GEOI Georesources, Inc. (MM)

Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

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

For the Quarterly Period ended June 30, 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 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   ¨

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):

 

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

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

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

 

Class of equity		Outstanding at August 8, 2008
Common stock, par value $.01 per share		16,236,717 shares

 

 

 

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TABLE OF CONTENTS

 

PART I.		FINANCIAL INFORMATION
Item 1.		Financial Statements
		Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007		3
		Consolidated Statements of Operations for the Three Months and Six Months ended June 30, 2008 and 2007		4
		Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the Six Months ended June 30, 2008		5
		Consolidated Statements of Cash Flows for the Six Months ended June 30, 2008 and 2007		6
		Notes to Consolidated Financial Statements		7
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3.		Quantitative and Qualitative Disclosure About Market Risk		25
Item 4T.		Controls and Procedures		25
PART II.		OTHER INFORMATION
Item 1.		Legal Proceedings		26
Item 1A.		Risk Factors		26
Item 6.		Exhibits		27
Signatures				29

 

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Item 1 - Financial Statements

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

 

		June 30, 2008				December 31, 2007
		(unaudited)
ASSETS
Current assets:
Cash		$	23,578			$	24,430
Accounts receivable:
Oil and gas revenues			32,472				20,365
Joint interest billings and other			4,287				3,913
Affiliated partnerships			4,162				3,360
Notes receivable			120				600
Federal income tax receivable			251				—
Prepaid expenses and other			2,250				1,430
Total current assets			67,120				54,098
Oil and gas properties, successful efforts method:
Proved properties			199,071				187,641
Unproved properties			3,520				5,140
Office and other equipment			989				996
Land			96				96
			203,676				193,873
Less accumulated depreciation, depletion and amortization			(18,106	)			(12,430	)
Net property and equipment			185,570				181,443
Other assets:
Equity in oil and gas limited partnerships			3,319				1,880
Deferred financing costs and other			2,695				2,937
		$	258,704			$	240,358
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	11,349			$	11,374
Accounts payable to affiliated partnerships			20,575				9,538
Revenues and royalties payable			21,164				14,567
Drilling advances			445				882
Accrued expenses			3,673				3,839
Derivative financial instruments			33,955				6,527
Total current liabilities			91,161				46,727
Long-term debt			50,000				96,000
Deferred income taxes			10,860				6,476
Asset retirement obligations			5,217				7,827
Derivative financial instruments			55,062				15,296
Stockholders’ equity:
Common stock, par value $.01 per share; authorized 100,000,000 shares; 16,236,717 in 2008 and 14,703,383 in 2007 shares issued and outstanding			162				147
Additional paid-in capital			112,290				79,690
Accumulated other comprehensive income (loss)			(85,567	)			(19,310	)
Retained earnings			19,519				7,505
Total stockholders’ equity			46,404				68,032
		$	258,704			$	240,358

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(unaudited)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2008				2007				2008			2007
Revenue:
Oil and gas revenues		$	25,118			$	7,060			$	47,581		$	10,598
Partnership management fees			522				256				834			412
Property operating income			357				445				671			682
Gain (loss) on sale of property and equipment			1,551				(15	)			1,961			(15	)
Partnership income			429				154				655			213
Interest and other			228				385				450			512
Total revenue			28,205				8,285				52,152			12,402
Expenses:
Lease operating expense			5,789				2,255				11,580			3,315
Severance taxes			2,428				534				4,317			803
Re-engineering and workovers			984				415				1,682			433
Exploration and impairment expense			502				—				502			—
General and administrative expense			1,861				2,457				3,645			3,247
Depreciation, depletion and amortization			3,573				1,932				7,450			2,861
Hedge ineffectiveness			(582	)			(7	)			937			(3	)
Interest			1,314				199				2,883			355
Total expense			15,869				7,785				32,996			11,011
Income before income taxes			12,336				500				19,156			1,391
Income taxes:
Current			1,330				94				2,759			96
Deferred			3,216				1,755				4,383			1,758
			4,546				1,849				7,142			1,854
Net income (loss)		$	7,790			$	(1,349	)		$	12,014		$	(463	)
Net income per share (basic)		$	0.51			$	(0.09	)		$	0.80		$	(0.05	)
Net Income per share (diluted)		$	0.50			$	(0.09	)		$	0.79		$	(0.05	)
Weighted average shares outstanding (basic)			15,214				14,573				14,959			10,106
Weighted average shares outstanding (diluted)			15,505				14,573				15,146			10,106

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)

Six Months Ended June 30, 2008

(In thousands, except share data)

(unaudited)

 

		Common Stock					Additional Paid-in			Retained			Accumulated Other Comprehensive
		Shares		Par value			Capital			Earnings			Income (loss)				Total
Balance, December 31, 2007		14,703,383		$	147		$	79,690		$	7,505		$	(19,310	)		$	68,032
Issuance of common stock, net of stock issue costs of $2,183,000		1,533,334			15			32,302										32,317
Comprehensive income (loss):
Net income											12,014							12,014
Change in fair market value of hedged positions														(74,164	)			(74,164	)
Net realized hedging losses charged to income														7,907				7,907
Total comprehensive income (loss)																		(54,243	)
Equity based compensation expense								298										298
Balance, June 30, 2008		16,236,717		$	162		$	112,290		$	19,519		$	(85,567	)		$	46,404

The accompanying notes are an integral part of these statements.

 

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GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)

 

		Six Months Ended June 30,
		2008				2007
Cash flows from operating activities:
Net income (loss)		$	12,014			$	(463	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			7,450				2,861
(Gain) loss on sale of property and equipment			(1,961	)			15
Impairment of unproved properties			483				—
Accretion of asset retirement obligations			216				53
Hedge ineffectiveness loss (gain)			937				(3	)
Partnership income			(655	)			(213	)
Partnership distributions			194				—
Deferred income taxes			4,383				1,758
Non-cash compensation			298				422
Changes in assets and liabilities:
Increase in accounts receivable			(13,534	)			(10,269	)
Decrease in notes receivable			480				—
Increase in prepaid expense and other			(623	)			344
Increase in accounts payable and accrued expenses			17,006				11,869
Net cash provided by operating activities			26,688				6,374
Cash flows from investing activities:
Proceeds from sale of property and equipment			20,432				1,750
Additions to property and equipment			(33,311	)			(10,143	)
Investment in oil and gas limited partnership			(978	)			(1,632	)
Net cash used in investing activities			(13,857	)			(10,025	)
Cash flows from financing activities:
Issuance of common stock, net of stock issue cost of $2,183,000			32,317				22,799
Distributions to stockholders			—				(4,006	)
Issuance of long-term debt			—				3,000
Reduction of long-term debt			(46,000	)			(9,800	)
Net cash provided by (used in) financing activities			(13,683	)			11,993
Net increase (decrease) in cash and cash equivalents			(852	)			8,342
Cash and cash equivalents at beginning of period			24,430				6,217
Cash and cash equivalents at end of period		$	23,578			$	14,559
Supplementary information:
Interest paid		$	2,831			$	332
Income taxes paid		$	4,210			$	—
Non-cash net asset acquire in merger transactions:
GeoResources		$	—			$	23,827
PICA Energy, LLC		$	—			$	11,703
Yuma property interests		$	—			$	3,120

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 and six months ended June 30, 2008 are those attributable to the combined entities. The results of operations and cash flows for the six months ended June 30, 2007 are those attributable to the former Southern Bay entity for the entire six months and those of the combined entity for the period from April 18, 2007 through June 30, 2007.

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, Oklahoma, 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.

Reclassification

Certain reclassifications have been made to prior period amounts to conform to current period presentation of Revenues and royalties payable in the Consolidated Balance Sheet as of 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.

 

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Under the Purchase Agreement, the Company purchased the interest for a cash purchase price of $91,100,000 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 E. 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.

Pro Forma Results of Operations

The following summary presents unaudited pro forma information for the six month period ended June 30, 2007 as if the Merger and Acquisition had been consummated at January 1, 2007 respectively (in thousands, except share data).

 

Six months ended June 30, 2007
Total revenue		$	30,374
Income before income taxes		$	5,051
Net income		$	1,839
Net income per share: basic and diluted		$	0.18
Weighted average shares outstanding at June 30, 2007			10,106,159

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 May 2008, Southern Bay, through Catena, formed an entity in connection with the acquisition of producing oil and gas properties located throughout Oklahoma. OKLA Energy Partners LP (“OKLA”) 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 May 2008, these entities paid cash of $61.7 million to acquire certain Oklahoma properties. Catena, purchased 18% of the interests and OKLA purchased the remaining 82%. Catena’s share of the property purchase price was $12.8 million, and its general partner contribution to OKLA was $980,000. The Company’s investment in OKLA 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 are operated by the Company. The purchase price was allocated to oil and gas properties.

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

 

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In May 2008, the Company closed certain property sales that were pending at March 31, 2008. The May sales consisted of seven non-core fields in Louisiana and Texas and were sold for approximately $11.8 million. The Company recognized a gain of $1.5 million related to these sales.

NOTE C: 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 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 D: Income Taxes

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

The Company estimates that its effective tax rate for the year ending December 31, 2008 will be approximately 37%. Income tax expense of $7.1 million and $1.9 million was recognized for the six month periods ended June 30, 2008 and 2007, respectively. Income tax expense of $4.5 million and $1.9 million was recognized for the three month periods ended June 30, 2008 and 2007, respectively.

FIN 48-Uncertain Tax Positions

The Company also accounts for income taxes under the provisions of FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, and FSP FIN 48-1, which provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. FIN 48 prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criteria and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. FIN 48 also requires that the amount of interest expense recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return.

The Company did not have any 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.

 

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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 or six months then ended. 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 June 30, 2009.

NOTE E: 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 April 1 and October 1 of each year. As of June 30, 2008, the borrowing base had been reduced to $95 million due to the sales of certain non-core 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.

On October 16, 2007, the Company borrowed $96 million under the Amended Credit Agreement, in connection with the AROC Energy 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 June 30, 2008, the outstanding principal balance was $50.0 million. The interest rate in effect at June 30, 2008 was 4.46% on the entire amount of the outstanding 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 June 30, 2008, the Company has recorded a liability of $999,000, of which $436,000 is current, related to this hedge. The fair market value of the interest rate swap at December 31, 2007 was a liability of $854,000, of which $477,000 was classified as a current liability.

At June 30, 2008, accumulated other comprehensive loss included $999,000 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 six months ended June 30, 2008, the Company recognized realized cash settlement gains of $19,000 related to this swap. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at June 30, 2008, the Company expects to reclassify net losses of $436,000 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

NOTE F: 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 changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the six months ended June 30, 2008, are as follows (in thousands):

 

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Asset retirement obligation, January 1, 2008		$	7,827
Additional liabilities incurred			125
Accretion expense			216
Obligations on sold properties			(2,906	)
Settled obligations			(45	)
Asset retirement obligation, June 30, 2008		$	5,217

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 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 June 30, 2008, accumulated other comprehensive loss consisted of $84,568,000 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 three and six month periods ended June 30, 2008, the Company recognized realized cash settlement losses on commodity derivatives of $5,840,000 and $7,926,000, respectively. For the three and six month periods ended June 30, 2007, the Company recognized realized settlement losses on commodity derivatives of $400,000 and $720,000, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at June 30, 2008, the Company expects to reclassify net losses of $33,519,000 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially. At June 30, 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 (remainder)		157,000					$	80.19
2009		368,000					$	76.00
2010		322,000					$	74.71
2011		282,000					$	74.37
Costless collar contracts:
2008 (remainder)		60,000		$	65.00		$	75.10
Natural Gas Contracts (Mmbtu):
Swap contracts:
2009		779,268					$	4.785
2009		427,200					$	5.61
Costless collar contracts :
2008 (remainder)		60,000		$	8.00		$	8.45
2008		818,500		$	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 June 30, 2008 was a liability of $88,018,000 of which $33,519,000 was classified as a current liability. The fair market value of these hedge contracts at December 31, 2007 was a liability of $20,696,000, of which $6,051,000 was classified as a current liability. During the three months ended June 30, 2008 and 2007, the Company recognized gains of $582,000 and $7,000, respectively, due to hedge ineffectiveness on these hedge contracts. During the six month period ended June 30, 2008, the Company recognized a loss due to hedge ineffectiveness of $937,000 compared to a gain of $3,000 for the same period in 2007.

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

NOTE H: 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:

 

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•

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

 

•

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

 

•

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

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of the input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The following table presents information about the Company’s liabilities measured at fair value on a recurring basis as of June 30, 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 June 30, 2008
Current portion of derivative financial instrument liability (1)		—		$	33,955,000		—		$	33,955,000
Long-term portion of derivative financial instrument liability (2)		—		$	55,062,000		—		$	55,062,000

 

(1)	Includes Interest Rate Swap ($436,000) and Commodity Derivative Instruments ($33,519,000)

(2)	Includes Interest Rate Swap ($563,000) and Commodity Derivative Instruments ($54,499,000)

The Company does not have any assets measured at fair value on a recurring basis as of June 30, 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 I: Private Placement Offering

On June 9, 2008, the Company issued 1,533,334 shares of common stock and 613,336 warrants to non-affiliated accredited investors pursuit to exemptions from registration under federal and state securities laws. The shares of common stock were sold for $22.50 per share. The warrants have a term of five years but cannot be exercised before six months after the closing of the private placement transaction at an exercise price of $32.43. The gross proceeds of $34.5 million were reduced by placement fees and issue costs of $2.2 million.

NOTE J: Stock Options, Performance Awards and Stock Warrants

On October 10, 2007, November 15, 2007, and June 19, 2008, the Company granted options to officers and employees to purchase 755,000, 10,000 and 25,000 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
June 19, 2010		12,500		$	22.50
October 10, 2011		188,750		$	9.56
November 15, 2011		2,500		$	9.56
June 19, 2011		6,250		$	25.00
June 19, 2012		6,250		$	25.00
Total shares		790,000

The closing market prices of the Company’s common stock on the date of the October and November 2007 grants were $7.20 and $8.65 respectively. The closing market price of the Company’s common stock on the date of the June 2008 grant was $20.99.

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 based upon the fair value of the option at the date of grant determined by the Black-Scholes option pricing model. During the three and six months ended June 30, 2008, the Company included stock-based compensation expense in general and administrative expenses of $149,000 and $298,000, respectively. As of June 30, 2008, the future pre-tax expense of nonvested stock options is $1.3 million to be recognized through 2011.

NOTE K: Related Party Transactions

In July 2007, the Company acquired certain 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 June 30, 2008 and December 31, 2007, includes $3,667,000 and $3,360,000 respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at June 30, 2008, also includes $495,000 due from OKLA Energy Partners LP. Both of these partnerships are oil and gas limited partnerships for which a subsidiary of the Company serves as general partner. These amounts represent the limited partnerships’ share of property operating expenditures incurred by operating subsidiaries of the Company on their behalf, as well as accrued management fees. Accounts payable at June 30, 2008, and December 31, 2007, includes $19,512,000 and $9,538,000, respectively, due to the SBE Partners for oil and gas revenues collected on its behalf. Accounts Payable at June 30, 2008, also includes $1,063,000 due to OKLA Energy for oil and gas revenues collected on its behalf.

 

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The Company earned partnership management fees during the three month periods ended June 30, 2008, and 2007, of $522,000 and $256,000, respectively. The Company earned partnership management fees during the six month periods ended June 30, 2008, and 2007, of $834,000 and $412,000, respectively.

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

 

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Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is Management’s Discussion and Analysis (“MD&A”) of significant factors that have affected certain aspects of our financial position and operating results during the periods included in the accompanying unaudited consolidated financial statements. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-KSB/A for the year ended December 31, 2007.

Forward-Looking Information

Certain of the statements in all parts of this document, contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by words such as “may,” “will,” “expect,” “anticipate,” “estimate” or “continue,” or comparable words. All statements other than statements of historical facts included in this report, including, without limitation, statements regarding our business strategy, plans, objectives, expectations, intent, and beliefs of management, related to current or future operations are forward-looking statements. Such statements are based on certain assumptions and analyses made by management 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.

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, 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.

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 the purchase of 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 acquired oil and gas properties treated as purchased upon closing.

Our business strategy is 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 using 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.

 

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(3)

Implement re-engineering and development programs within existing fields.

 

(4)

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

 

(5)

Selectively divest assets to upgrade our oil and gas 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 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

As more fully discussed in Note B to the consolidated financial statements in Part I of this Form 10-Q, 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 existing operations. As part of our ongoing property review, we divested certain of the purchased properties and may divest certain additional purchased 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 in the properties 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 are operated by the Company.

In May 2008, we acquired properties located throughout the state of Oklahoma which included 200 producing wells and approximately 100 additional drilling locations. 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 18% working interest in the properties and a 2% general partner in this partnership. Our share of the acquisition purchase price of $61.7 million was $12.8 million, and our general partner contribution was $980,000. This acquisition was funded with the proceeds from the divestitures discussed below.

 

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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. The sale of the property allows the Company to focus on its core areas of operation.

In February 2008, the Company sold its interests in certain oil and gas properties to unaffiliated parties for $1.8 million and recognized a gain of $430,000. In May 2008, the Company closed the sales of certain other non-core oil and gas properties in Louisiana and Texas for approximately $11.8 million. These sales were part of the Company’s planned property divestiture program. The properties, which were producing approximately 390 BOPD, included fields located in inland waters with short production lives, limited upside, high operating and administrative costs and significant plugging and abandonment obligations. These sales will allow the Company to focus on activities that have greater development and exploration potential and therefore, higher potential returns.

Results of Operations

Three months ended June 30, 2008, compared to three months ended June 30, 2007

The Company recorded net income of $7,790,000 for the three months ended June 30, 2008 as compared to a net loss of $1,349,000 for the same period in 2007. This $9,139,000 increase resulted primarily from the following factors:

 

Net amounts contributing to increase (decrease) in net income (in 000s):
Oil and gas sales		$	18,058
Lease operating expense			(3,534	)
Production taxes			(1,894	)
Exploration expense			(502	)
Re-engineering and workovers			(569	)
General and administrative expenses (“G&A”)			596
Depletion, depreciation and amortization expense (“DD&A”)			(1,641	)
Net interest income (expense)			(1,272	)
Hedge ineffectiveness			575
Gain (loss) on sale of property			1,566
Other income - net			453
Income before income taxes			11,836
Provision for income taxes			(2,697	)
Net increase		$	9,139

The following discussion applies to the above changes.

Net revenues from oil and gas sales increased $18,058,000, or 256%. Properties acquired from AROC Energy LP, in October 2007, accounted for $14,736,000 of the increase. The remaining $3,322,000 increase resulted primary from increased commodity prices. Price and production comparisons are set forth in the following table. Properties acquired from AROC Energy LP accounted for increased production of approximately 375,000 Mcf of gas and approximately 102,000 barrels of oil during the second quarter of 2008.

 

		Percent increase (decrease)			Three Months Ended June 30,
					2008			2007
Gas Production (MMcf)		99	%			719			361
Oil Production (MBbls)		127	%			186			82
Barrel of oil equivalent (MBOE)		115	%			305			142
Average Price Gas Before Hedge Settlements (per Mcf)		59	%		$	11.05		$	6.96
Average Price Oil Before Hedge Settlements (per Bbl)		105	%		$	124.09		$	60.95
Average Realized Price Gas (per Mcf)		41	%		$	9.74		$	6.91
Average Realized Price Oil (per Bbl)		75	%		$	97.66		$	55.95

 

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Lease operating expenses increased from approximately $2,255,000 in the second quarter of 2007 to $5,789,000 for the same period in 2008, an increase of $3,534,000 or 157%. Properties acquired from AROC Energy LP accounted for $2,789,000 of the increase. On a unit-of-production basis, barrel of oil equivalent (“BOE”) costs increased by $3.05 or 19% 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 $569,000 from $415,000 to $984,000, due to increased emphasis on restoring and enhancing existing production capabilities. Production taxes increased by $1,894,000 or 355%, due to increased production volumes and revenues.

G&A decreased $596,000 due primarily to expenses associated with the Merger that were incurred during the quarter ended June 30, 2007, but did not reoccur in the same period in 2008.

The increase in DD&A expense attributable to the properties acquired from AROC Energy LP was $1,786,000. This increase was partially offset by decreases related to the properties sold during the second quarter of 2008.

Interest expense increased by $1,115,000 due to higher debt levels in the second quarter of 2008 compared to the same period of 2007. As of June 30, 2008, we had outstanding debt of $50,000,000 compared to a balance of zero as of June 30, 2007. During the second quarter of 2008 and 2007, our average outstanding debt was approximately $68,000,000 and $5,000,000, respectively. Interest income decreased by $157,000 in the second quarter of 2008 over the same period of 2007, due to lower interest rates on average invested cash balances.

In the second quarter of 2008 the gain from hedge ineffectiveness was $582,000, compared to $7,000 for the same period in 2007. In the first quarter of 2008 there was a larger differential between the market benchmark used for hedging and the prices we realized on sales of oil and gas, this combined with an increased liability caused us to record a large ineffectiveness loss. In the second quarter of 2008 our realized price was more consistent with the market benchmark used for hedging therefore the cumulative ineffectiveness charge was reduced and we recorded a gain on hedge ineffectiveness.

Other income increased by $453,000 in the second quarter of 2008 compared to the same period in 2007 due to increased partnership management fees of $266,000 and increased partnership income of $275,000; these increases were offset by a decrease in property operating income of $88,000. Additionally, in the second quarter of 2008 we had a net gain on sales of non-core properties and other assets of $1,551,000.

Income tax expense for the second quarter of 2008 was $4,546,000 compared to $1,849,000 for the same period in 2007. Our income tax expense increased significantly as a result of significantly higher pre-tax earnings. Our effective tax rate during the second quarter of 2008 was 37%.

Six months ended June 30, 2008, compared to six months ended June 30, 2007

The Company recorded net income of $12,014,000 for the six months ended June 30, 2008 as compared to a net loss of $463,000 for the same period in 2007. This $12,477,000 increase resulted primarily from the following factors:

 

Net amounts contributing to increase (decrease) in net income (in 000s):
Oil and gas sales		$	36,983
Lease operating expense			(8,265	)
Production taxes			(3,514	)
Exploration expense			(502	)
Re-engineering and workovers			(1,249	)
General and administrative expenses (“G&A”)			(398	)
Depletion, depreciation and amortization expense (“DD&A”)			(4,589	)
Net interest income (expense)			(2,590	)
Hedge ineffectiveness			(940	)
Gain (loss) on sale of property			1,976
Other income—net			853
Income before income taxes			17,765
Provision for income taxes			(5,288	)
Net increase		$	12,477

 

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The following discussion applies to the above changes.

Net revenues from oil and gas sales increased $36,983,000, or 349%. Properties acquired in the Merger and from AROC Energy LP accounted for $3,185,000 and $26,889,000 of the increase, respectively. The remaining $6,909,000 increase resulted primary from 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 51,000 barrels of oil during the six month period ended June 30, 2008. Properties acquired from AROC Energy LP accounted for increased production of approximately 790,000 Mcf of gas and approximately 200,000 barrels of oil during the six month period ended June 30, 2008.

 

		Percent increase (decrease)			Six Months Ended June 30,
					2008			2007
Gas Production (MMcf)		177	%			1,528			552
Oil Production (MBbls)		204	%			386			127
Barrel of oil equivalent (MBOE)		192	%			640			219
Average Price Gas Before Hedge Settlements (per Mcf)		37	%		$	9.30		$	6.79
Average Price Oil Before Hedge Settlements (per Bbl)		80	%		$	107.11		$	59.41
Average Realized Price Gas (per Mcf)		31	%		$	8.68		$	6.63
Average Realized Price Oil (per Bbl)		63	%		$	89.01		$	54.47

Lease operating expenses increased from approximately $3,315,000 during the six months ended June 30, 2007, to $11,580,000 for the same period in 2008, an increase of $8,265,000 or 249%. Properties acquired in the Merger and from AROC Energy LP accounted for $1,434,000 and $5,453,000 of the increase, respectively. On a unit-of-production basis, barrel of oil equivalent (“BOE”) costs increased by $2.98 or 20% 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 $1,249,000 from $433,000 to $1,682,000, due to our increased emphasis on restoring and enhancing existing production capabilities. Production taxes increased by $3,514,000 or 438%, due to increased production volumes and revenues.

G&A increased $398,000 due primarily to overall business expansion related to the Merger.

The increase in DD&A expense attributable to the properties acquired from AROC Energy LP was $4,065,000. The remaining increase of $524,000 was due to property additions subsequent to the Merger, partially offset by lower net capitalized costs on other properties.

Interest expense increased by $2,528,000 due to higher debt levels during the six months ended June 30, 2008, compared to the same period of 2007. As of June 30, 2008, we had outstanding debt of $50,000,000 compared to a balance of zero as of June 30, 2007. During the six month period ended June 30, 2008, and 2007, our average outstanding debt was approximately $73,000,000 and $4,000,000, respectively. Interest income decreased by $62,000 during the six month period ended June 30, 2008, compared to the same period of 2007, due to lower interest rates on average invested cash balances.

During the six month period ended June 30, 2008, the losses from hedge ineffectiveness were $937,000, compared to a gain of $3,000 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. The increases were due to significantly higher oil and gas prices and were partially offset by monthly hedge settlement payments.

Other income increased by $853,000 during the six month period ended June 30, 2008, compared to the same period in 2007, due to increased partnership management fees of $422,000 and increased partnership income of $442,000. These increases were partially offset by a decrease in property operating income of $11,000. Additionally, during the six months ended June 30, 2008, we had a net gain on sales of non-core properties and other assets of $1,961,000.

Income tax expense for the six month period ended June 30, 2008, was $7,142,000 compared to $1,854,000 for the same period in 2007. Income tax expense increased due to increased pre-tax earnings; our effective tax rate during the six month period ended June 30, 2008, was 37%.

Impact of Property Acquisitions, Divestitures and Development

 

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We estimate that production volumes for the year 2008 will range from 720,000 to 760,000 Bbls of oil and from 2,800,000 to 3,000,000 Mcf of natural gas. The lower ends of these ranges represent an increase of approximately 84% and 64%, respectively, over 2007. Ranges are provided herein because estimates are dependent on the availability of rigs, materials and services, within the industry. These estimates are predicated on the results of operations for the six months ended June 30, 2008, adjusted for production from properties sold, estimated production from properties acquired, and from our drilling and development program. We closed several divestitures of properties situated in state waters and onshore along the Gulf Coast in May 2008 and closed an acquisition in Oklahoma in June 2008. In the opinion of management, the acquired properties have longer productive lives and greater development and exploration potential that those properties which were sold. In addition, the Company reduced its estimated future abandonment expenses. However, in the short term the Company will experience a net reduction in production volumes. As previously reported, divestitures resulted in reduced oil volumes by about 390 BOPD, while the Oklahoma acquisition will initially add about 600 Mcfd. Management expects to replace this net reduction by its drilling and development program, but due to availability of rigs, materials and services the timing cannot be predicted with accuracy.

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.” These activities are intended 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 relating 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/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 during the first and second quarters of 2008. Average realized oil prices of $89.01 per Bbl, net of hedges, for the six months ended June 30, 2008, were 63% higher than for the comparable period in 2007. Average realized natural gas prices of $8.68, net of hedges, for the six months ended June 30, 2008, were 31% higher than for the comparable period in 2007. Such average realized prices for the six months ended June 30, 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.

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

 

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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. Financing activities in 2008 have resulted in a net reduction of debt of $46 million from the outstanding debt of $96 million at December 31, 2007. 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 significant property acquisition as discussed in Note B of the consolidated financial statements. During the first quarter of 2008 we repaid $10 million in debt using cash flow from operations. During the second quarter of 2008 we completed a private placement of common stock and warrants to acquire common stock (discussed in Note I above) and used the net proceeds of $32 million plus additional cash flows from operations to reduce our debt by an additional $36 million.

Credit Facility

We currently have a borrowing base of $95 million and, as a result of the AROC Energy LP acquisition our debt balance increased to $96 million at December 31, 2007. Our remaining outstanding principal balance is $50 million. At present we have unused remaining borrowing capacity currently is $45 million.

Cash Flows from Operating Activities

For the six months ended June 30, 2008, our net cash provided by operating activities was $26.7 million, up by $20.3 million from the same period in 2007, due primarily to favorable commodity price changes and increases in production resulting from acquisition and development activities, partially offset by increased general and administrative expenses. We expect the recent acquisitions and development activities to continue to increase cash provided by operating activities throughout the remainder of 2008, assuming commodity prices do not decrease substantially.

Cash Flows from Investing Activities

Cash applied to oil and gas capital expenditures for the six months ended June 30, 2008 and 2007, was $33.3 million and $10.1 million, respectively. In 2008, we also realized cash of $20.4 million from the sale of properties as compared to $1.7 million during the same period during 2007. In 2008, we invested $1.0 million in an oil and gas limited partnership for which we are the general partner as compared to $1.6 million invested in a different partnership during the same period during 2007. Capital expenditures for 2008 were financed with working capital. We expect to spend approximately $61.5 million in capital expenditures during 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.

 

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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

 

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.

 

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Notes:

The budget, as well as the timing of expenditures, is subject to change as we re-evaluate alternative projects in connection with our recent acquisitions 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 six months of 2008, financing activities provided $32.3 million in cash as a result of a private placement stock offering. Financing activities also used cash of $46.0 million in the reduction of our long-term debt.

 

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Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

The following is a list of contracts outstanding at June 30, 2008:

 

Transaction Date		Transaction Type		Beginning		Ending		Price Per Unit			Remaining Annual Volumes		Fair Value Outstanding as of June 30, 2008
													(in thousands)
Natural Gas
June-07		Collar		04/01/08		12/31/08		$	8.00 - $8.45		60,000 MMBtu		(304	)
October-07		Collar		01/01/08		12/31/08		$	7.00 - $9.80		818,500 MMBtu		(3,036	)
October-07		Collar		01/01/09		12/31/09		$	7.00 - $10.75		275,532 MMBtu		(464	)
October-07		Swap		01/01/09		12/31/09		$	4.785		779,268MMBtu		(5,835	)
October-07		Swap		01/01/09		12/31/09		$	5.61		427,200 MMBtu		(2,856	)
October-07		Collar		01/01/10		12/31/10		$	7.00 - $9.90		1,287,000 MMBtu		(1,638	)
October-07		Collar		01/01/11		12/31/11		$	7.00 - $9.20		1,079,000 MMBtu		(1,571	)
Crude Oil
June-07		Collar		01/01/08		12/31/08		$	65.00 - $75.10		60,000 Bbls		(3,934	)
October-07		Swap		01/01/08		12/31/08		$	80.19		157,000 Bbls		(9,499	)
October-07		Swap		01/01/09		12/31/09		$	76.00		368,000 Bbls		(23,241	)
October-07		Swap		01/01/10		12/31/10		$	74.71		322,000 Bbls		(19,444	)
October-07		Swap		01/01/11		12/31/11		$	74.37		282,000 Bbls		(16,196	)
													(88,018	)

 

Item 4T.

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.

During the quarter ended June 30, 2008, there were no changes in our internal controls over financial reporting that materially affect, or are reasonably likely to affect, our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) 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 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 2007 Annual Report on Form 10-KSB/A, which could materially affect our business, financial condition or future results. The risks described in our 2007 Annual Report on Form 10-KSB/A may not be the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

 

Item 2 – Unregistered Sale of Equity Securities and Use of Proceeds		None
Item 3 – Defaults Upon Senior Securities		None
Item 4 – Submission of Matters to Vote of Security Holders		None
Item 5 – Other Information		None

 

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Item 6.

Exhibits

The following exhibits are filed as part of this report:

 

3.1		Amended and Restated Articles of Incorporation dated 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 the 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)
10.25		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 17 th 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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10.32		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)
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. (1)
14.1		Code of Business Conduct and Ethics adopted March 2, 2004, incorporated by reference to Exhibit 14.1 of Registrant’s Form 10-KSB for fiscal year ended December 31, 2003.
21.1		Subsidiaries of the Registrant. (3)
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
32.1		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)
32.2		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)

 

(1)	Filed herewith.

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

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

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

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

 

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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.
August 11, 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

 

(a)

Exhibits.

 

3.1		Amended and Restated Articles of Incorporation dated 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 the 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)
10.25		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 475-17th Street, CO. and Collis P. Chandler III for 475 17 th 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)
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. (1)
14.1		Code of Business Conduct and Ethics adopted March 2, 2004, incorporated by reference to Exhibit 14.1 of Registrant’s Form 10-KSB for fiscal year ended December 31, 2003.
21.1		Subsidiaries of the Registrant. (3)
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act. (1)
32.1		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)
32.2		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act. (1)

 

(1)	Filed herewith.

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

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

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

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

 

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