GEOI Georesources, Inc. (MM)

Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-QSB

 

 

 

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

For the Quarterly Period ended March 31, 2008

 

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

Commission File Number – 0-8041

 

 

GEORESOURCES, INC.

(Exact name of small business issuer 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)

(281) 537-9920

(Issuer’s telephone number)

 

 

Check whether the Issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the Issuer 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 checkmark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act.    Yes   ¨     No   x

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date:

 

Class of equity		Outstanding at May 12, 2008
Common stock, par value $.01 per share		14,703,383 shares

Transitional Small Business Disclosure Format (check one):    YES   ¨     NO   x

 

 

 

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TABLE OF CONTENTS

 

PART I.		FINANCIAL INFORMATION
Item 1.		Financial Statements
		CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED):
		Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007		3
		Consolidated Statements of Operations for the Three Months ended March 31, 2008 and 2007		4
		Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the Three Months ended March 31, 2008		5
		Consolidated Statements of Cash Flows for the Three Months ended March 31, 2008 and 2007		6
		Notes to Consolidated Financial Statements		7
Item 2.		Management’s Discussion and Analysis or Plan of Operation		14
Item 3.		Controls and Procedures		20
PART II.		OTHER INFORMATION
Item 1.		Legal Proceedings		21
Item 6.		Exhibits		21

 

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Item 1 - Financial Statements

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

		March 31, 2008				December 31, 2007
		(unaudited)
ASSETS
Current assets:
Cash		$	17,163,949			$	24,430,181
Accounts receivable:
Oil and gas revenues			23,125,008				20,365,111
Joint interest billings and other			5,074,769				3,913,461
Affiliated partnerships			3,745,134				3,360,017
Notes receivable			120,000				600,000
Oil and gas properties held for sale			9,694,654				—
Prepaid expenses and other			1,902,159				1,430,445
Total current assets			60,825,673				54,099,215
Oil and gas properties, successful efforts method:
Proved properties			176,537,239				187,640,420
Unproved properties			6,872,150				5,139,309
Office and other equipment			1,031,375				995,365
Land			96,462				96,462
			184,537,226				193,871,556
Less accumulated depreciation, depletion and amortization			(14,568,762	)			(12,430,174	)
Net property and equipment			169,968,464				181,441,382
Other assets:
Equity in oil and gas limited partnerships			2,003,514				1,880,361
Deferred financing costs and other			3,019,951				2,937,312
		$	235,817,602			$	240,358,270
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	8,394,747			$	11,374,221
Accounts payable to affiliated partnerships			5,298,816				4,271,238
Revenues and royalties payable			23,275,950				19,833,732
Drilling advances			542,876				882,367
Accrued expenses			2,563,241				2,599,915
Income taxes payable			1,211,456				1,239,172
Derivative financial instruments			12,659,158				6,527,360
Total current liabilities			53,946,244				46,728,005
Long-term debt			86,000,000				96,000,000
Deferred income taxes			7,643,752				6,476,433
Asset retirement obligations			5,140,372				7,826,856
Derivative financial instruments			22,718,164				15,295,948
Stockholders’ equity:
Common stock, par value $.01 per share; authorized 100,000,000 shares; 14,703,383 shares issued and outstanding			147,034				147,034
Additional paid-in capital			79,838,738				79,689,720
Accumulated other comprehensive income (loss)			(31,345,975	)			(19,310,316	)
Retained earnings			11,729,273				7,504,590
Total stockholders’ equity			60,369,070				68,031,028
		$	235,817,602			$	240,358,270

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

 

		Three Months Ended March 31,
		2008			2007
Revenue:
Oil and gas revenues		$	22,462,739		$	3,537,494
Partnership management fees			312,474			155,636
Property operating income			314,271			237,758
Gain on sale of property and equipment			409,754			—
Partnership income			225,193			59,746
Interest and other			222,504			126,923
Total revenue			23,946,935			4,117,557
Expenses:
Lease operating expense			5,791,117			1,060,409
Severance taxes			1,889,467			268,942
Re-engineering and workovers			697,163			78,187
General and administrative expense			1,783,588			827,717
Depreciation, depletion and amortization			3,876,949			928,568
Hedge ineffectiveness			1,518,355			4,030
Interest			1,569,175			156,152
Total expense			17,125,814			3,324,005
Income before income taxes			6,821,121			793,552
Income taxes:
Current			1,429,119			1,862
Deferred			1,167,319			2,340
			2,596,438			4,202
Net income		$	4,224,683		$	789,350
Net income per share (basic and diluted)		$	0.29		$	0.15
Weighted average shares outstanding (basic and diluted)			14,703,383			5,378,893

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. and SUBSIDIARIES

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

Three Months Ended March 31, 2008

(unaudited)

 

		Common Stock					Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (loss)				Total
		Shares		Par value
Balance, December 31, 2007		14,703,383		$	147,034		$	79,689,720		$	7,504,590		$	(19,310,316	)		$	68,031,028
Comprehensive income (loss):
Net income											4,224,683							4,224,683
Change in fair market value of hedged positions														(14,066,181	)			(14,066,181	)
Net realized hedging losses charged to income														2,030,522				2,030,522
Total comprehensive income (loss)																		(7,810,976	)
Equity based compensation expense								149,018										149,018
Balance, March 31, 2008		14,703,383		$	147,034		$	79,838,738		$	11,729,273		$	(31,345,975	)		$	60,369,070

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

 

		Three Months Ended March 31,
		2008				2007
Cash flows from operating activities:
Net income		$	4,224,683			$	789,350
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			3,876,949				928,568
Gain on sale of property and equipment			(409,754	)			—
Accretion of asset retirement obligations			130,998				25,892
Hedge ineffectiveness loss			1,518,355				4,030
Partnership income			(225,193	)			(59,746	)
Partnership distributions			102,040				—
Deferred income taxes			1,167,319				2,340
Non-cash compensation			149,018				104,067
Changes in assets and liabilities:
Increase in accounts receivable			(4,306,322	)			(8,022,059	)
Decrease in notes receivable			480,000				—
Increase in prepaid expense and other			(554,353	)			(58,772	)
Increase in accounts payable and accrued expenses			1,086,441				9,759,955
Net cash provided by operating activities			7,240,181				3,473,625
Cash flows from investing activities:
Proceeds from sale of property and equipment			8,532,154				—
Additions to property and equipment			(13,038,567	)			(6,914,750	)
Investment in oil and gas limited partnership			—				(1,631,860	)
Net cash used in investing activities			(4,506,413	)			(8,546,610	)
Cash flows from financing activities:
Issuance of common stock			—				5,000,000
Distributions to stockholders			—				(62,235	)
Issuance of long-term debt			—				3,000,000
Reduction of long-term debt			(10,000,000	)			—
Net cash provided by (used in) financing activities			(10,000,000	)			7,937,765
Net increase (decrease) in cash and cash equivalents			(7,266,232	)			2,864,780
Cash and cash equivalents at beginning of period			24,430,181				6,216,822
Cash and cash equivalents at end of period		$	17,163,949			$	9,081,602
Supplementary information:
Interest paid		$	1,583,807			$	101,250
Income taxes paid		$	1,762,383			$	—

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

NOTE A: Organization and Summary of Significant Accounting Policies

Merger

On April 17, 2007, pursuant to the terms of an Agreement and Plan of Merger (“Merger Agreement”), GeoResources, Inc. (“GeoResources” or the “Company”), a Colorado corporation, acquired Southern Bay Oil & Gas, L.P. (“Southern Bay”), a Texas limited partnership, PICA Energy, LLC (“PICA”), a Colorado limited liability company and subsidiary of Chandler Energy LLC, and certain oil and gas properties in exchange for 10,690,000 shares of common stock (the “Merger”). These transactions resulted in a change in stockholder control of the Company. As a result of the Merger, the former Southern Bay partners received a majority of the outstanding common stock of the Company and thus, obtained voting control of the Company. Accordingly, for financial reporting purposes, the Merger was accounted for as a reverse acquisition of GeoResources and PICA by Southern Bay. Therefore, the results of operations and cash flows as presented herein for the three months ended March 31, 2008 are those attributable to the combined entities. The results of operations and cash flows for the three months ended March 31, 2007 are those attributable to the former Southern Bay entity.

Organization and Basis of Presentation

GeoResources 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, Louisiana, North Dakota, Montana and Colorado. The accompanying consolidated financial statements include the accounts of our wholly-owned subsidiaries. All events described or referred to as prior to April 18, 2007, relate to Southern Bay as the accounting acquirer.

The financial statements included herein have been prepared by the Company without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the statements reflect all adjustments (which consist solely of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, the Company believes that the disclosures are adequate to make the information not misleading. For further information regarding the Company’s accounting policies, please read the audited consolidated financial statements included in the Company’s Form 10-KSB/A for the year ended December 31, 2007.

NOTE B: Acquisitions and Sales

Merger

The net assets of the acquired GeoResources and PICA as well as certain oil and gas properties were recorded at fair value using the purchase method of accounting, as required by generally accepted accounting principles. Such net assets consisted of cash and other current assets and liabilities, oil and gas properties, certain mineral leases and options, and debt. The fair value of the net assets acquired in these purchases was based on the average trading price of GeoResources common stock immediately before and after the public announcement of the Merger Agreement, of $6.29 per share.

AROC Energy Acquisition

On October 16, 2007, the Company, through a wholly-owned subsidiary, entered into an agreement to purchase (“Purchase Agreement”) all of the limited partnership interest in AROC Energy, L.P., an affiliated limited partnership for which the Company served as general partner. The limited partner was an unaffiliated entity. Prior to this transaction, the Company owned 2% of the partnership and the limited partner owned the remaining 98%. The Acquisition, which was accounted for as a purchase, included oil and gas properties located in Louisiana, the Gulf Coast, South Texas, the Permian Basin and the Black Warrior Basin.

Under the Purchase Agreement, the Company purchased the interest for a cash purchase price of $91,100,000 (the “Purchase Price”) and paid $12,952,000 to cancel the Limited Partnership’s oil and gas hedge contracts. These costs were funded with cash of $8,052,000 and borrowings of $96 million under the Amended Credit Agreement discussed in Note F. The Company also paid its bank a fee of $1,250,000 in connection with the acquisition. The purchase of the interest was effective on the date of closing of the Purchase Agreement, October 16, 2007, and resulted in the Company’s total ownership percentage of 100% of the Limited Partnership. In November 2007, the Company dissolved the Limited Partnership.

 

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Pro Forma Results of Operations

The following summary presents unaudited pro forma information for the three month period ended March 31, 2007 as if the Merger and Acquisition had been consummated at January 1, 2007 respectively (in thousands except share data).

Three months ended March 31, 2007

 

		2007
Total revenue		$	13,521
Income before income taxes		$	2,543
Net income		$	1,925
Net income per share:
basic & diluted		$	0.13
Weighted average shares outstanding			14,572,977

Other Acquisitions and Sales

In January 2007, Southern Bay formed two entities in connection with the acquisition of producing oil and gas properties located in southeast Texas. Catena Oil & Gas LLC (“Catena”) was formed as an indirect wholly-owned subsidiary of Southern Bay and SBE Partners LP (“SBE”) was formed with Catena as general partner with a 2% partnership interest, and a large institutional investor as the sole limited partner with a 98% partnership interest. In February, 2007 these entities paid cash of $82 million to acquire certain southeast Texas properties. Catena purchased 8% of the interests and SBE purchased the remaining 92%. Catena’s share of the property purchase price was $6.6 million, and its general partner contribution to SBE was $1.6 million. Southern Bay funded these amounts with additional capital contributions from its partners of $5 million, borrowings under its bank credit agreement of $3 million and working capital of $200,000. The Company’s investment in SBE is accounted for under the equity method of accounting.

In January 2008, the Company sold all of its interest in the Grand Canyon Unit, a property acquired in the Merger. This property, located in Otsego County, Michigan, was sold to an unaffiliated party for $6.6 million in cash. The carrying value of this property at the date of the sale was equal to the selling price; therefore, no gain or loss was recognized on this sale.

In February 2008, the Company acquired producing properties from an unaffiliated party in the Williston Basin of North Dakota and Montana for $7.9 million in cash. The acquired properties will be operated by the Company. The purchase price was allocated to oil and gas properties.

In February 2008, the Company sold its interests in certain oil and gas properties to unaffiliated parties for $1.8 million and recognized gains of $430,000.

NOTE C: Oil and Gas Properties Held for Sale

At March 31, 2008, the Company had pending sales involving six producing oil and gas properties located in Louisiana and Texas. Accordingly, the net carrying value of these properties of $9,695,000 is reflected in current assets in the accompanying consolidated balance sheet.

NOTE D: Recent Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement No. 161, Disclosure about Derivative Instruments and Hedging Activities – an amendment to FASB Statement No. 133 (“SFAS 161”). The adoption of SFAS 161 is not expected to have an impact on the Company’s consolidated financial statements, other than additional disclosures. SFAS 161 expands interim and annual disclosures about derivative and hedging activities that are intended to better convey the purpose of derivative use and the risks managed. SFAS is effective for fiscal years and interim periods beginning after November 15, 2008.

In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 (“SFAS 160”). This statement amends ARB No. 51 and intends to improve the

 

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relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards on the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent. SFAS 160 is effective for fiscal years, and interim periods, beginning on or after December 15, 2008. The Company is currently evaluating the impact SFAS 160 will have on its consolidated financial statements.

In December 2007, the FASB issued Statement No. 141R, Business Combinations (“SFAS 141R”). SFAS 141R may have an impact on the Company’s consolidated financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms, and size of the acquisitions that the Company consummates after the effective date. SFAS 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements, the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The statement also provides guidance for recognizing and measuring goodwill acquired in business combinations and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of business combinations. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008.

NOTE E: Income Taxes

Three Months Ended March 31, 2008 and 2007

Income tax expense for the first quarter of 2008 was $2,596,000 compared to $4,000 for the same period in 2007. As previously stated, the 2007 financial statements, as presented herein, are those of Southern Bay, which, as a Texas partnership, was only subject to the Texas Margin Tax and was not generally subject to federal and state income taxes.

FIN 48-Uncertain Tax Positions

The Company did not have any unrecognized tax benefits and there was no effect on its financial condition or results of operations as a result of implementing FIN 48. The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.

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

The Company’s continuing practice is to recognize estimated interest and penalties, if any, related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated Statement of Operations. As of the date of adoption of FIN 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current quarter. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2009.

NOTE F: Long-Term Debt

On September 26, 2007, the Company entered into a Credit Agreement with Wachovia Bank (the “Bank”), as Administrative Agent and Issuing Bank and the Bank and U.S. Bank as Lenders. This agreement provided for a Senior Secured Revolving Credit Facility in the maximum amount of $100 million, with an initial borrowing base of $35 million.

On October 16, 2007, the Company entered into an Amended and Restated Credit Agreement (“Amended Credit Agreement”) with the Bank as Administrative agent, Issuing Bank, Sole Lead Arranger and Sole Bookrunner. This agreement provides financing of up to $200 million to the Company. The initial borrowing base of the Amended Credit Facility was $110 million, subject to redetermination on June 1 and December 1 of each year. As of March 31, 2008, the borrowing base had been reduced to $95 million due to the anticipated sales of oil and gas properties. The amounts borrowed under this Amended Credit Agreement bear interest at either (a) the London Interbank Offered Rate (“LIBOR”) plus 1.50% to 2.25% or (b) the prime lending rate of the Bank plus .5% to 1.25%, depending on the amount borrowed under the Amended Credit Agreement. Principal amounts outstanding under this Amended Credit Agreement are due and payable in full at maturity on October 16, 2010. The Amended Credit Agreement also requires the payment of commitment fees to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.375% to 0.50% per year depending on the amount of borrowing base utilization. The Company is also required to pay customary letter of credit fees. All of the obligations under the Amended Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. The Amended Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase its capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the Amended Credit Agreement requires the maintenance of certain financial ratios, contains customary affirmative covenants and provides for events of default.

 

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On October 16, 2007, the Company borrowed $96 million under the Amended Credit Agreement, in connection with the acquisition discussed in Note B. The Company also paid the Bank transaction fees of $1.25 million as well as underwriting fees and other loan costs totaling $1.25 million. At March 31, 2008, the outstanding principal balance was $86.0 million. The interest rate in effect at March 31, 2008 was 6.06% on $50,000,000 of outstanding principal and 4.56% on the remaining $36,000,000 of principal.

Also, in October 2007, the Company entered into an interest rate swap agreement with the Bank, providing a fixed rate of 4.34% on a notional $50,000,000 through October 16, 2010. As of March 31, 2008, the Company has recorded a liability of $2,226,796, of which $876,116 is current, related to this hedge. The fair market value of the interest rate swap at December 31, 2007 was a liability of $853,945, of which $476,620 was classified as a current liability.

At March 31, 2008, accumulated other comprehensive loss included $2,226,796 of unrecognized losses, representing the inception to date change in mark-to-market value of the Company’s interest rate swap, designated as a hedge, as of the balance sheet date. For the quarter ended March 31, 2008, the Company recognized realized cash settlement gains of $55,423 related to this swap. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at March 31, 2008, the Company expects to reclassify net losses of $876,116 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

NOTE G: Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration, in accordance with applicable local, state and federal laws. In accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), the Company determines its obligation by calculating the present value of estimated cash flows related to plug and abandonment obligations. The following table provides a reconciliation of the Company’s Asset Retirement Obligation for the three months ended March 31, 2008:

 

Asset retirement obligation, January 1, 2008		$	7,826,856
Additional liabilities incurred			84,131
Accretion expense			130,998
Obligations on sold properties			(69,540	)
Transferred liabilities associated with properties held for sale			(2,832,073	)
Asset retirement obligation, March 31, 2008		$	5,140,372

NOTE H: 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 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. The Company does not enter into derivative instruments for speculative or trading purposes.

At March 31, 2008, accumulated other comprehensive loss consisted of $29,119,179 of unrecognized losses, 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. For the quarter ended March 31, 2008, the Company recognized realized cash settlement losses of $2,085,945 on commodity derivative settlements. For the quarter ended March 31, 2007, the Company recognized realized losses of $319,734 on commodity derivative settlements. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at March 31, 2008, the Company expects to reclassify net losses of $11,783,042 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially. At March 31, 2008, the Company had hedged its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:

 

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		Total Annual Volume		Floor Price			Ceiling/ Swap Price
Crude Oil Contracts (Bbls.):
Swap contracts:
2008		235,500					$	80.19
2009		368,500					$	76.00
2010		322,000					$	74.71
2011		282,000					$	74.37
Costless collar contracts:
2008		90,000		$	65.00		$	75.10
Natural Gas Contracts (Mmbtu):
Swap contracts:
2009		779,268					$	4.785
2009		427,200					$	5.61
Costless collar contracts (Mmbtu):
2008		90,000		$	8.00		$	8.45
2008		1,227,749		$	7.00		$	9.80
2009		275,532		$	7.00		$	10.75
2010		1,287,000		$	7.00		$	9.90
2011		1,079,000		$	7.00		$	9.20

The fair market value of these hedge contracts at March 31, 2008 was a liability of $33,150,526, of which $11,783,042 was classified as a current liability. The fair market value of these hedge contracts at December 31, 2007 was a liability of $20,696,363, of which $6,050,740 was classified as a current liability. The Company recognized a loss of $1,518,355 due to hedge ineffectiveness on these hedge contracts for the three months ended March 31, 2008, compared to a loss of $4,030 for the same period in 2007.

The Company has also entered into an interest rate swap designated as a fair value hedge as discussed in Note F above.

NOTE I: Fair Value Disclosures

SFAS 157 – Effective January 1, 2008, the Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of SFAS 157 did not cause a change in the method of calculating fair value assets or liabilities. The primary impact from adoption was additional disclosures.

The Company elected to implement SFAS 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2 Effective Date of FASB No. 157 (“FSP 157-2”), issued February 2008, which defers the effective date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. As it relates to the Company, the deferral applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value, impaired oil and gas property assessments, and the initial recognition of asset retirement obligations for which fair value is used.

Fair Value Hierarchy – SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

 

•

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

 

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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. The following table presents information about the Company’s liabilities measured at fair value on a recurring basis as of March 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

 

		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, 2008
Current portion of derivative financial instrument liability (1)		—		$	12,659,158		—		$	12,659,158
Long-term portion of derivative financial instrument liability (2)		—		$	22,718,164		—		$	22,718,164

 

(1)	Includes Interest Rate Swap ($876,116) and Commodity Derivative Instruments ($11,783,042)

(2)	Includes Interest Rate Swap ($1,350,680) and Commodity Derivative Instruments ($21,367,484)

The Company does not have any assets measured at fair value on a recurring basis as of March 31, 2008.

The following methods and assumptions were used to estimate the fair values of the liabilities in the table above:

Commodity Derivative Instruments – 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.

Interest Rate Swap – The Company’s interest rate swap is valued using the counterparty’s mark-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 Company has no assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3.

SFAS 159 – In February 2007, the FASB issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No 115 (“SFAS 159”). SFAS 159 expands the use of fair value accounting but does not affect existing standards which require assets or liabilities to be carried at fair value. On January 1, 2008, the Company adopted SFAS 159 and decided not to elect fair value accounting for any of its eligible items. The adoption of SFAS 159 therefore had no impact on the Company’s consolidated financial position, cash flows or results of operations. If the use of fair value is elected in the future (the fair value option), however, any upfront costs and fees related to the item must be recognized in earnings and cannot be deferred, e.g., debt issue costs. The fair value election is irrevocable and generally made on an instrument-by-instrument basis, even if a company has similar instruments that it elects not to measure based on fair value. Subsequent to the adoption of SFAS 159, changes in fair value are recognized in earnings.

 

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NOTE J: Stock Options, Performance Awards and Stock Warrants

On October 10, and November 15, 2007, the Company granted options to officers and employees to purchase 755,000 and 10,000 shares of common stock, respectively. These shares were granted pursuant to the GeoResources, Inc. Amended and Restated 2004 Employees’ Stock Incentive Plan. The following is a summary of the terms of these options:

 

Vesting date		Number of shares		Exercise Price per share
October 10, 2009		377,500		$	8.27
November 15, 2009		5,000		$	8.65
October 10, 2010		188,750		$	9.56
November 15, 2010		2,500		$	9.56
October 10, 2011		188,750		$	9.56
November 15, 2011		2,500		$	9.56
Total shares		765,000

The closing market prices of the Company’s common stock on the date of the October and November grants were $7.20 and $8.65 respectively.

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

The Company accounts for these stock options under the provisions of Statement of Financial Accounting Standards No. 123R, “Share Based Payment” and, accordingly, recognized compensation expense associated with these options during the first quarter of 2008 of $149,018.

NOTE K: Related Party Transactions

In July 2007, the Company acquired oil and gas properties from officers and key employees for $1,075,079, including cash of $856,459 and the issuance of 30,406 shares of common stock at $7.19 per share. Also, in July 2007, the Company issued 100,000 shares of common stock for cash of $719,000 to three individuals, including two members of the board of directors and an affiliate of one of our directors.

Accounts receivable at March 31, 2008 and December 31, 2007 includes $3,745,134 and $3,360,017 respectively, due from SBE Partners LP (“SBE Partners”), an oil and gas limited partnership for which a subsidiary of the Company serves as general partner. These amounts represent the limited partnership’s 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, 2008, and December 31, 2007, includes $5,298,816 and $4,271,238, respectively, due to the limited partnership for oil and gas revenues collected on their behalf.

The Company earned partnership management fees during the three month periods ended March 31, 2008, and 2007 of $312,474 and 155,636, respectively.

Subsidiaries of the Company operate most oil and gas properties in which the limited partnership has an interest. Under this arrangement, the Company collects revenues from purchasers and incurs property operating and development expenditures on the partnership’s behalf. Monthly, these revenues are paid to the partnership, which in turn reimburses the Company for its share of expenditures.

 

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Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

The following discussion should be read in conjunction with the unaudited consolidated financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-QSB and should further be read in conjunction with our Annual Report on Form 10-KSB/A for the year ended December 31, 2007.

Forward-Looking Information

This Quarterly Report on Form 10-QSB, and in particular this “Item 2. Management’s Discussion and Analysis or Plan of Operation”, contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by words such as “may,” “will,” “expect,” “anticipate,” “estimate” or “continue,” or comparable words. All statements other than statements of historical facts included in this quarterly report and this section of this report, including, without limitation, statements regarding the 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 of the Company 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-KSB/A for the year ended December 31, 2007. 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.

Merger-Change in Management, Control and Business Strategy

On April 17, 2007, the Company completed certain merger transactions (“Merger”) among the Company, Southern Bay and PICA. The Merger provided, in substance, for the mergers of the businesses of Southern Bay and PICA, two independent oil and gas entities, into the Company, and further included working interests in oil and gas properties. A total of 10,690,000 shares of the Company’s common stock were issued in connection with the Merger. Prior to the Merger, neither Southern Bay nor PICA nor any of their owners or affiliates had any material relationship with the Company or any of its associates, or any director or officer of the Company, or any affiliate of any such director or officer. The Merger resulted in a change of control of the Company as its board of directors and executive officers consist mostly of persons formerly affiliated with Southern Bay and PICA.

Under generally accepted accounting principles, Southern Bay was deemed to have acquired the Company, PICA and certain oil and gas properties. Southern Bay accounted for the transactions using the purchase method of accounting for business combinations. Accordingly, the historical financial statements presented for the Company are those of Southern Bay, back to its inception in 2004, with the Company, PICA and the property treated as purchased upon closing.

General

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, currently focused in Texas, Louisiana, North Dakota, Montana and Colorado. As further discussed herein, future growth in assets, earnings, cash flows and share values are dependent upon our ability to acquire, discover and develop commercial quantities of oil and gas reserves that can be produced at a profit and assemble an oil and gas reserve base with a market value exceeding its acquisition, development and production costs.

We continue to implement our business strategy to acquire, discover and develop oil and gas reserves and achieve continued growth. Management continues to focus on reducing operating and administrative costs on a per unit basis. In addition, we have attempted to mitigate downward price volatility by the increased use of commodity price hedging, and have placed an increased emphasis on development drilling and exploration. The current high oil and gas price environment is unprecedented, and management cannot predict that these historically high prices will be available on an ongoing basis. Following is a brief outline of our current plans.

 

(1)

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

 

(2)

Solicit industry or institutional partners, on a promoted basis for selected acquisitions, in order to diversify, reduce average cost and generate operating fees.

 

(3)

Implement re-engineering and development programs within existing fields.

 

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(4)

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

 

(5)

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

 

(6)

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

 

(7)

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 as a means of continued growth, increasing value and creating liquidity for our equity holders. Management believes that opportunities may become available to acquire corporate entities or otherwise effect business combinations. The primary financial considerations in the evaluation of any such potential transaction 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 Acquisition

As more fully discussed in Note B to the consolidated financial statements in Part I of this Form 10-QSB, on October 16, 2007, we acquired the limited partnership interest in an affiliated limited partnership from a non affiliated limited partner for $91.1 million. As a result, we then owned 100% of this limited partnership which held oil and gas property interests in Louisiana, the Gulf Coast, South Texas, the Permian Basin and the Black Warrior Basin. We subsequently dissolved the partnership and integrated the oil and gas properties into our exiting operations. As part of our ongoing property review, we divested certain properties and intend to divest certain additional properties that no longer meet our primary objectives.

In January 2007, we acquired properties located in the Giddings Field of the Austin Chalk trend of Texas. In conjunction with this acquisition, a partnership was formed with a large institutional investor as limited partner. A wholly-owned subsidiary of the Company acquired both a direct 8% working interest and a 2% general partner interest in this partnership. Our share of the acquisition purchase price of $82 million was $6.6 million, and our general partner contribution was $1.6 million. These amounts were funded with additional capital contributions of $5 million from former Southern Bay partners, borrowings under our bank credit agreement of $3 million and working capital of $196,000.

In February 2008, we acquired producing properties located in the Williston Basin of North Dakota and Montana for a purchase price of $7.9 million. The properties will be operated by the Company.

 

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Results of Operations

Three months ended March 31, 2008, compared to three months ended March 31, 2007

The Company recorded net income of $4,224,683 and $789,350 for three months ended March 31, 2008 and 2007, respectively. This $3,435,333 increase in net income resulted primarily from the following factors:

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

 

Oil and gas sales		$	18,925
Lease operating expenses			(4,731	)
Production taxes			(1,621	)
Re-engineering and workovers			(619	)
General and administrative expenses (“G&A”)			(956	)
Depletion, depreciation and amortization expense (“DD&A”)			(2,948	)
Net interest income (expense)			(1,317	)
Hedge ineffectiveness			(1,514	)
Other income - net			808
Income before income taxes			6,027
Provision for income taxes			(2,592	)
Net income		$	3,435

The following discussion applies to the changes shown above.

Net revenues from oil and gas sales increased $18,925,000, or 535%. Properties acquired in the Merger and from AROC Energy LP accounted for $3,185,000 and $13,133,000 of the increase, respectively. The remaining $2,607,000 increase resulted from production increases due to re-engineering and workovers, as well as to increased commodity prices. Price and production comparisons are set forth in the following table. Properties acquired in the Merger accounted for increased production of approximately 57,000 Mcf of gas and approximately 36,000 barrels of oil during the first quarter of 2008. Properties acquired from AROC Energy LP accounted for increased production of approximately 420,000 Mcf of gas and approximately 108,000 barrels of oil during the first quarter of 2008.

 

		Percent increase			Three Months Ended March 31,
		(decrease)			2008			2007
Gas Production (MMcf)		321	%			809			192
Oil Production (MBbls)		335	%			200			46
Barrel of oil equivalent (MBOE)		329	%			335			78
Average Price Gas Before Hedge Settlements (per Mcf)		20	%		$	7.75		$	6.48
Average Price Oil Before Hedge Settlements (per Bbl)		60	%		$	91.37		$	57.20
Average Realized Price Gas (per Mcf)		27	%		$	7.73		$	6.10
Average Realized Price Oil (per Bbl)		56	%		$	81.00		$	51.82

Lease operating expenses increased from approximately $1,060,000 in the first quarter of 2007 to $5,791,000 for the same period in 2008, an increase of $4,731,000 or 446%. Properties acquired in the Merger and from AROC Energy LP accounted for $1,052,000 and $3,702,000 of the increase, respectively. On a unit-of-production basis, barrel of oil equivalent (“BOE”) costs increased by $3.70 or 27% as a result of higher costs due to an unprecedented demand for personnel, materials, services and rigs caused by high commodity prices. Re-engineering and workover costs increased by $619,000 from $78,000 to $697,000, due to increased emphasis on restoring and enhancing existing production capabilities. Production taxes increased by $1,621,000 or 446%, due to increased production volumes and revenues.

G&A increased $956,000 due primarily to overall business expansion related to the Merger.

 

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The increase in DD&A expense attributable to the properties acquired in the Merger and from AROC Energy LP was $386,000 and $2,292,000, respectively. The remaining increase of $270,000 was due to property acquisitions by Southern Bay prior to the Merger, partially offset by lower net capitalized costs on other properties.

Interest expense increased by $1,413,000 due to higher debt levels in the first quarter of 2008 compared to the same period of 2007. As of March 31, 2008 and 2007, we had outstanding debt of $86,000,000 and $8,000,000, respectively. During the first quarter of 2008 and 2007, our average outstanding debt was approximately $90,000,000 and $4,000,000, respectively. Interest income increased by $96,000 in the first quarter of 2008 over the same period of 2007, due to larger invested cash balances.

In the first quarter of 2008 loss from hedge ineffectiveness was $1,518,000, compared to $4,000 for the same period in 2007. This resulted from an increase in the liability associated with the mark-to-market valuation of our hedge contracts. Those increases are due to significantly higher oil and natural gas prices and are partially offset by monthly hedge settlement payments.

Other income increased by $808,000 in the first quarter of 2008 from the same period in 2007. This was due to increased partnership management fees of $157,000, increased property operating income of $76,000, increased partnership income of $165,000 as well as nonrecurring income from a gain on property sales in the first quarter of 2008 of $410,000.

Income tax expense for the first quarter of 2008 was $2,596,000 compared to $4,000 for the same period in 2007. As previously stated, the 2007 financial statements, as presented herein, are those of Southern Bay which, as a partnership, was not generally subject to income taxes.

Impact of Property Acquisitions and Development

We estimate that production volumes for the year 2008 will approximate 708,000 Bbls of oil and 2,654,000 Mcf of natural gas, representing an increase of 99% and 61%, respectively, over 2007 net of certain divestitures. These estimates are predicated on the results of operations for the three months ended March 31, 2008, and production estimates of expected divestitures. These projected increases are a direct result of acquisition and development activities. In connection with property acquisitions, we generally implement a capital expenditures program; directly related to existing producing wells and those capable of production; which we refer to as “re-engineering activities,” designed to increase production and forestall natural or mechanical production declines, as well as lower recurring expenses. Thereafter, we conduct detailed field studies designed to isolate development and exploration opportunities, if any. We have identified numerous projects in our existing property portfolio related to proved behind-pipe and undeveloped reserves and expect to define additional development and exploratory potential. Net future cash flows could be favorably affected by additional development potential and also by further price improvement and/or reductions to per-unit operating costs. No assurance can be given, however, that we will be able to successfully and economically develop additional reserves.

Impact of Changing Prices and Costs

Our revenues and the carrying value of our oil and gas properties are subject to significant change due to changes in oil and gas prices. As demonstrated historically, prices are volatile and unpredictable. Oil prices increased appreciably during 2007 and again in recent months in 2008. Average realized oil prices of $81.00 per Bbl, net of hedges, for the three months ended March 31, 2008, were 56% higher than for the comparable period in 2007 and, in recent weeks, prices have reached an all time high. Average natural gas prices, net of hedges, increased 27% in the first quarter of 2008 over the same period of 2007. Such average realized prices for the three months ended March 31, 2008, were affected by certain hedging activities. 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.

 

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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 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 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 subsidize 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. Financing activities in 2008 have resulted in a net reduction of debt of $10 million. At December 31, 2007, outstanding debt was $96 million. During 2007, we borrowed $3,000,000, assumed $1,800,000 in the Merger and repaid the entire balance outstanding of $9.8 million in late June 2007. In October 2007, we borrowed $96 million to finance a major acquisition as discussed above in Note B.

We intend to continue to divest certain oil and gas properties, but at present we cannot predict the timing of any remaining divestitures or estimated proceeds there from with certainty. In addition, we have developed a $61.5 million capital expenditure budget for the two-year period that commenced on October 1, 2007. At present, we believe that proceeds from divestitures and net cash flows from operating activities are sufficient to continue to fund projected capital expenditures and also reduce our debt balances, but, we could incur additional debt in connection with further acquisition and development activities or corporate acquisitions or mergers, if any.

Credit Facility

At March 31, 2007, we had a $9.5 million borrowing base, with available borrowing capacity of $1.5 million, in accordance with our revolving Credit Agreement with our bank. We currently have a borrowing base of $95 million and, as a result of the AROC Energy LP acquisition, have an outstanding principal balance of $86 million. Our remaining borrowing capacity currently is $9 million.

Cash Flows from Operating Activities

For the three months ended March 31, 2008, our net cash provided by operating activities was $7.2 million, up by $3.7 million from the same period in 2007, due primarily to increases in production resulting from acquisition and development activities, partially offset by increased general and administrative expenses. We expect recent acquisitions and development activities to significantly increase cash provided by operating activities throughout the remainder of 2008, assuming commodity prices do not decrease substantially.

 

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Cash Flows from Investing Activities

Cash applied to oil and gas capital expenditures for the three months ended March 31, 2008 and 2007, was $13.0 million and $6.9 million, respectively. In 2008, we also realized cash of $8.5 million from the sale of properties. In 2007, we invested $1.6 million in an oil and gas limited partnership for which we are the general partner. Capital expenditures for 2008 were financed with equity and operating cash flow. We expect to spend approximately $62 million in capital expenditures in 2008 and 2009.

During the remainder of 2008, we also expect to incur certain capital expenditures related to our existing portfolio of properties for re-engineering facilities (surface and down-hole), restoring shut-in wells to production and for recompletions. In addition, we expect to drill certain development wells in existing fields. We also expect to make additional capital expenditures during 2008 to maintain leases and complete the interpretation of 3-D seismic data associated with certain exploratory and development projects. We will continue our practice of soliciting partners, on a promoted basis, for higher risk projects.

2008-2009 Capital Budget

Based solely on our existing portfolio of properties and projects, we presently expect to incur the following capital expenditures during 2008 and 2009:

 

		($ Millions)
Southern District:
Austin Chalk drilling and development (1) (2)		$	7.2
Other development drilling (2)			2.8
Waterflood expansion			1.3
Exploratory drilling (3)			7.8
Re-engineering (4)			3.2
Acreage, seismic and other (5)			3.5
Northern District:
Horizontal development drilling (2) (6)			11.8
Other development drilling			1.7
Waterflood and associated drilling			9.7
Bakken Shale drilling (7)			9.0
Re-engineering (4)			1.0
Acreage, seismic and other (5)			2.5
Total (8)		$	61.5

 

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Notes:

 

1)	Continuation of ongoing horizontal drilling and development program with an affiliated institutional partnership. The program includes ten scheduled wells with one drilling rig with certain other recompletion and frac expenditures intended to further increase production in producing wells.

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

3)	Principally South Louisiana and Gulf Coast Texas.

4)

Includes activities related to existing fields intended to enhance production and lower operating expenses. These expenditures include flowlines, facilities, compression, down-hole lift methods, recompletions and side-track drilling. We currently have 70 such projects including multiple wells within ten fields budgeted for 2008.

5)	Initial funds allocated for further expansion of acreage and prospect inventory.

6)	Includes eight horizontal development wells within existing fields where we have interests ranging from 66%—100%.

7)

Includes ten wells where our working interest is 10.5% and one well with a 5.25 % interest. Also includes three wells where our working interest is less than 1% but where, in the opinion of management, such participation should provide valuable technical data related to the drilling operations and reservoir characteristics. Also includes one Bakken Shale test in Montana where we presently hold a 50% working interest.

8)

In summary, our current scheduled drilling activities include diversified opportunities intended to develop reserves and increase production. The current budget includes: i) 29 wells which have assigned proved undeveloped reserves and the potential for the development of non-proved reserves; ii) 10 wells which do not have proved reserves assigned but have the potential of developing a resource gas play in Colorado; iii) two potentially high impact exploratory wells at Quarantine Bay, Plaquemines Parish, Louisiana; iv) 15 Bakken Shale wells; and v) one well intended to test an emerging shale play in our Northern Region.

The budget, as well as the timing of expenditures, is subject to change as we re-evaluate alternative projects in connection with our recent major acquisition and further expand our portfolio. We expect that the majority of expenditures will occur during 2008, but certain projects may extend into 2009, specifically including acreage acquisition, projected waterflood and horizontal drilling projects. This budget may be accelerated pending drilling and service rig availability and adequate staffing to effectively manage activities and control costs. In addition, certain expenditures may be deferred in favor of new opportunities.

We believe projected expenditures will result in increased production, cash flows and reserve value and will further expose us to potential upside from exploration. We further believe any deferral of certain projects will not result in any material losses. Should we be unable to acquire new properties, capital expenditures associated with existing properties could be increased.

Cash Flows from Financing Activities

In the first three months of 2008, financing activities used cash of $10.0 million in the reduction of our long-term debt.

 

Item 3.

Controls and Procedures

Our principal executive officer, Frank A. Lodzinski, and our principal financial officer, Howard E. Ehler, have implemented or caused to be implemented, our disclosure controls and procedures to ensure that material information relating to the Company is communicated adequately to our chief executive officer and our chief financial officer through the end of the reporting period addressed by this report. As of the end of the reporting period reflected herein, our chief executive officer and chief financial officer evaluated the effectiveness of our disclosure controls and procedures, and based on such evaluation our chief executive officer and chief financial officer have concluded that the our disclosure controls and procedures, as of the end of the period covered by this report, are effective in alerting them on a timely basis to material information relating to the Company that is required to be included in our reports filed or submitted under the Securities Exchange Act of 1934.

 

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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 6.

Exhibits

(a) Exhibits.

 

3.1		Amended and Restated Articles of Incorporation and amendments thereto. (1)
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)
10.25		December 22, 2004 Credit Agreement by and between Southern Bay Oil & Gas, L.P. as borrower and Wachovia Bank, National Association. (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)

 

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10.30		Credit Agreement dated September 26, 2007 between the Registrant and Wachovia Bank National Association. (2)
10.32		Limited Partner Interest Purchase and Sale Agreement dated October 16, 2007 between the Registrant and TIFD III-X, LLC (2)
10.33		Amended and Restated Credit Agreement dated October 16, 2007 between the Registrant and Wachovia Bank National Association (2)
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.

 

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SIGNATURES

In accordance with the requirements of the Exchange Act, the Registrant caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

		GEORESOURCES, INC.
May 13, 2008
		/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)

 

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EXHIBIT INDEX

(b) Exhibits.

 

3.1		Amended and Restated Articles of Incorporation and amendments thereto. (1)
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)
10.25		December 22, 2004 Credit Agreement by and between Southern Bay Oil & Gas, L.P. as borrower and Wachovia Bank, National Association. (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)

 

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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)
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.

 

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