory wells, drill and equip development wells and install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs are charged to operations as incurred. Depreciation, depletion and amortization (“DD&A”) of the capitalized costs associated with proved oil and gas properties are computed using the unit-of-production method, at the field level, based on proved reserves. Oil and gas properties are periodically assessed for impairment and generally written down to estimated fair value if the sum of estimated future undiscounted pretax cash flows, based on engineering and expected economic circumstances, is less than the carrying value of the asset. The fair value of impaired assets is generally determined using market values, if known, or using reasonable projections of production, prices and costs and discount rates commensurate with the risks involved.

Recent Property Acquisitions and Divestitures

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 subsequent leasehold acquisitions, as of April 2010 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 April 2010, the joint venture was running five 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 in the producing wells 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.

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 operated position. As of April 2010, we have acquired approximately 47,000 net leasehold acres. We intended to develop the acreage position with two industry partners and retain a 47.5% working interest. We expect to drill our first well in the prospect during late summer 2010.

Results of Operations

Three months ended March 31, 2010, compared to three months ended March 31, 2009

The Company recorded net income of $6,074,000 for the three months ended March 31, 2010 compared to net income of $477,000 for the same period in 2009. This $5,597,000 increase resulted primarily from the following factors:


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

Oil and gas sales	$	12,429
Lease operating expenses		(634	)
Production taxes		(989	)
Exploration expense		(384	)
Re-engineering and workovers		728
General and administrative expenses (“G&A”)		276
Depletion, depreciation and amortization expense (“DD&A”)		(1,883	)
Net interest income (expense)		(456	)
Hedge ineffectiveness		304
Gain (loss) on derivative contracts		39
Gain (loss) on sale of property		(1,254	)
Other income - net		838

Income before income taxes		9,014
Provision for income taxes		(3,417	)

Net income	$	5,597

The following discussion applies to the above changes.

Oil and Natural Gas Sales . Net revenues from oil and gas sales increased $12,429,000, or 101%. Increases in commodity prices accounted for $6,037,000 of the increase and increased production volumes accounted for the remaining $6,392,000. 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 490,000 Mcf and total revenues of $2,316,000 in the first quarter of 2010. Price and production comparisons are set forth in the following table.


	Percent increase (decrease)		Three Months Ended March 31
	Percent increase (decrease)		2010		2009
Gas Production (MMcf)	92	%		1,279		665
Oil Production (Mbbls)	41	%		249		177
Barrel of Oil Equivalent (MBOE)	60	%		462		288
Average Price Gas Before Hedge Settlements (per Mcf)	26	%	$	4.83	$	3.83
Average Price Oil Before Hedge Settlements (per Bbl)	101	%	$	74.21	$	36.89
Average Realized Price Gas (per Mcf)	36	%	$	5.61	$	4.12
Average Realized Price Oil (per Bbl)	31	%	$	70.62	$	54.00

Lease Operating Expenses. Lease operating expenses (“LOE”) increased from $4,390,000 in the first quarter of 2009 to $5,024,000 for the same period in 2010, an increase of $634,000 or 14%. On a unit-of-production basis, LOE actually decreased by $4.37 per BOE, or 29%, as a result changes in our property portfolio, re-engineering projects completed during 2008 and 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 $728,000, from $981,000 to $253,000, due to the completion of a major re-engineering and workover program in 2009.

Production Taxes . Production taxes increased by $989,000 or 125%, 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 quarter ended March 31, 2010 and 2009 were 7.2% and 8.8%, respectively, of oil and gas sales before the effects of hedging. The 2010 rate decreased from 2009 due to a change in our portfolio of producing properties as well as obtaining severance tax exemptions for certain high cost gas wells.

General and Administrative Expenses. G&A decreased $276,000 due primarily to cost containment measures, partially offset by increases in personnel costs. The total non-cash charges related to stock-based compensation included in G&A expense for the three month periods ended March 31, 2010 and 2009 were $219,000 and $265,000, respectively.

Depreciation, Depletion and Amortization . DD&A expense increased by $1,883,000 or 42%, 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.

Interest Income and Expense . Interest expense increased by $454,000 due to higher debt levels in the first quarter of 2010 compared to the same period in 2009. For the three months ended March 31, 2010, average outstanding debt was $69,000,000 compared to $40,000,000 for the same period in 2009. Interest income decreased by $2,000 in the first quarter of 2010 compared to the same period of 2009.

Hedge Ineffectiveness . In the first quarter of 2010 the gain from hedge ineffectiveness was $255,000, compared to a loss of $49,000 for the same period in 2009. During the first 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 first quarter of 2010, we recognized cash settlement losses of $100,000, offset by mark-to-market gains of $87,000. In the first quarter of 2009,

we recognized cash settlement losses on the $10 million swap of $94,000, offset by mark-to-market gains of $42,000.

Other Income . Other income increased by $838,000 in the first quarter of 2010 compared to the same period in 2009 due primarily to increases in partnership income of $849,000. 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. The increase in partnership income was offset by decreases in partnership management fees and property operating income. Additionally, in the first quarter of 2009 we had a net gain on sales of properties and other assets of $1,399,000 versus $145,000 in the same period of 2010.

Income Tax Expense . Income tax expense for the first quarter of 2010 was $3,777,000 compared to $360,000 for the same period in 2009. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate during the first quarter of 2010 was approximately 38% versus 43% in the same period during 2009. During the first quarter of 2009 our effective tax rate was increased to 43% as a result of the qualified stock options coupled with lower earnings. The expense related to these options is not deductible in determining taxable income.

Impact of Changing Prices and Costs

Our revenues and the carrying value of our oil and gas properties are subject to significant change due to changes in oil and gas prices. Also, as demonstrated historically, prices are 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 quarter of 2010. Average realized oil prices of $70.62 per Bbl, net of hedges, for the three months ended March 31, 2010, were 31% higher than for the comparable period in 2009. Average realized natural gas prices of $5.61 per Mcf, net of hedges, for the three months ended March 31, 2010, were 36% higher than for the comparable period in 2009. The average realized prices for the three months ended March 31, 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.

For example, due to low natural gas prices in mid-2009 we suspended drilling activity on our Giddings field, Texas, and our natural gas production recently peaked during the fourth quarter of 2009 and decreased approximately 15% in the first quarter of 2010 compared to the last quarter of 2009. However, with the advent of higher natural gas prices in the fall of 2009 we recommenced drilling in the Giddings field, and we expect the new resulting production to replace the recent decline in our natural gas production and production to continue to increase above all prior levels.

Hedging Activities

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

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

(1)

Secure and maintain favorable debt financing terms;

(2)

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

(3)

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

(4)

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

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

Administrative and Operating Costs

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

Liquidity and Capital Resources

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

Credit Facility

As of March 31, 2010, our borrowing base under our credit facility with Wells Fargo Bank was $145 million and our outstanding balance was $69 million. 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.

Cash Flows from Operating Activities

For the three months ended March 31, 2010, our net cash provided by operating activities was $17.5 million, versus operating activities requiring cash of $3.9 million from 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 three months ended March 31, 2010 and 2009, was $12.7 million and $5.1 million, respectively. In addition, cash generated from the sale of oil and gas properties for the three months ended March 31, 2010 and 2009 was $503,000 and $2.0 million, respectively. Capital expenditures for 2010 were financed with working capital. We expect to spend approximately $90 million to $100 million in additional capital expenditures during the remainder of 2010 and 2011.

Capital Budget

As of December 31, 2009, we had identified approximately $160 million of diversified exploration and development projects, which are summarized in the table below. From this list of identified projects, we currently have budgeted capital expenditures of $90 million to $100 million for 2010 and 2011. While the table includes the bulk of our currently identified projects, we are constantly working on developing and acquiring new opportunities. In addition, seismic and acreage expenditures as well as drilling results will likely lead to modifications of our estimates. 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 are committed to limiting our capital spending to 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 and take advantage of regional differences in net commodity prices and service costs. Furthermore, our budget may be accelerated or deferred, pending commodity prices, drilling and service rig availability and cost, and adequate staffing to effectively manage activities and control costs. While financial conditions, 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.

The projects, estimated costs and timing of actual expenditures are subject to significant change as we continue to technically and economically evaluate existing and alternative projects, as we further expand our portfolio, and as industry conditions dictate. Estimated expenditures are also subject to significant change. There can be no assurance that all of the projects identified and summarized in the table below will remain 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	59	%
Other development drilling ⁽²⁾		17.6	20	%
Exploratory drilling ⁽³⁾		7.7	9	%
Acreage, seismic and other ⁽⁵⁾		7.0	8	%
Re-engineering ⁽⁴⁾		2.5	3	%
Waterflood expansion ⁽²⁾		1.0	1	%

		86.7
Northern District
Bakken Shale drilling ^{(6) (2)}	$	39.5	54	%
Other development drilling ⁽²⁾		22.6	31	%
Acreage, seismic and other ⁽⁵⁾		7.0	10	%
Waterflood and associated drilling ⁽²⁾		3.2	4	%
Re-engineering ⁽⁴⁾		1.0	1	%

		73.3

Total	$	160.0

Notes :

(1)

Horizontal drilling and development program with an affiliated institutional partnership. As of December 31, 2009, we identified 22 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.

(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 within close proximity of our existing fields.

(6)	The estimates included above relate to both our operated and non-operated positions in the Bakken Shale play of the Williston Basin. This is one of our core areas and the Bakken trend is experiencing rapid expansion and development. Pursuant to our business strategy, we have

expanded our acreage positions and increased our working interests. 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. The nature of this play and its rapid expansion make estimates particularly difficult to determine with reasonable certainty and therefore this estimate is subject to material change.

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 March 31, 2010:

Transaction Date

Transaction

Type

Beginning

Ending

Price Per

Unit

Remaining

Annual Volumes

Fair Value
Outstanding

as of
March 31,

2010

(in thousands)

Natural Gas

October-07

Collar

01/01/10

12/31/10

$7.00 - $9.90

965,250 Mmbtu

$2,662

October-07

Collar

01/01/11

12/31/11

$7.00 - $9.20

1,079,000 Mmbtu

1,972

June-09

Swap

01/01/10

12/31/10

$5.155

1,080,000 Mmbtu

992

June-09

Swap

01/01/10

12/31/10

$5.195

360,000 Mmbtu

345

December-09

Swap

04/01/10

03/31/11

$6.065

570,000 Mmbtu

847

December-09

Swap

04/01/11

03/31/12

$6.450

780,000 Mmbtu

784

December-09

Swap

04/01/12

12/31/12

$6.415

450,000 Mmbtu

328

7,930

Crude Oil

October-07

Swap

01/01/10

12/31/10

$74.71

241,500 Bbls

(2,473)

October-07

Swap

01/01/11

12/31/11

$74.37

282,000 Bbls

(3,306)

January-10

Swap

02/01/10

12/31/10

$85.32

90,000 Bbls

January-10

Swap

01/01/11

12/31/11

$88.45

84,000 Bbls

166

(5,587)

Interest Rate

Oct-07/Dec-09

Swap

10/10/07

10/16/10

4.29375%

$40 Million Notional

30-day LIBOR

(953)

Oct-07/Dec-09

Swap

12/16/08

10/16/10

4.29375%

$10 Million Notional

30-day LIBOR

(238)

(1,191)

$1,152

Item 4.

Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our Chief Executive Officer, Chief Financial Officer and other members of management evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of March 31, 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 March 31, 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 March 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 1A.

Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1- Risk Factors” in our 2009 Annual Report on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2009 Annual Report on Form 10-K may not be the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.


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

Item 6.

Exhibits

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended March 31, 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 475-17 ^th Street, CO. and Collis P. Chandler III for 475 17th Street Building, Suite 860, 475 17th Street, Denver, Colorado 80202. (3)

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

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

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



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

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

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

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

10.34		Form of Purchase Agreement. (4)

10.35		Form of Warrant. (4)

10.36		Form of Registration Rights Agreement. (4)

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

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

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

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.

SIGNATURES

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


		GEORESOURCES, INC.

May 7, 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)