10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year ended December 31, 2011

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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of exchange on which registered
Common Stock, Par Value $0.01 Per Share	NASDAQ Global Select Market

Indicated by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    ¨  Yes    x  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    ¨  Yes    x  No

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

Indicated by check mark whether the registrant is a large accelerated file, an accelerated file, a non-accelerated filer, or a smaller reporting company. (Check one):

Larger accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller reporting company	¨

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

Aggregate market value of the voting common stock held by non-affiliates of the registrant at June 30, 2011: $451,046,891

Number of shares of the registrant’s common stock outstanding at March 9, 2012: 25,625,792

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Definitive Proxy Statement for the registrant’s 2012 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2011 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

	Certain Definitions	3
	PART I
Item 1.	Business	8
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	26
Item 2.	Properties	27
Item 3.	Legal Proceedings	37
Item 4.	Mine Safety Disclosures	37
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 8.	Financial Statements and Supplementary Data	59
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	59
Item 9A.	Controls and Procedures	60
Item 9B.	Other Information	62
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	63
Item 11.	Executive Compensation	63
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	63
Item 13.	Certain Relationships, Related Transactions and Director Independence	64
Item 14.	Principal Accountant Fees and Services	64
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	65
	Signatures

Page 1

Forward-Looking Statements

Certain statements contained in this report on Form 10-K are not statements of historical fact and constitute forward-looking statements within the meaning of the various provisions of the Securities Act of 1933, as amended, (the “Securities Act”) and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including, without limitation, the statements specifically identified as forward-looking statements within this report. Many of these statements contain risk factors as well. In addition, certain statements in our future filings with the SEC, in press releases, and in oral and written statements made by or with our approval which are not statements of historical fact constitute forward-looking statements within the meaning of the Securities Act and the Exchange Act. Examples of forward-looking statements, include, but are not limited to: (i) projections of capital expenditures, revenues, income or loss, earnings or loss per share, capital structure, and other financial items, (ii) statements of our plans and objectives or our management or board of directors including those relating to planned development of our oil and gas properties, (iii) statements of future economic performance and (iv) statements of assumptions underlying such statements. Words such as “believes,” “anticipates,” “expects,” “intends,” “targeted,” “may,” “will” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

• Changes in production volumes, worldwide demand and volatility in commodity prices for oil and natural gas;

• Changes in estimates of proved reserves;

• Our ability to replace produced oil and gas reserves;

• Declines in the values of our oil and gas reserves;

• The timing and extent of our success in discovering, acquiring, developing and producing oil and natural gas reserves;

• Our ability to acquire leases, drilling rigs, supplies and services on a timely basis and at reasonable prices;

• Reductions in the borrowing base under our credit facility;

• Risks incident to the drilling and operation of oil and natural gas wells;

• Future production and development costs;

• The availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on prices;

• Competition, including intense competition in resources play areas;

• The effect of existing and future laws, governmental regulations and the political and economic climates of the United States of America;

• Our ability to attract and retain key members of senior management;

• Changes in environmental laws and the regulation and enforcement related to those laws;

• The identification of and severity of environmental events and governmental responses to the events;

• Legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, derivatives reform, and changes in state, federal and foreign income taxes;

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• Social unrest, political instability, acts of terrorism or sabotage in oil and gas producing regions in the Middle East or our markets;

• The effect of oil and natural gas derivative activities; and

• Capital market conditions including the availability and cost of capital.

Such forward-looking statements speak only as of the date on which such statements are made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made to reflect the occurrence of unanticipated events.

CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this report refer to GeoResources, Inc., together with its consolidated operating subsidiaries. When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this report:

After payout – With respect to an oil or natural gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

AMI – Area of mutual interest

Bbl – One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bbls/d or BOPD – barrels per day or barrels of oil per day.

Bcf – Billion cubic feet.

Bcfe – Billion cubic feet equivalent, determined using the ratio of six thousand cubic feet (Mcf) of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Before payout – With respect to an oil and natural gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

Behind-pipe reserves – Those reserves expected to be recovered from completion interval(s) not yet open but still behind casing in existing wells. These reserves, if they meet the criteria for proved reserves, will be included in the PDNP category of our reserves.

BOE – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Carried interest – A contractual arrangement, usually in a drilling project, whereby all or a portion of the working interest cost participation of the project originator is paid for by another party in exchange for earning an interest in such project.

Completion – The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Compression – A force that tends to shorten or squeeze, decreasing volume or increasing pressure.

DD&A – Depreciation, depletion and amortization.

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Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.

Development activities – Activities following exploration including the drilling and completion of additional wells and the installation of production facilities.

Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well – A well found to be incapable of producing hydrocarbons economically.

(Adjusted) EBITDAX – Adjusted EBITDAX is a Non-GAAP measure of performance. Adjusted EBITDAX is calculated as earnings (net income) before interest, taxes, depreciation, amortization and exploration expenses. See Item 6 Selected Financial Data for a reconciliation of this Non-GAAP measure to GAAP Net Income.

Exploitation – The act of making oil and gas property more profitable, productive or useful.

Exploratory well – A well drilled to find and produce oil or natural gas reserves in an area or to a potential reservoir not classified as proved.

Farm-in or Farm-out – An agreement whereby the owner of a working interest in an oil and natural gas lease assigns or contractually conveys subject to future assignment the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the farmee is required to drill one or more wells in order to earn its interest in the acreage. The farmor usually retains a royalty and/or after payout interest in the lease. The interest received by the farmee is a “farm-in” while the interest transferred by the farmor is a “farm-out.”

FASB – The Financial Accounting Standards Board.

Field – An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

GAAP – Generally accepted accounting principles in the United States of America.

HBP – Held by production. Proved undeveloped reserves or drilling opportunities, that are developmental or exploratory, that are not subject to mineral lease expiration because within the field or project area certain wells are producing and therefore retain the mineral rights on the lease.

Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling – A drilling technique that permits the operator to drill horizontally within a specified targeted reservoir and thus exposes a larger portion of the producing horizon to a wellbore than would otherwise be exposed through conventional vertical drilling techniques. Greater horizontal exposure to a hydrocarbon bearing reservoir typically results in increased production rates and greater ultimate recoveries of hydrocarbons than vertical drilling.

Hydraulic fracture (Frac, Frac’ing) – A well stimulation method by which fluid (approximately 95-98% water) and proppant (purposely sized particles used to hold open an induced fracture) are injected downhole and into the producing formation at high pressures and rates in order to exceed the rock strength and create a fracture such that the proppant material can be placed into the fracture to enhance the productive capability of the formation.

Injection well – A well which is used to inject gas, water, or liquefied petroleum gas under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.

Joint Operating Agreement or JOA – Any agreement between working interest owners concerning the duties and responsibilities of the operator and rights and obligations of the non-operators.

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MBbls – One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE – one thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.

Mbtu (Mmbtu) – Used as a standard unit of measurement for natural gas and provides a convenient basis for comparing the energy content of various grades of natural gas and other fuels. One cubic foot of natural gas produces approximately 1,000 BTUs, so 1,000 cubic feet of gas is comparable to 1 MBTU. MBTU is often expressed as MMBTU, which is intended to represent a thousand BTUs.

Mcf – One thousand cubic feet.

Mcfe – One thousand cubic feet equivalent determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis although there have been periods in which they have been lower or substantially lower.

MMcf – One million cubic feet.

MMcf/d – One million cubic feet per day.

MMcfe – One million cubic feet equivalent.

Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.

NGL’s – Natural gas liquids measured in barrels.

NRI or Net Revenue Interests – The share of production after satisfaction of all royalty, oil payments and other non-operating interests.

Normally pressured reservoirs – Reservoirs with a formation-fluid pressure equivalent to 0.465 PSI per foot of depth from the surface. For example, if the formation pressure is 4,650 PSI at a depth of 10,000 feet, the pressure is considered to be normal.

Over-pressured reservoirs – Reservoirs with a formation fluid pressure greater than 0.465 PSI per foot of depth from the surface.

Pad drilling – When multiple wells are drilled from the same drilling pad in an effort to minimize the downtime and cost of dismantling and transporting a drilling rig to a new site.

Plant products – Liquid hydrocarbons generated by a plant facility; including propane, iso-butane, normal butane, pentane and ethane.

Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface.

PV10 – The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices, as prescribed in the SEC rules, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion and amortization, or Federal income taxes and discounted using and annual discount rate of 10%. PV10% is considered a Non-GAAP financial measure as defined by the SEC.

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Primary recovery – The first stage of hydrocarbon production in which natural reservoir drives are used to recover hydrocarbons, although some form of artificial lift may be required to exploit declining reservoir drives.

Productive well – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed nonproducing reserves or PDNP – Proved reserves that meet the definition of proved developed reserves (defined below) but are either shut-in or are behind-pipe reserves.

Proved developed producing reserves or PDP – Proved reserves that meet the definition of proved developed reserves (defined below) that are currently able to produce to market.

Proved developed reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the costs of the required equipment is relatively minor compared to the costs of a new well.

Proved reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimates. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves or PUDs – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time

Reasonable certainty – If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achived than non, and, as changes due to increased availability of geoscience (geological, geophysical or geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonabley certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

Recompletion – The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

Re-engineering – a process involving a comprehensive review of the mechanical conditions associated with wells and equipment in producing fields. Our re-engineering practices typically result in a capital expenditure plan, which is implemented over time, to workover (see below) and re-complete wells and modify down-hole artificial lift equipment and surface equipment and facilities. The programs are designed specifically for individual fields to increase and maintain production, reduce down-time and mechanical failures, lower per-unit operating expenses, and therefore, improve field economics.

Reprocessing – Taking older seismic data and performing new mathematical techniques to refine subsurface images or to provide additional ways of interpreting the subsurface environment.

Reservoir – A permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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Royalty interest – An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SEC – The U.S. Securities and Exchange Commission.

Secondary recovery – The use of water-flooding or gas injection to maintain formation pressure during primary production and to reduce the rate of decline of the original reservoir drive.

Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserve was estimated but were not producing due to market conditions, mechanical difficulties or because production equipment or pipelines were not yet installed. These reserves are included in the PDNP category on the reserve report.

Sliding sleeve (or mass sliding sleeve) – These are tools used in horizontal fracture stimulation in order to isolate zones and allow for multiple fracture stages in a single wellbore. This type of tool allows for up to approximately 40 individual stages to be stimulated separately in one well during the completion process.

Standardized Measure of Discounted Future Net Cash Flows – A measure of the present value of the estimated cash flows derived from the production and sales proved reserves. Estimated production taxes, estimated operating expenses, estimated future investment costs, and estimated future income taxes are discounted and deducted from estimated cash inflows to arrive at the standardized measure of discounted future net cash flows. We calculate this measure in accordance with FASB ASC Topic (932) Extractive Activities – Oil and Gas.

3-D seismic – An advanced technology method of detecting accumulation of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Waterflooding – The secondary recovery method in which water is forced down injection wells laid out in various patterns around the producing wells. The water injected displaces the oil and forces it to the producing wells.

Working interest or WI – The ownership interest, generally defined in a JOA, that gives the owner the right to drill, produce and/or conduct operating activities on the property and share in the sale of production, subject to all royalties, overriding royalties and other burdens and obligates the owner of the interest to share in all costs of exploration, development operations and all risks in connection therewith.

Workover – Operations on a producing well to restore or increase production.

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PART I

Item 1. Business

Overview

GeoResources, Inc., a Colorado corporation, (the “Company,” “we” or “us”) is an independent oil and gas company engaged in the acquisition and development of oil and natural gas reserves through an active and diversified program which includes purchases of reserves, re-engineering, development and exploration activities primarily focused in Texas, the Gulf Coast and the Williston Basin areas of the United States. Our corporate headquarters and Southern Division operating office is located in Houston, Texas, and our Northern Division operating office is located in Denver, Colorado. We also have an additional operating office for the Northern Division in Williston, North Dakota.

Our strategy, which is further discussed below, calls for operations in multiple oil and gas basins and also includes a combination of acquisition, development and exploration activities. Management believes, our strategy allows us to manage risk and also take advantage of changing market conditions and regional differences in commodity prices, service costs and available infrastructure. At present our activities are principally focused on the development of our acreage positions in the Bakken shale trend in the Williston Basin and the Eagle Ford shale and Austin Chalk trends in Texas. As of March 9, 2012 we held approximately 54,700 net acres in the Bakken shale trend and 23,600 net acres in the Eagle Ford shale trend.

As of January 1, 2012, we had an estimated 29,244 MBOE of proved reserves being approximately 67% oil and 70% developed. Production for the year ended December 31, 2011 totaled 1,924 MBOE or 5,270 BOE per day of which 64% was oil. In addition, we have a general partner and operating interest in two managed limited partnerships, which are accounted for under the equity method of U.S. generally accepted accounting principles. Our share of partnership reserves, at January 1, 2012 was estimated at 1,217 MBOE, being 4% oil and 89% developed. See “Item 2. Properties” of this report for additional information related to our oil and gas reserves at January 1, 2012.

Recent Developments

Acquisition and Divestitures

During 2011 and into early 2012 we expanded our reserves and acreage positions through continued leasing efforts as well as pursuit of farm-in opportunities and acquisitions.

Most recently, on February 29, 2012, we closed an acquisition of producing wells and acreage in the Austin Chalk trend of east Texas in the Brookeland field area. We acquired varying working interests, with an average of approximately 72%, in producing and productive wells across approximately 170,000 net acres. Estimated total proved reserves associated with the acquisition were 2.5 Mmboe comprised of 24% oil, 28% NGLs and 48% gas (January 1, 2012 management estimates at SEC prices). The properties averaged 914 BOE/day of net production in December 2011 being 24% oil, 28% NGLs and 48% residue gas. Our net acquisition cost was $40.4 million, plus closing adjustments for normal operating activity and other customary purchase price adjustments. We funded this acquisition through borrowings on our credit facility.

On January 20, 2012, we closed an acquisition of unproved leasehold interests in McKenzie County, North Dakota in which we acquired approximately 3,700 net acres. Our net acquisition cost was $12.7 million and was funded with working capital and borrowings on our credit facility.

In December 2011, we sold approximately 1,800 net acres in Atascosa County, Texas for $4.6 million. For accounting purposes we used the cost recovery method to account for this sale; under this method proceeds have been recorded in the balance sheet as a reduction in the carrying value of the associated unproved properties.

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In August 2011, we closed an acquisition of producing oil and gas properties located in the Austin Chalk trend of east Texas. We acquired varying working interests in 11 producing and productive wells across 3,700 net acres in Tyler county Texas. Estimated total proved reserves associated with the acquisition were 0.6 Mmboe comprised of 25% oil, 17% NGLs and 58% gas (June 30, 2011 management estimates using forward NYMEX strip prices). Our net acquisition cost was approximately $11 million plus closing adjustments for normal operating activity and other customary purchase price adjustments. We funded the acquisition with working capital.

In November 2010, we purchased an 86.67% membership interest in Trigon Energy Partners LLC (“Trigon”) and recorded a $2.2 million non-controlling interest in our consolidated financial statements. Trigon held leases in the Eagle Ford shale trend of Texas. The acquisition cost was approximately $11.8 million. In June 2011, our membership interest decreased to 73.34% as a result of a $2.2 million capital contribution by the non-controlling interest holder. In September 2011, all assets of Trigon were distributed to its members and we deconsolidated the non-controlling interest in the financial statements.

Long-term Debt

On November 9, 2011, we entered into a Third Amended and Restated Credit Agreement (the “Credit Agreement”), which increased our senior secured revolving credit facility from $250 million to $450 million and extended the term of the credit agreement to November 9, 2016. The initial borrowing base of the credit facility was $180 million, subject to review and redetermination on May 1 and November 1 of each year. The Credit Agreement provides for interest rates at (a) LIBOR plus 1.75% to 2.75% or (b) the prime lending rate plus 0.75% to 1.75%, depending upon the amount borrowed and also requires the payment of commitment fees to the lender with respect to unutilized commitments. The commitment rate is 0.375% per annum if we utilize less than 50% of our borrowing base and .500% if we utilize 50% or greater of our borrowing base. We incurred costs of approximately $1.5 million to complete the amendment and we are amortizing these costs over the remaining life of the Credit Agreement; the amortization of these costs is included in interest expense. The banks participating in the credit facility include: Wells Fargo Bank, Comerica Bank, Compass Bank, U.S. Bank, The Frost National Bank, BMO Harris Financing, Inc, Royal Bank of Canada, and SunTrust Bank. We had no principal amounts outstanding under the credit facility at December 31, 2011. In February 2012, we borrowed $60 million under our credit facility to fund property acquisitions.

Stock Issuances

On January 19, 2011, we issued 5,175,000 shares of common stock (including the full exercise of the underwriters’ option to purchase an additional 675,000 shares of common stock) and 989,000 shares were sold by certain selling shareholders in a public offering, at a public offering price of $25.00 per share pursuant to an offering registered with the SEC. Our net proceeds from the offering were approximately $122.5 million after underwriting discounts and commissions, and other offering expenses of $6.9 million. Net proceeds from this offering were used to reduce indebtedness and for other corporate purposes.

Our Business Strategy

We pursue a value-driven growth strategy focused on pursuing projects that generate strong rates of return and shareholder value. This strategy is implemented through acquisitions, development drilling and exploration activities, currently focused on oil weighted projects in the Bakken trend in the Williston Basin of North Dakota and Montana and in the Eagle Ford and Austin Chalk trends of Texas. We focus on building production, reserves and cash flows while continually working to expand our undeveloped acreage and drilling inventory. We will continue to exploit our current assets and acreage positions particularly in the Bakken, Eagle Ford and Austin Chalk trends through cost-efficient drilling and completion activities, while also utilizing our technical staff to identify and evaluate other targeted areas or potential reservoirs or trends for future growth. In our Northern Division, our current efforts are focused on expanding our Bakken leasehold interests in targeted areas of the Williston Basin, including both North Dakota and eastern Montana. In our Southern Division, our current efforts are focused on growing our leasehold in the Eagle Ford and Austin Chalk trends, as well as other potential formations, located within reasonable regional proximity to our existing acreage positions and operations. Furthermore, as we continue to grow we will divest of some of our legacy conventional assets that are located outside our focus areas. Our divestitures are intended to improve the economic and strategic profile of our asset portfolio. While these legacy

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assets have contributed meaningfully to our historical production and cash flow, as we continue our growth they will become less significant and therefore may be sold with the proceeds re-deployed into our focus areas. Historically, our capital structure and diverse asset portfolio has allowed us to pursue a dynamic operating strategy whereby we have shifted our emphasis among acquisitions, development drilling and exploration activities in addition to adjusting our capital plans among regions and projects (i.e. oil vs. natural gas) all in an effort to take advantage of changing market conditions (i.e. commodity prices, price differentials and service costs). Although our asset portfolio will become more focused on the Bakken, Eagle Ford and Austin Chalk trends in the future, we believe our portfolio will be sufficiently diverse to allow us to pursue a similar dynamic strategy going forward whereby we can adjust our leasing, acquisition and drilling efforts according to changing market conditions.

Our business strategy includes:

• Accelerating the cost-effective development and exploration of our existing acreage positions with a focus on our properties in the Bakken, Eagle Ford and Austin Chalk trends;

• Expanding our acreage positions and drilling inventory in and around our focus areas through acquisitions and farm-in opportunities with an emphasis on operated positions and selective non-operated participations with other capable oil and gas operators;

• Generating additional exploration and development projects in and around our focus areas;

• Selectively divesting of legacy assets to high-grade our property portfolio and to lower corporate wide “per-unit” operating and administrative costs, and focus our attention on our current focus areas and new projects with greater development and exploitation potential;

• Pursuing value-accretive corporate merger and acquisition opportunities; and

• Obtaining additional capital, as needed, through the issuance of equity securities and/or through debt financing.

Our fundamental operating and technical strategy is complemented by management’s commitment to increasing shareholder value by:

• Maintaining a sound capital structure;

• Promoting industry and institutional partners into projects to manage our risk, enhance rates of return and lowering our net finding and development costs;

• Controlling capital, operating and administrative costs;

• Hedging a portion of production to provide a foundation of predictable cash flows to support development and exploration activities; and

• Divesting non-core assets to high-grade our property portfolio.

In the opinion of management, our strategy is appropriate for us because:

• It addresses multiple risks of oil and gas operations while providing shareholders with significant upside potential; and

• It results in “staying-power”, which management believes is essential to mitigate the adverse impacts of volatile commodity prices and financial markets and it is the strategy employed successfully in prior entities formed, acquired and operated by management.

The major components of our business strategy and related matters are briefly discussed below.

Development Activities – The largest part of our capital expenditures relates to the development and exploitation of non-producing reserves through drilling activities. Our operational and technical teams are focused on driving drilling and completion costs down while at the same time maximizing reserve recoveries in our focus areas. We plan to continue implementing new initiatives and technologies such as pad drilling, use of “skidable” rigs, and mass sliding sleeve completions that will result in cost savings while at the same time ensuring strong reserve recoveries. Additionally, in our focus areas, we conduct comprehensive regional geological and geophysical studies and detailed field studies of existing properties which usually result in identifying:

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• Specific areas of interest for us to pursue additional leasing, farm-out or other activities, intended to expand our acreage positions; and

• Additional development and exploration projects associated with existing properties to recover bypassed, undeveloped or under-developed reserves.

Acquisitions and Divestitures – The fundamental intent of our acquisition and divestiture activities is to continually high-grade our property portfolio. Such acquisitions of oil and gas producing or undeveloped properties, either through corporate or asset acquisitions, is intended to allow us to assemble a portfolio of properties with the potential for meaningful economic returns from (1) the application of operational and technical attention, (2) development of non-producing reserves, and (3) realization of exploration upside. We seek to acquire oil and gas interests with the characteristics of manageable risks, fairly predictable production and value enhancement potential. An important part of our post-acquisition activities associated with producing properties are re-engineering projects intended to implement more efficient production practices, increase production or mitigate production declines, lower per-unit operating expenses and/or reduce field down-time. Our current portfolio of producing properties includes certain non-core legacy properties that are providing production and cash flows to pursue other opportunities. Consistent with our growth and in order to devote our human resources toward our most significant projects, periodically we will divest of non-core assets.

Exploration – Our exploration activities are intended to provide significant upside potential; accordingly, we expect to continue to expand our exploration activities as our asset portfolio increases. This component of our strategy is designed to:

• Expand our inventory of substantive acreage and prospects;

• Fully develop acquired properties; and

• Realize substantial economic returns from exploration.

Corporate Mergers and Acquisitions – As a distinct part of our overall strategy, we pursue asset acquisitions and corporate merger and acquisition opportunities (“M&A”) as a means to increase shareholder value and liquidity. Historically, in prior entities, management has pursued and completed transactions which included both acquisitions whereby the company might acquire another entity and transactions where the company might be merged into or sold to another entity. Considerations for such mergers or acquisitions include, but are not limited to:

• Realization of increased shareholder value and liquidity;

• Greater visibility and acceptance in the capital markets;

• Lower cost of capital in the financial markets;

• The potential to increase assets in a core or targeted areas leading to greater size, scale, improved economics and operational efficiencies in our core areas;

• The opportunity to increase earnings and cash flow on a per share basis;

• Development and exploration potential that will add meaningfully to our proved reserves and production; and

• Improved per unit realizations and lower per unit operating and administrative costs.

In summary, we believe our business strategy will lead to growth in reserves, production, cash flow and profitability and therefore enhance shareholder value.

Marketing of Production

Our oil and gas production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field posted prices or market indices, plus or minus adjustments for quality or transportation. Natural gas is usually sold under a contract at a negotiated price based upon the “spot” market for gas sold in the area.

The vast majority of our oil and gas sales contracts and off-lease marketing arrangements are generally standard industry contracts with 30 to 90 day cancelation notice provisions. We do however have one long-term natural gas sales contract in our Williams County North Dakota project area in the Bakken Shale trend. Under the

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terms of this contract we have committed substantially all of the production for the life of our leases to one purchaser. In return for this commitment, the purchaser has committed to building a gas gathering system across our project area. The sales price under this contract is based on a posted market rate. In addition, as discussed elsewhere in this report, we have entered into short-term and long-term commodity hedge contracts in seeking to provide a foundation of predictable cash flows to support development and exploration activities.

Competition

In addition to being highly volatile, the domestic oil and gas business is highly competitive among many independent operators and major oil companies in the industry. Our competitors may possess financial resources and technical capabilities which are greater than those available to us and they may, therefore, be able to pay more for desirable properties or more effectively exploit productive prospects due to their size and ability to secure better service contracts.

Environmental Regulations

We conduct our operations according to high industry standards and in compliance with all applicable laws and regulations. Our operations are generally subject to numerous stringent federal, state and local environmental regulations under various acts including the Comprehensive Environmental Response, Compensation and Liability Act, the Federal Water Pollution Control Act, and the Resources Conservation and Recovery Act. For example, our operations are affected by diverse environmental regulations including those regarding the disposal of produced oilfield brines, other oil-related wastes, and additional wastes not directly related to oil and gas production. Additional regulations exist regarding the containment and handling of crude oil as well as preventing the release of oil into the environment. It is not possible to estimate future environmental compliance costs due in part, to the uncertainty of continually changing environmental initiatives. While future environmental costs can be expected to be significant to the entire oil and gas industry, we do not believe that our costs would be any more or less of a relative financial burden than others in our industry.

Foreign Operations and Export Sales

We do not have any interests, production facilities, or operations in foreign countries.

Employees

As of December 31, 2011, we had 77 full-time employees, 53 of which are management, technical and administrative personnel, and 24 of which are field employees. Contract personnel operate some of our producing fields under the direct supervision of our employees. We consider all relations with our employees to be good. We have no unions and are not the subject of any collective bargaining agreements.

Available Information

We maintain a website at the address www.georesourcesinc.com. We are not including the information contained on our website as part of, or incorporating it by reference into, this report. Through our website, we make available our Annual Report on Form

10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after we file such material with the SEC.

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Executive Officers of the Registrant

The following table sets forth certain information as of March 9, 2012, regarding our named executive officers:

Name	Age		Position(s) with the Company
Frank A. Lodzinski		62	President and Chief Executive Officer
Robert J. Anderson		50	Chief Operating Officer (Northern Division) and Executive Vice President Engineering and Acquisitions
Howard E. Ehler		67	Vice President and Chief Financial Officer
Timothy D. Merrifield		56	Executive Vice President—Geology and Geophysics
Francis M. Mury		60	Chief Operating Officer (Southern Division) and Executive Vice President

Frank A. Lodzinski has served as our President, Chairman and Chief Executive Officer since 2007. He has 40 years of oil and gas industry experience. In 1984, he formed Energy Resource Associates, Inc., which acquired management and controlling interests in oil and gas limited partnerships, joint ventures and producing properties. Certain partnerships were exchanged for common shares of Hampton Resources Corporation in 1992, which Mr. Lodzinski joined as a director and President. Hampton was sold in 1995 to Bellwether Exploration Company. In 1996, he formed Cliffwood Corp and in 1997, Cliffwood shareholders acquired controlling interest in Texoil, Inc. where Mr. Lodzinski served as CEO and President. In 2001, Texoil, Inc. was sold to Ocean Energy, Inc. In 2001, Mr. Lodzinski was appointed CEO and President of AROC, Inc., to direct the restructuring and ultimate liquidation of that company. In 2003, AROC completed a monetization, of oil and gas assets with an institutional investor and began a plan of liquidation in 2004. In 2004, Mr. Lodzinski formed Southern Bay Energy, LLC, the general partner of Southern Bay which acquired the residual assets of AROC, Inc., and he served as President of Southern Bay Energy, LLC since its formation. He holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan.

Robert J. Anderson has served as our Executive Vice President – Engineering & Acquisitions since April 2007 and was appointed to our Board of Directors and to the position of Chief Operating Officer – Northern Division in January 2012. He is a petroleum engineer and has been active in the oil and gas industry since 1987 with diversified domestic and international experience for both major oil companies (ARCO International/Vastar Resources) and independent oil companies (Hunt Oil/Hugoton Energy/Anadarko Petroleum). From October 2000 through February 2004, he was employed by Anadarko Petroleum Corporation as a petroleum engineer. From March 2004 through December 2004 he was employed by AROC, Inc. as Vice President, Acquisitions and Divestitures. He joined Southern Bay Energy, LLC in January 2005 as Vice President, Acquisitions and Divestitures. His professional experience includes acquisition evaluation, reservoir and production engineering and field development, and project economics, budgeting and planning. Mr. Anderson’s domestic acquisition and divestiture experiences include the Gulf Coast of Texas and Louisiana (offshore and onshore), east and west Texas, north Louisiana, Mid-Continent and the Rockies. His international experience includes Canada, South America and Russia. He has an undergraduate degree in Petroleum Engineering from the University of Wyoming (1986) and also holds an MBA, Corporate Finance, from the University of Denver (1988).

Howard E. Ehler has been our Chief Financial Officer and Principle Accounting Officer since April 2007. He was the Vice President and Chief Financial Officer of AROC, Inc. from May 2001 through December 2004. Since January 2005, Mr. Ehler has been employed by Southern Bay Energy, LLC as Vice President and Chief Financial Officer. He previously served as Vice President of Finance and Chief Financial Officer for Midland Resources, Inc. from March 1997 through October 1998. From November 1999 through April 2001 he performed independent accounting and auditing services in oil and gas as a sole practitioner in public accounting. He was employed in public accounting with various firms for over 21 years, including practice with Grant Thornton LLP, where he was admitted to the partnership. He has substantive experience in oil and gas banking, finance, accounting and reporting. In addition, his experience includes administration, tax, budgets, forecasts and cash management. Mr. Ehler holds an Accounting Degree from Texas Tech University (1966) and has been a Certified Public Accountant since 1970.

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Timothy D. Merrifield was appointed Executive Vice President – Geology and Geophysics in January 2012. Mr. Merrifield has over 30 years of industry experience. He has been employed by the Company since April 2007 and previously as Vice-President – Geology and Geophysics for our Southern Division where he successfully led our exploration and development activities. His prior experience includes both domestic and international projects and he has also had responsibility for our reservoir engineering and project management. He was employed by AROC, Inc. as Vice President – Exploration from November 1998 through December 2004. Since January 2005, he has been employed by Southern Bay Energy LLC as Vice President Geology and Geophysics. Additionally, he was employed by Forcenergy, Inc. from January 1997 to November 1998 as a Senior Explorationist and Great Western Resources, Inc. from January 1986 to January 1997 where he was promoted to Exploration Manager in February 1994. Prior to 1986 Mr. Merrifield was employed by L&B Oil Co., Inc., Core Laboratories, Inc., Mesa Petroleum and Atlantic Richfiled, Inc. He attended Texas Tech University.

Francis M. Mury has been Executive Vice President and Chief Operating Officer—Southern Division since April 2007. He has been active in the oil and gas industry since 1974. He was employed by AROC, Inc. as Executive Vice President from May 2001 through December 2004. Since January 2005, he has been employed by Southern Bay Energy LLC as Executive Vice President. Mr. Mury worked for Texaco, Inc. from July 1974 through March 1979, ending his tenure there as a petroleum field engineer. From April 1979 through December 1985, he worked for Wainoco Oil & Gas as a production engineer and drilling superintendent. From January 1986 to November 1989 he worked for Diasu Oil & Gas as an operations manager. He has worked with Mr. Lodzinski since 1989, including at Hampton Resources Corporation, where he served as Vice President – Operations from January 1992 through May 1995, and Texoil, Inc., where he served as Executive Vice President from November 1997 through February 2001. His experience extends to all facets of petroleum engineering, including reservoir engineering, drilling and production operations and further into petroleum economics, geology, geophysics, land and joint operations. Geographical areas of experience include the Gulf Coast (offshore and onshore), east and west Texas, Mid-Continent, Florida, New Mexico, Oklahoma, Wyoming, Pennsylvania and Michigan. Mr. Mury received a degree in Computer Science (1974) from Nicholls State University, Thibodeaux, Louisiana.

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Item 1A. Risk Factors

Set forth below are risks with respect to our Company. Readers should review these risks, together with the other information contained in this report. The risks and uncertainties we have described in this report are not the only ones we face. There may be additional risks and uncertainties that are not presently known to us, or that we presently deem immaterial, that may become material and also adversely affect our business. If any of the following risks develop into actual events, our business, financial conditions or results of operations could be material and adversely affected. See “Forward Looking Statements” at the beginning of this report for additional risks.

We are dependent upon the services of our chief executive officer and other executive officers.

We are dependent upon a limited number of personnel, including Frank A. Lodzinski, our Chief Executive Officer and President, and certain other management personnel and key employees. Failure to retain the services of these persons, or to replace them with adequate personnel in the event of their departure or termination, may have a material adverse effect on our operations and adversely affect the price of our common stock. There are no employment agreements with any of our officers currently exist, although we may consider such agreements in the future. We have no key-man life insurance on the lives of any of our executive officers.

We must successfully acquire or develop additional reserves of oil and gas.

Our future replacement of production of oil and gas is highly dependent upon our level of success in acquiring or finding additional reserves. The rate of production from our oil and gas properties generally decreases as reserves are produced. We may not be able to successfully acquire or develop additional oil and gas properties to cost effectively replace our reserves.

Intense competition in the oil and gas exploration and production segment could adversely affect our ability to acquire desirable properties prospective for oil and gas, as well as producing oil and gas properties.

The oil and gas industry is highly competitive. We compete with major integrated and independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than ours. These competitive factors could make future acquisitions of acreage and producing properties at economic prices difficult for us. We also face significant competition in attracting and retaining experienced, capable and technical personnel, including geologists, geophysicists, engineers, landmen and others with experience in the oil and gas industry.

The domestic oil and gas exploration and production industry is faced with shortages of personnel and equipment, and such shortages may adversely affect our operations and financial results.

The oil and gas industry, as a whole, suffers from an aging workforce and a shortage of qualified and experienced personnel. Our operations and financial results may be adversely impacted due to difficulties in attracting and retaining such personnel within our Company or within companies that provide materials and services to the industry. The substantial increase in oil prices in 2010 and 2011 has resulted in increased drilling and construction activity in the industry and shortages of personnel and equipment are present in our primary focus areas. Presently, personnel shortages and high labor costs are particularly prevalent in areas of high industry activity such as the Williston Basin of Montana and North Dakota, and the Eagle Ford trend of Texas. Additional personnel will likely be required in connection with our expansion plans, and the domestic oil and gas industry has in the past experienced significant shortages of qualified personnel in all areas of operations. Further, our expansion plans will likely require access to services and oil field equipment. Such equipment and operating personnel are currently in short supply.

The tightness in the availability of drilling rigs and field services in the Bakken Shale trend in North Dakota and Montana and the Eagle Ford trend in Texas could adversely affect our ability to execute our development plans within our budget on a timely basis.

Since 2009, we have experienced tightness in the availability of drilling rigs, services for pressure pumping and other services required for well completion in the Bakken trend in North Dakota and Montana and the Eagle Ford trend in Texas. During 2011 we experienced substantial delays between drilling and completion of many of our

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operated and non-operated wells in the Williston Basin. In the latter half of 2011, timing between drilling and well completion improved, but continued increases in drilling activity could lengthen delays. Increased delays could adversely affect production and reserve replacement, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. The lack of availability of these types of services has caused delays in our development and production operations and caused us to incur additional expenditures above what we had budgeted for those services. We cannot determine the magnitude or length of the tightness for these services, but should they persist or increase the cost or lack of availability of these services they could have a material adverse effect on our business, cash flows and their timing, financial condition and results of operations.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our financial condition and results of operations.

Our success depends on the results of our exploitation, exploration, development and production activities. Oil and natural gas exploration and production activities are subject to numerous significant risks some of which are beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in large part on our proper evaluation and assessment of data obtained through geophysical and geological analyses, production data, and engineering studies. Our evaluations and assessments could ultimately prove to be incorrect. Significant aspects of costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can render a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including:

• Shortages of or delays in obtaining equipment and qualified personnel such as we are currently experiencing;

• Pressure or irregularities in geological formations;

• Equipment failures or accidents;

• Adverse weather conditions, such as those experienced during the first half of 2011;

• Reductions in oil and natural gas prices;

• Issues associated with property titles; and

• Delays imposed by or resulting from compliance with regulatory requirements.

Volatile oil and natural gas prices could adversely affect our financial condition and results of operations.

Our most significant market risk is the price of crude oil and natural gas. Management expects energy prices to remain volatile and unpredictable. Moreover, oil and natural gas prices result from numerous factors that are outside of our control, including:

• Economic and energy infrastructure disruptions caused by geopolitical factors including but not limited to embargoes and sanctions on major producing countries and actual or threatened acts of war, or terrorist activities particularly with respect to oil producers in the Middle East, Nigeria and Venezuela;

• Weather conditions, such as hurricanes, including energy infrastructure disruptions resulting from those conditions;

• Changes in the global oil supply, demand and inventories;

• Changes in domestic natural gas supply, demand and inventories;

• The price and quantity of foreign imports of oil;

• Political conditions in or affecting other oil-producing countries;

• General economic conditions in the United Stated and worldwide;

• The level of worldwide oil and natural gas exploration and production activity;

• Technological advances affecting energy consumption; and

• The price and availability of alternative fuels.

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Lower oil and natural gas prices not only decrease revenues on a per unit of production basis, but also may reduce the amount of oil and natural gas that we can economically produce negatively impacting estimates of our economically recoverable proved reserves. We have attempted to mitigate the risks associated with commodity price fluctuations by hedging a portion of our production. However, substantial or extended declines in oil or natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity and ability to finance operations and planned capital expenditures.

Industry changes may adversely affect various financial measurements relating to our business and negatively affect the market price of our common stock.

Although we believe that our business strategy has and will allow us to continue our growth and increase operating efficiencies, unforeseen costs and industry changes could potentially have an adverse effect on return of capital and earnings per share. Future events and conditions could cause any such changes to be significant, including, among other things, adverse changes in:

• Commodity prices for oil, natural gas and liquid natural gas;

• Economically recoverable reserves;

• Operating results;

• Capital expenditure obligations; and

• Production levels.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

Oil and natural gas exploration, drilling and production activities are subject to numerous operating risks including the possibility of:

• Blowouts, fires and explosions;

• Personal injuries and death;

• Uninsured or underinsured losses;

• Unanticipated, abnormally pressured formations;

• Mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; and

• Environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination.

Any of these operating hazards could cause damage to properties, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages, which could expose us to significant liabilities.

We have hurricane and other weather-related risks associated risks in connection with our operations in the Texas and Louisiana Gulf Coast as well as North Dakota and Montana.

Because a portion of our oil and gas properties are located in or near coastal areas of the Texas and Louisiana Gulf, we have experienced in the past significant production curtailments due to hurricane damage. We could also be subject to production curtailments in the future resulting from hurricane damage to certain fields or, even in the event that producing fields are not damaged, production could be curtailed due to damage to facilities and equipment owned by oil and gas purchasers, or vendors and suppliers. We may also experience winter weather-related and spring thaw operational problems on our North Dakota and Montana properties. Due to severe winter weather and spring flooding in North Dakota and Montana in the first half of 2011 we had to shut in a number of our producing wells as well as delay several of our drilling and completion operations. We may in the future experience these operational problems due to severe weather and it will likely negatively impact our results of operations.

Insurance may not fully recover potential losses.

Although we believe that we are reasonably insured against losses to wells and associated equipment, potential operational or hurricane related losses could result in a loss of our reserves and properties and materially reduce our ability to self-fund exploration and development activities and property acquisitions. The insurance market, in general, and the energy insurance market in particular, have experienced substantial cost increases over

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recent years, resulting from significant losses associated with hurricanes and commercial losses. To offset the significant cost increases we increased our deductibles and made other modifications to coverage. The potential for loss, however, cannot be accurately or reasonably predicted. If we incur substantial damages or liabilities that are not fully covered by insurance or are in excess of policy limits, then our business, results of operations, and financial condition could be materially affected. Also, as is customary in the oil and gas business, we do not carry business interruption insurance. In the future, it is also possible that we will further modify insurance coverage or determine not to purchase some insurance because of high insurance premiums.

If oil and gas prices decrease or exploration efforts are unsuccessful, we may be required to write-down the capitalized cost of individual oil and gas properties.

A writedown of the capitalized cost of individual oil and gas properties could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved oil and gas reserves, if operating costs or development costs increase over prior estimates, or if exploratory drilling is unsuccessful. A writedown could adversely affect the trading prices of our common stock.

We use the successful efforts accounting method. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves are discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. All of our geological and geophysical costs on exploratory prospects are expensed as incurred.

The net capitalized costs of our oil and gas properties, on a field-by-field basis, may exceed the estimated future net cash flows of that field for periods of time when oil and gas prices are low. If so, pursuant to generally accepted accounting principles, we are required to record impairment charges to reduce the capitalized costs of each such field to its estimate of the field’s fair market value, even though other fields may have increased in value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges reduce earnings and shareholders’ equity.

Negative or downward revisions of oil and gas reserve estimates could adversely affect the trading price of our common stock. Oil and gas reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.

The market price of our common stock may be subject to significant decreases due to decreases in our estimated reserves, our estimated cash flows and other factors. Estimated reserves may be subject to downward revision based upon future production, results of future development, prevailing oil and gas prices, prevailing operating and development costs, SEC rules related to proved undeveloped reserves and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves, projecting future rates of production, and timing of development expenditures.

The estimates of future net cash flows from proved reserves and the standardized measure of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.

In addition, SEC rules generally require that proved undeveloped reserves that have not been drilled within five years be reclassified out of estimates of proved reserves; although such technically and economically recoverable reserves may be still owned or controlled by us. Accordingly, given the shortages of materials, equipment and human resources prevailing in the industry and also current low natural gas prices we may not drill certain proved undeveloped locations within the established five year time frame and therefore we may be required to reclassify such reserves out of our estimated proved undeveloped reserves. The effect of reclassifying such reserves would result in decreases in estimated proved reserve quantities and therefore could result in decreases in net income and earnings per share, resulting from increased depletion expense and possible impairments. These effects could have an adverse effect on our stock price.

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Our hedging activities may prevent us from realizing the benefits in oil or gas price increases.

In seeking to reduce our financial exposure to oil and gas price volatility, we have, and will likely continue to, enter into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. In a typical hedge transaction, we may fix the price, or establish a floor or a range, on a portion of our production over a predetermined period of time. If market prices exceed our hedge positions we will not receive the full market value for our production covered by those hedges. There are numerous risks associated with hedging activities such as the risk that reserves are not produced at rates equivalent to the hedged position, and the risk that production and transportation cost assumptions used in determining an acceptable hedge could be substantially different from the actual cost. In addition, the counter-party to the hedge may become unable or unwilling to perform its obligations under hedging contracts, and we could incur a material adverse financial effect if there is any significant non-performance. While intended to reduce the effects of oil and gas price volatility, hedging transactions may limit potential gains earned by us from oil and gas price increases and may expose us to the risk of financial loss in certain circumstances.

The adoption of derivatives legislation by the U. S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing certain portions of it in the near future. In July 2011, the CFTC granted temporary exemptive relief from certain swap regulation provisions of the legislation until December 21, 2011, or until the agency finalized the corresponding rules. In December 2011, the CFTC extended the potential latest expiration date of the exemptive relief to July 16, 2012. In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets, and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize other regulations, including critical rulemaking on the definition of “swap”, “swap dealer” and “major swap participant.” Depending on our classification, the financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The recent legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

The use of debt financing may adversely affect our business strategy.

We have used debt to fund a portion of our activities and we are using debt to fund a portion of our future acquisition and development activities. Any temporary or sustained inability to service or repay debt we incur will materially adversely affect our results of operations and financial condition and will materially adversely affect our ability to obtain other financing.

We are obligated to comply with financial and other covenants in our existing Credit Agreement that could restrict our operating activities, and the failure to comply could result in defaults that accelerate the payment of our debt.

Our Credit Agreement generally contains customary covenants, including, among others, provisions:

• Relating to the maintenance of the oil and gas properties securing the debt;

• Restricting our ability to assign or further encumber the properties securing the debt; and

• All of our obligations under our Credit Agreement are secured by substantially all of our assets.

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• A current ratio of not less than 1.0:1.0 excluding current hedge obligations; and

• A funded debt to EBITDAX ratio of not greater than 4.0:1.0.

As of the date of this report, we were in compliance with all such covenants. If we were to breach any of our debt covenants and not cure the breach within any applicable cure period, the lender could require us to immediately repay any outstanding debt amounts at the time, and if the debt is secured, could immediately begin proceedings to take possession of substantially all of our properties. Any such property losses would materially and adversely affect our cash flow and results of operations.

Global financial and economic circumstances may have impacts on our business and financial condition that we currently cannot predict.

Global financial markets may have an adverse impact on our business and our financial condition, and we may face challenges if conditions in the financial markets are inadequate to finance our activities at a reasonable cost of capital. While the current economic situation has improved since 2008 any deterioration in financial markets (or changes in lending practices) could have a material adverse impact on our lenders. Furthermore, adverse economic circumstances could cause customers, joint owners or other parties with whom we transact business to fail to meet their obligations to us. Additionally, market conditions could have a materially adverse impact on our commodity hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. Also, worldwide economic conditions could lead to reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a material negative impact on our revenues, results of operations and financial conditions.

Our properties may be subject to influence by third parties that do not allow us to proceed with planned explorations and expenditures.

We are the operator of a majority of our properties, but for many of our properties we own less than 100% of the working interests. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a joint operating agreement (“JOA”), where a single working interest owner is designated as the “operator” of the property. For properties where we own less than 100% of the working interest, whether operated or non-operated, drilling and operating decisions may not be within our sole control. If we disagree with the decision of a majority of working interest owners, we may be required, among other things, to postpone the proposed activity or decline to participate. If we decline to participate, we might be forced to relinquish our interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate, or forever relinquish its position. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, and an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated or curtailed as a result of future legislation.

Among the changes contained in the Obama Administration’s Fiscal Year 2013 budget proposal, released by the Office of Management and Budget on February 13, 2012, is the elimination or deferral of certain U.S. federal income tax deductions and credits currently available to domestic oil and gas exploration companies. Such changes include, but are not limited to, (i) the elimination of current deductions for intangible drilling and development costs; (ii) the elimination of the deduction for certain U.S. production activities for oil and gas properties; (iii) an extension of the amortization period for certain geological and geophysical expenditures and (iv) the repeal of the enhanced oil recovery credit. Some of these same proposals to repeal or limit oil and gas tax deductions and credits have been included in legislation that has recently been considered by Congress. It is unclear whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposal, or the passage of bills containing similar changes in U.S. federal income tax law could eliminate or defer certain tax deductions and credits that are currently available with respect to oil and gas exploration and development and could negatively affect our financial results.

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Recovery of investments in acquiring oil and gas properties is uncertain.

We cannot assure that we will recover the costs we incur in acquiring oil and gas properties. While the acquisition and development of oil and gas properties is based on engineering, geological and geophysical assessments, such data and analysis is inexact and inherently uncertain. There can be no assurance that any properties we acquire will be economically produced or developed. Re-engineering operations pose the risk that anticipated benefits, which may include reserve additions, production rate improvements or lower recurring operating expenses, may not be achieved, or that actual results obtained may not be sufficient to recover investments. Drilling activities, whether exploratory or developmental, are subject to mechanical and geological risks, including the risk that no commercially productive reservoirs will be encountered. Unsuccessful acquisitions, re-engineering or drilling activities could have a material adverse effect on our results of operations and financial condition.

There can be no assurance that we will be able to achieve continued growth in assets, production or revenue.

There can be no assurance that we will continue to experience growth in revenues, oil and gas reserves or production. Any future growth in oil and gas reserves, production and operations will place significant demands on us and our management and personnel. Our future performance and profitability will depend, in part, on our ability to successfully integrate acquired properties into our operations, develop such properties, hire additional personnel and implement necessary enhancements to our management systems.

The nature of our business and assets may expose us to significant compliance costs and liabilities.

Our operations involving the exploration, production, storage, treatment, and transportation of liquid hydrocarbons, including crude oil, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Compliance with all of these laws and regulations may represent a significant cost of doing business. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; and the issuance of injunctions that may restrict, inhibit or prohibit our operations; or claims of damages to property or persons.

Compliance with environmental laws and regulations may require us to spend significant resources.

Environmental laws and regulations may: (1) require the acquisition of a permit before well drilling commences; (2) restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; (3) prohibit or limit drilling activities on certain lands lying within wetlands or other protected areas; and (4) impose substantial liabilities for pollution resulting from past or present drilling and production operations. Moreover, changes in Federal and state environmental laws and regulations, as well as how such laws and regulations are administered, could occur and may result in more stringent and costly requirements which could have a significant impact on our operating costs. In general, under various applicable environmental regulations, we may be subject to enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability from third parties for civil claims by affected neighbors arising out of a pollution event. Laws and regulations protecting the environment may, in certain circumstances, impose strict liability rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time such acts were performed. We believe we are in compliance with applicable environmental and other governmental laws and regulations. In recent years, increased concerns have been raised over the protection of the environment. Legislation to regulate the emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Also, the EPA has recently undertaken significant efforts to collect information regarding greenhouse gas emissions and their effects.

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Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for crude oil and natural gas that we produce.

In December 2009, the U.S. Environmental Protection Agency, (“EPA”) determined that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”), present an endangerment to public health and the environment because emissions of such gasses are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one set of rules limit emissions of GHGs from motor vehicles and the other set of rules require certain Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for GHG emissions from certain large stationary sources. The EPA rules have tailored the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which may include certain of our operations, on an annual basis.

In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as government reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect our production and/or ability to book future reserves.

Hydraulic fracturing involves the injection of water, sand, and chemical additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. We engage third parties to provide hydraulic fracturing or other well stimulation services for us in connection with several wells or proposed wells for which we are the operator. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs, especially shale formations such as the Bakken and the Eagle Ford trends, where we have significant acreage. The process is typically regulated by state oil and natural gas commissions; however, the EPA, recently asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In February 2012, the U.S. Department of the Interior (the “DOI”) released draft regulations governing hydraulic fracturing on federal and Indian oil and gas leases to require disclosure of information regarding the chemicals used in hydraulic fracturing, advance approval for well-stimulation activities, mechanical integrity testing of casing, and monitoring of well-stimulation operations. In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic-fracturing process are adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and cause us to experience added delays or curtailment in the pursuit of exploration, development, or production activities.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic-fracturing practices. The EPA has commenced a study

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of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities and plans to propose these standards by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. These ongoing or proposed studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Colorado, Montana, Pennsylvania, Louisiana, Texas, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and additional well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and/or hydraulic fracturing in particular. These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and oil that we can economically produce. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities on a timely basis following leasing. Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry for attractive oil and gas properties and other E&P companies. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and manage effectively additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our hedging arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the use of debt or the issuance of equity. Even if our credit reviews are satisfactory, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could adversely affect our financial condition and results of operation.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could eliminate certain proposed drilling locations or materially delay the timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability and cost of capital, seasonal conditions, regulatory approvals, natural gas and oil prices,

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drilling and completion costs and drilling results. Because of these uncertainties, we do not know if all the numerous potential drilling locations we have identified and plan to drill ultimately will be drilled or if we will be able to produce oil or natural gas economically from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue making substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed, and in the future we intend to continue to finance, capital expenditures primarily with cash generated by operations, proceeds from bank borrowings, including under existing facilities, and sales of equity securities. Our cash flow from operations and access to capital are subject to a number of variables that may or may not be within our control, including:

• The level of oil and natural gas we are able to produce from existing wells;

• The prices at which our oil and natural gas production is sold;

• The results of our development programs associated with proved and unproved properties;

• Our ability to acquire, locate and produce new economically recoverable reserves;

• Global credit and securities markets; and

• The ability and willingness of lenders and investors to provide capital and the cost of that capital.

If our revenues or the borrowing base under our credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our credit facility restricts our ability to obtain new debt financing outside that facility. There can be no assurance as to the availability or terms of any additional or alternative financing.

If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing on acceptable terms could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to possible writedowns in the carrying value of our properties, a decline in our natural gas and oil reserves as well as our revenues and results of operations.

Changes in financial markets could result in significantly reduced access to public and private capital as well as substantially higher costs of capital if we are able to obtain capital.

Historically, we have obtained equity and debt capital to fund our growth strategy. We may require additional equity capital in order to pursue our business strategy and avoid excessive debt levels. Financial markets often change abruptly and we may not be able to attract investors that would provide equity capital to us at all, or the costs to obtain such capital may be prohibitive. To the extent that we may attract capital, the costs of such capital could increase appreciably and such capital may take forms, such as preferred stock or convertible debt, which would be senior to our common stock. We believe that the ability to attract capital at reasonable costs is critical to our long-term growth strategy, particularly due to the depleting nature of oil and gas operations.

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Effects of inflation and pricing may impact our demand for goods and services.

The oil and gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Demand for equipment and services have caused costs to increase significantly since 2008. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices would also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices generally impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel.

There are a substantial number of shares of our common stock eligible for future sale in the public market. The sale of a large number of these shares could cause the market price of our common stock to fall.

There were 25,625,792 shares of our common stock outstanding as of March 9, 2012. Members of our management owned approximately 4,450,311 shares of our common stock, representing 17% of our outstanding common stock as of March 9, 2012. Sale of a substantial number of these shares would likely have a significant negative effect on the market price of our common stock, particularly if the sales are made over a short period of time. These shares may be sold publicly pursuant to an effective registration statement with the SEC.

If our shareholders, particularly management and their affiliates, sell a large number of shares of our common stock, the market price of shares of our common stock could decline significantly. Moreover, the perception in the public market that our management and affiliates might sell shares of our common stock could have a depressing effect on the market price of our shares.

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Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

Offices

Our principal executive office is located at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, where we occupy approximately 15,800 square feet of office space. Our Northern Division office, consisting of approximately 5,000 square feet, is located at 475 17^th Street, Suite 1210, Denver, Colorado 80202. Our Williston office consists of approximately 4,000 square feet and is located at 1407 West Dakota Parkway, Williston, North Dakota 58801.

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Oil and Gas Reserve Information

All of our oil and gas reserves are located in the United States. Unaudited information concerning the estimated net quantities of all of our proved reserves and the standardized measure of future net cash flows from the reserves is presented in “Note N: Supplemental Financial Information for Oil and Gas Producing Activities — Unaudited” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report. The reserve estimates have been prepared by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. We have no long-term supply or similar agreements with foreign governments or authorities.

Set forth below is a summary of our oil and gas reserves as of December 31, 2011. We did not provide any reserve information to any federal agencies in 2011 other than to the SEC.

	Oil (Mbbl)		Gas (Mmcf)		Present Value Discounted at 10% ($M) (1)
Proved developed		13,906		38,514	$	486,191
Proved undeveloped		5,787		18,791		128,708
Total Proved		19,693		57,305	$	614,899

Oil and Gas Reserve Quantities

	Oil (Mbbl)			Gas (Mmcf)
Proved reserve quantities, January 1, 2011		14,393			57,554
Purchases of minerals-in-place		134			2,195
Extensions and discoveries		5,265			4,687
Production		(1,222	)		(4,209	)
Revisions of quantity estimates		1,123			(2,922	)
Proved reserve quantities, December 31, 2011		19,693			57,305
Proved developed reserve quantities
December 31, 2010		11,231			39,097
December 31, 2011		13,906			38,514

(1) Present Value Discounted at 10% (“PV10”) is a Non-GAAP measure that differs from the GAAP measure “standardized measure of discounted future net cash flows” in that PV10 is calculated without regard to future income taxes. Management believes that the presentation of PV10 value is relevant and useful to our investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, management uses, and believes the industry generally uses, the PV10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties.

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PV10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For presentation of the standardized measure of discounted future net cash flows, please see “Note N: Supplemental Financial Information for Oil and Gas Producing Activities—Unaudited” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report. The table below titled “Non-GAAP Reconciliation” provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows.

Partnership Operations and Reserves as of January 1, 2012 (not included above):

The reserve quantities and values set forth above do not include our interest in two affiliated partnerships, discussed directly hereafter.

We hold an approximate 30% general partnership interest in SBE Partners, LP (“SBE Partners”) which owns interests in the Giddings field (as discussed further below in “Description of Noteworthy Properties”). In addition, we also hold the general partner interest in OKLA Energy Partners, LP (“OKLA”) which owns working interests in producing oil and gas properties in Oklahoma. Our 2% partnership interest in OKLA increases to 35.66% if the limited partner realizes a contractually specified rate of return (reversionary interest).

The following table represents our estimated share (excluding our reversionary interests) of the affiliated partnerships’ reserves and estimated present value of future net income discounted at 10% (in thousands), using SEC guidelines.

	Affiliated Partnership Reserves
	Oil (Mbbl)		Gas (Mmcf)		Present Value Discounted at 10%($M) (1)
Proved developed		48		6,196	$	9,095
Proved undeveloped		6		784		480
Total		54		6,980	$	9,575

(1) See footnote (1) to the above table for a definition of Present Value Discounted at 10%.

Non-GAAP Reconciliation (in thousands)

The following table reconciles our direct interest in oil and gas reserves as of December 31, 2011:

Present value of estimated future net revenues (PV10)	$	614,899
Future income taxes, discounted at 10%		(188,073	)
Standardized measure of discounted future net cash flows	$	426,826

The following table reconciles our indirect interest, through our affiliated partnerships, in oil and gas reserves as of December 31, 2011:

Present value of estimated future net revenues (PV10)	$	9,575
Future income taxes, discounted at 10%		(2,534	)
Standardized measure of discounted future net cash flows	$	7,041

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality

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of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of the estimates, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.

Proved Undeveloped Reserves

From January 1, 2011 to January 1, 2012, our proved undeveloped reserves (“PUDs”) increased 43% from 6,238 MBOE to 8,919 MBOE, or an increase of 2,681 MBOE. This increase was primarily attributable to successful drilling activity in 2011 in the Bakken Shale trend of North Dakota. We added 3,387 MBOE as a result of successful drilling in 2011 and the commensurate PUDs associated with such drilling. During 2011 we did not have any acquisitions that increased our PUDs. There were 182 MBOE that were no longer deemed to be economic PUDs at year-end. Reserves of 568 MBOE were moved from the PUD reserve category to the proved developed or the proved developed non-producing category through the drilling of 26 gross wells. We incurred approximately $6.2 million in capital expenditures during 2011 in converting these 26 gross PUD wells to the proved developed reserve category. The remaining change in PUDs of 44 MBOE was a result of increased prices and performance revisions over the time period. Based on our 2011 year end independent engineering reserve report, we plan to drill all of our individual PUD drilling locations within five years.

Preparation of Reserve Estimates

We have engaged an independent petroleum engineering consulting firm, Cawley Gillespie & Associates, Inc. (“CG&A”), to prepare our annual reserve estimates and have relied on their expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines.

The technical person primarily responsible for the preparation of the reserve report is Mr. Robert Ravnaas, Executive Vice President at CG&A. He earned a Bachelor’s of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder in 1979, and a Master’s of Science degree in Petroleum Engineering from the University of Texas at Austin in 1981. Mr. Ravnaas is a Registered Professional Engineer in Texas and has more than 30 years of experience in the estimation and evaluation of oil and gas reserves. He is also a member of the Society of Petroleum Geologists, and Society of Professional Well Log Analysts.

Our Executive Vice President, Engineering and Acquisitions, who also serves as our Chief Operating Officer for our Northern Region is a qualified reserve estimator and auditor and is primarily responsible for overseeing our independent petroleum engineering firm during the preparation of our reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelors of Science degree in Petroleum Engineering from the University of Wyoming, 1986; Masters of Business Administration degree from the University of Denver, 1988; member of the Society of Petroleum Engineers since 1985; and more than 24 years of practical experience in estimating and evaluating reserve information with more than five years of those being in charge of estimating and evaluating reserves.

We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest, and production data. The relevant field and reservoir technical information, which is updated annually, is assessed for validity when our independent petroleum engineering firm has technical meetings with our engineers, geologist, operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to our internal controls over financial reporting, and they are incorporated in our reserve database as well and verified internally by us to ensure their accuracy and completeness. Once the reserve database has been updated with current

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information, and the relevant technical support material has been assembled, our independent engineering firm meets with our technical personnel to review field performance and future development plans in order to further verify the validity of estimates. Following these reviews the reserve database is furnished to CG&A so that it can prepare its independent reserve estimates and final report. The reserve estimates prepared by CG&A are reviewed and compared to our internal estimates by our Executive Vice President, Engineering and Acquisitions and staff in our reservoir engineering department. Material reserve estimation differences are reviewed between CG&A’s reserve estimates and our internally prepared reserves on a case-by-case basis. An iterative process between CG&A and us regarding any significant differences allows for additional data to be provided in order to address the differences. If the supporting documentation will not justify any additional changes, the CG&A reserves are accepted. In the event that additional data supports a reserve estimation adjustment, CG&A will analyze the additional data, and may make any changes it deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final estimates provided by CG&A. Access to our reserve database is restricted to specific members of our reservoir engineering department.

Net Oil and Gas Production, Average Price and Average Production Cost

The net quantities of oil and gas produced and sold by us for each of the three years ended December 31, 2011, the average sales price per unit sold and the average production cost per unit are presented below.

	2011		2010		2009
Oil Production (MBbls)		1,222		1,060		851
Gas Production (MMcf)		4,209		4,789		4,944
Total Production (MBOE)*		1,924		1,858		1,675
Average sales price (net of hedging):
Oil per Bbl	$	88.42	$	70.33	$	61.09
Gas per Mcf	$	5.36	$	5.30	$	3.97
BOE	$	67.89	$	53.78	$	42.76
Production cost per BOE**	$	12.25	$	10.60	$	10.54

* Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE).

** Excludes ad valorem taxes (which are included in lease operating expenses on our consolidated statements of income) of $1.2 million, $1.3 million, and $1.1 million in 2011, 2010, and 2009, respectively and severance taxes.

Our Giddings field in east Texas contained 17%, 22% and 28% of our total proved reserves as of December 31, 2011, 2010, and 2009, respectively. No other single field accounted for 15% or more of our proved reserves in 2011, 2010 or 2009. The net quantities of oil and gas produced and sold by us for the each of the three years ended December 31, 2011, the average sales price per unit sold and the average production cost per unit for our Giddings field are presented below.

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Giddings Field
	2011		2010		2009
Oil Production (MBbls)		33		27		7
Gas Production (MMcf)		2,267		3,024		3,020
Total Production (MBOE)*		411		531		510
Average sales price (before the effects of hedging):
Oil per Bbl	$	87.59	$	74.26	$	71.14
Gas per Mcf	$	3.61	$	4.83	$	3.54
BOE	$	27.02	$	31.25	$	21.80
Production cost per BOE**	$	3.78	$	3.12	$	2.00

* Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE).

** Excludes ad valorem taxes and severance taxes

Our oil production is sold to large petroleum purchasers. Due to the quality and location of our crude oil production, we may receive a discount or premium from index prices or “posted” prices in the area. Our gas production is sold primarily to pipelines and/or gas marketers under short-term contracts at prices which are tied to the “spot” market for gas sold in the area. Natural gas liquids have been converted to Mcf in the table above.

In 2011, three purchasers each accounted for 12% of our consolidated oil and gas revenues. In 2010, two purchasers each accounted for 12% of our consolidated oil and gas revenues and one purchaser accounted for 11%. In 2009, one purchaser accounted for 17% of our consolidated oil and gas revenues, two purchasers accounted for 15% each of our consolidated oil and gas revenues, and one accounted for 11%. No other single purchaser accounted for 10% or more of our oil and gas revenues in 2011, 2010 or 2009. There are adequate alternate purchasers of our production such that we believe the loss of one or more of the above purchasers would not have a material adverse effect on our results of operations or cash flows.

Gross and Net Productive Wells

As of December 31, 2011, our total gross and net productive wells were as follows:

Productive Wells

Oil		Gas		Total
Gross Wells	Net Wells	Gross Wells	Net Wells	Gross Wells	Net Wells
899	275.0	443	132.5	1,342	407.5

* A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractions of working interests we own in gross wells. Productive wells are producing wells plus shut-in wells we deem capable of production. Horizontal re-entries of existing wells do not increase a well total above one gross well.

** We have working interests in 11 gross wells with completions into more than one productive zone; in the table above these wells with multiple completions are only counted as one gross well.

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Gross and Net Developed and Undeveloped Acres

As of December 31, 2011, we had total gross and net developed and undeveloped leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated or permitted by state regulatory authorities.

Gross acres are those acres in which working interest is owned. The number of net acres represents the sum of fractional working interests we own in gross acres.

	Developed				Undeveloped				Total
State	Gross		Net		Gross		Net		Gross		Net
Texas		129,014		65,117		49,306		23,656		178,320		88,773
N. Dakota		78,577		23,462		93,562		35,730		172,139		59,192
Colorado		3,310		2,404		40,925		20,276		44,235		22,680
Oklahoma		55,273		10,564		321		16		55,594		10,580
Alabama		42,480		21,420		—		—		42,480		21,420
Louisiana		31,707		11,083		5,134		2,959		36,841		14,042
Montana		11,921		8,705		10,664		6,193		22,585		14,898
All Others		4,636		3,649		—		—		4,636		3,649
Total		356,918		146,404		199,912		88,830		556,830		235,234

Exploratory Wells and Development Wells

Set forth below for the three years ended December 31, 2011 is information concerning the number of wells we drilled during the years indicated.

	Net Exploratory Wells Drilled				Net Development Wells Drilled				Total Net Productive and Dry Wells
Year	Productive		Dry		Productive		Dry		Drilled
2011		1.90		—		8.60		—		10.50
2010		0.48		—		5.82		0.52		6.82
2009		—		0.12		5.61		—		5.73

Present Activities

At March 9, 2012, we had 50 gross (6.9 net) wells in the process of drilling or completing.

Supply Contracts or Agreements

As of December 31, 2011 we had one natural gas sales contract in our Williams County North Dakota project area in the Bakken trend. Under the terms of this contract we have committed substantially all of the production for the life of our leases in this area to one purchaser. In return for our life of lease commitment, this purchaser has committed to building a gas gathering system across our project area. The sales price under this contract is based on a monthly posted market price. As of December 31, 2011, the majority of our production (aside from the aforementioned contract) is marketed under short-term contracts customary in division orders and off lease marketing agreements with the industry. We also engage in hedging activities as discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Description of Major Properties and General Strategy

We are the operator of properties containing approximately 75% of our proved oil and gas reserves. As operator we are able to directly influence exploration, development and production operations. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations, and have provided a solid foundation for our technical staff to pursue the development of our undeveloped acreage, further develop our existing properties and also generate new projects that we believe have the potential to increase our shareholder value. We are currently focused on three plays, being the Bakken and Three Forks formations in the Williston Basin, the Eagle Ford trend in Texas and the Austin Chalk trend in Texas. It is our intent to continue to expand our acreage and drilling inventory in these areas. Further, although we believe that many of our existing conventional fields have additional exploration and exploitation opportunities, as further discussed below, many of these fields will become divestiture candidates over the next few years. We will likely retain some legacy properties, provided they are profitable and located in reasonable proximity to our focus areas.

As is common in our industry we participate in non-operated properties on a selective basis; our non-operating participation decisions are dependent on the technical and economic nature of the projects and the operating expertise and financial standing of the operators. The following is a description of our major oil and gas properties.

Bakken Shale and Three Forks Formations, Williston Basin Overview – We believe the Bakken Shale and Three Forks formations in the Williston Basin represent a large North American oil deposit. Our opinion is supported by our own geological and engineering studies as well as reports from federal and state agencies and the industry in general. Our Bakken shale properties are located primarily in Mountrail, Williams and McKenzie counties in North Dakota and in Roosevelt and Richland counties in eastern Montana. Our focus is on the Middle Bakken and Three Forks formations and as of March 9, 2012 we have working interests in approximately 54,700 total net acres currently prospective for the Bakken and Three Forks formations. This acreage is comprised of 27,800 net acres in our Williams County project area, 12,900 net acres in our eastern Montana project area, 9,700 net acres in our Mountrail County project area, and 4,300 net acres in our McKenzie Line project area. We anticipate operating the majority of the spacing units in our Williams County and eastern Montana project areas, while we will primarily be non-operated working interest participants in most of the spacing units in our Mountrail County and McKenzie Line project areas. We are currently running two operated rigs in our Williams County and eastern Montana project areas and plan to bring on a third rig in the second quarter of 2012. All of these Bakken and Three Forks producers are from horizontal wells which initially flow without artificial lift and subsequently produce with the aid of rod pumps. Consistent with our operating strategy, during 2009 through early 2012, we increased our acreage positions in and around each of our four project areas. Most recently, in January 2012 we closed an acquisition of 3,700 net acres in our McKenzie Line project area. We will continue to lease or otherwise acquire or trade for acreage within and around all of our project areas in the Bakken Shale trend during 2012.

Williams County Project Area (Northwest Williams County, North Dakota) – Our Williams County project area is comprised of 27,800 net acres (primarily operated) in northwest Williams County, where we have lease positions in 91 1,280 acre spacing units. Our average working interest in this project area is approximately 34%. We originated this project and brought in industry partners on a promoted basis in 2010. We retained operations within a specified area of mutual interest. Drilling began in the project area in 2010. As of March 9, 2012, we have drilled 18 operated wells, participated in two non-operated wells and have two wells drilling in this project area. These wells are all in varying stages of completion and production operations. For the quarter ended December 31, 2011, total production net to our interest in our Williams County project area was approximately 346 BOE/day and was approximately 96% oil.

Eastern Montana Project Area (Roosevelt and Richland Counties, Montana) – In our eastern Montana project area, we have approximately 12,900 net acres with approximately 9,400 net acres being operated by us and the remainder operated by various industry partners. To date we have drilled one operated well in this project area and have participated in five non-operated wells. For the quarter ended December 31, 2011, the total production net to our interest in our eastern Montana project area was approximately 127 BOE/day and was approximately 94% oil.

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Mountrail County Project Area (Primarily Mountrail County, North Dakota) – We currently have approximately 9,700 net non-operated acres in our Mountrail County project area with working interests ranging from 1% to 14%. Our principal drilling activities in this area are through Slawson Exploration Company, Inc. (“Slawson”), but we also participate in this area with several other industry participants. We have been a non-operating partner in this project area since 2007. Drilling activities in this project area increased appreciably in 2011 as Slawson and our other operating partners increased their rig counts. To date, we have participated in over 110 wells with Slawson and we have also participated with nominal interests in over 300 wells with other operators in this project area. For the quarter ended December 31, 2011, total production net to our interest in this project area was approximately 1,525 BOE/day and was approximately 92% oil.

McKenzie Line Project Area (Primarily McKenzie and Southern Williams Counties, North Dakota) – Our McKenzie Line project area is comprised of approximately 4,300 net acres in McKenzie and southern Williams counties, North Dakota. Our acreage in this project area is primarily operated by Zavanna, LLC, an unaffiliated party. We hold varying working interests in this acreage. As of March 9, 2012, we have participated in the drilling of three wells that are waiting on completion with 1 well currently being drilled.

Eagle Ford Project Area (Southwest Fayette and Northeast Gonzales Counties, Texas)—Our Eagle Ford properties are located principally in southwest Fayette and northeast Gonzales counties of Texas where we are the operator. In southwest Fayette County, we have entered into agreements with an industry partner, which established an area of mutual interest and resulted in a cash receipt of $20 million in 2010 for a 50% undivided interest in our acreage. This agreement provided for our partner to fund 100% of the cost of drilling and completion in the first six wells, in which we retained a 50% interest. The agreement also provides that we are the operator of this project area and allows for additional leasing and an overriding royalty interest to us in certain leases. Our acreage position in the Eagle Ford totaled approximately 23,600 net acres as of March 9, 2012. We have drilled ten wells to date with seven wells currently on production and the remaining three waiting on completion. At present, we have two dedicated rigs under contract and drilling in the project. All of these Eagle Ford producers are from horizontal wells which initially flow without artificial lift and subsequently produce with the aid of gas lift, rod pump or other form of artificial lift. Our net working interests in our Eagle Ford drilling units range from 35% to 55% with an average working interest of approximately 48%. Our initial drilling began in January 2011 and for the quarter ended December 31, 2011, total production net to our interest in the Eagle Ford trend was approximately 176 BOE/day and was approximately 94% oil. Further we believe there are other potentially productive formations across our acreage position in this project area.

Austin Chalk Trend – Given our past and recent successes in the Austin Chalk trend of Texas we are generally working the trend across Texas from the Giddings field, where we have properties in Brazos, Burleson, Fayette, Grimes, Lee, Montgomery and Washington counties to the Brookeland field where we recently acquired properties located in Newton, Jasper, Sabine, Tyler and Polk counties. We intend to expand our Austin Chalk holdings and to further increase our near term and longer term drilling inventory. Much of our acreage is HBP or otherwise held by long-term leases. We believe our holdings across the Austin Chalk trend may provide additional opportunities related to other formations including potentially the Buda, Edwards, Georgetown, Wilcox, Woodbine (Eaglebine) and Yegua formations.

All of these Austin Chalk wells are horizontal producers that initially flow without artificial lift at high rates and subsequently produce through rod pumps, compression, and other production methods.

Giddings Field Project Area (Brazos, Burleson, Fayette, Grimes, Lee, Montgomery and Washington Counties, Texas)—We have an average direct working interest of 36% across our producing properties in this project area. In addition, we are the general partner and own approximately 30% of a limited partnership that has an average 56% working interest with an average 43% net revenue interest in the Giddings field project area. Excluding our southwest Fayette County acreage, our acreage position is approximately 35,000 net acres, with approximately 29,000 net acres held directly and approximately 6,000 net acres held through our interest in a limited partnership. From 2007 to early 2010, when we suspended most of our drilling operations in this project area due to low gas prices, we drilled 16 wells with a 100% success rate. We have an estimated 20 additional Austin Chalk drilling locations and believe the acreage is prospective for the Yegua, Georgetown and other formations. In 2011, we drilled one operated “oily” Chalk well in Grimes County and also participated in another “oily” Chalk well in southwest Fayette County. We anticipate drilling a select number of additional “oily” locations going forward on our southwest Fayette county acreage. For the quarter ended December 31, 2011, total production net to our interest in the Giddings field project area was approximately 1,401 BOE/day and was approximately 73% gas. An additional 806 net BOE/day (89% gas) was attributable to our share of the limited partnership.

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Brookeland Field Project Area (Jasper, Newton, Sabine and Tyler Counties, Texas) – We entered the Brookeland Field project area in August 2011 through the acquisition of producing properties and 3,700 net acres in Tyler counties for approximately $11 million. For the quarter ended December 31, 2011, the production from this portion of the field net to our interest was approximately 314 BOE/day and was approximately 77% gas. We further expanded our presence in this project area in February 2012 through the acquisition of additional producing properties and approximately 170,000 net acres in Newton, Jasper and Sabine counties at a cost of $40.4 million. Our working interests in this project area vary but average approximately 72%. This newly acquired property averaged 914 BOE/day of net production in December 2011 being 24% oil, 28% NGLs and 48% residue gas. However, as the effective date of the acquisition was January 1, 2012, we did not include this production or related revenue and cash flow in our Consolidated Statements of Income of the year ended December 31, 2011.

Other Properties – We also operate conventional legacy properties primarily located in Louisiana, Montana/North Dakota, New Mexico and west Texas, and other areas in the Gulf Coast region. For the quarter ended December 31, 2011, all of these properties collectively produce approximately 36% of our total production for the period (72% oil). Many, but not all, of these properties will ultimately become divestiture candidates as we continue our growth in our focus areas. Properties we retain will generally be located near our focus areas and will have upside potential. As we have done with prior divestitures we may only sell shallow rights or unitized zones within these properties and thus retain all or a portion of “deeper mineral rights”, below producing depths, thereby retaining exposure to potentially promising exploratory opportunities. We intend to conduct limited drilling operations on a number of these fields to expand near term production and demonstrate upside potential in order to maximize future divestiture proceeds. The following table indicates our fourth quarter 2011 production rates from these more significant conventional legacy properties.

	Avg. Daily Production—4th Qtr 2011
Conventional/Legacy Property Area	Boe/d		% Oil
Louisiana		754		96	%
Montana/North Dakota		508		94	%
New Mexico/West Texas		322		67	%
Gulf Coast/Other		643		31	%
Total		2,227		73	%

Title to Properties

It is customary in the oil and gas industry to make a limited review of title to undeveloped oil and gas leases at the time they are acquired. It is also customary to obtain more extensive title examinations prior to the commencement of drilling operations on undeveloped leases or prior to the acquisition of producing oil and gas properties. With respect to the future acquisition of both undeveloped and proved properties, we plan to conduct title examinations on such properties in a manner consistent with industry and banking practices. We have obtained title opinions, title reports or otherwise conducted title investigations covering substantially all of our producing properties and believe we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, overriding royalty interests, and other burdens which we believe do not materially interfere with the use or affect the value of such properties. Our credit facility is secured by substantially all of our oil and gas properties (see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources”).

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Item 3. Legal Proceedings

We are not 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 us.

Item 4. Mine Safety Disclosures

Not applicable

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock trades on The NASDAQ Global Select Market under the Symbol “GEOI.” The following table sets forth, for each of the periods indicated, the high and low sales prices per share of our common stock as reported by The NASDAQ Global Select Market. These trade prices may represent prices between dealers and do not include retail markup, markdowns or commissions.

	High		Low
2011
Fourth Quarter	$	30.95	$	14.56
Third Quarter	$	27.98	$	17.61
Second Quarter	$	32.37	$	20.02
First Quarter	$	32.94	$	22.51
2010
Fourth Quarter	$	23.44	$	15.83
Third Quarter	$	16.43	$	13.01
Second Quarter	$	17.87	$	13.32
First Quarter	$	16.25	$	11.29

As of March 9, 2012, there were 504 holders of record of our common stock. We believe that there are also 7,418 additional beneficial owners of our common stock held in “street name.”

Dividend Policy

We have never paid dividends on our common stock and do not intend to pay a dividend in the foreseeable future. Furthermore, our Credit Agreement restricts the payment of cash dividends. The payment of future cash dividends on common stock, if any, will be reviewed periodically by our Board of Directors and will depend upon, among other things, our financial condition, funds available for operations, the amount of anticipated capital and other expenditures, our future business prospects and any restrictions imposed by our present or future bank credit arrangements.

The following information in this Item 5 of this report is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Securities Exchange Act, and will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such a filing.

The following graph compares on a cumulative basis changes since December 31, 2006 in (a) the total shareholder return on our common stock with (b) the total return on the Standard & Poor’s Composite 500 Index and (c) the total return on the Dow Jones U.S. Oil & Gas Index. Such changes have been measured by dividing (a) sum of (i) the amount of dividends for the measurement period, assuming dividend reinvestment, and (ii) the difference between the price per share at the end of and the beginning of the measurement period, by (b) the price per share at the beginning of the measurement period. The graph assumes $100 was invested on December 31, 2006 in our common stock, the Standard & Poor’s Composite 500 Index and the Dow Jones U.S. Oil & Gas Index.

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	2006		2007		2008		2009		2010		2011
GeoResources, Inc.	$	100.00	$	140.19	$	135.36	$	212.77	$	345.95	$	456.54
Standard & Poors’s Composite 500 Index	$	100.00	$	103.53	$	63.69	$	78.62	$	88.67	$	88.67
Dow Jones U.S. Oil & Gas Index	$	100.00	$	133.01	$	84.12	$	96.73	$	113.62	$	116.26

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Item 6. Selected Financial Data

The following selected financial data contained in this table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and the accompanying notes thereto included elsewhere in this report.

	Year ended December 31
	2011			2010			2009			2008			2007
A. Summary of Operating Data
Production
Oil (Mbls)		1,222			1,060			851			743			392
Natural gas (MMcf)		4,209			4,789			4,944			2,962			1,648
Barrel of oil equivalent (MBOE)		1,924			1,858			1,675			1,236			667
Average realized prices:
Oil (per bbl)	$	88.42		$	70.33		$	61.09		$	82.42		$	67.20
Natural gas (per Mcf)	$	5.36		$	5.30		$	3.97		$	8.12		$	6.19
B. Summary of Operations (in thousands, except per share amounts):
Oil and gas revenues	$	130,608		$	99,913		$	71,618		$	85,263		$	36,518
Total revenues		137,748			107,017			80,998			94,606			40,115
Lease operation and workover expenses		27,434			22,906			21,570			26,432			12,910
Production taxes		8,028			6,589			4,193			7,517			2,880
Depletion and depreciation		27,659			24,686			22,409			16,007			7,507
Pretax earnings		51,242			35,254			14,842			21,291			7,949
Income tax expense		19,991			11,923			5,067			7,769			4,880
Net income		31,251			23,331			9,775			13,522			3,069
Net income attributable to GeoResources, Inc.		31,338			23,331			9,775			13,522			3,069
Net income per share:
Basic	$	1.24		$	1.18		$	0.59		$	0.87		$	0.25
Diluted	$	1.22		$	1.16		$	0.59		$	0.86		$	0.25
C. Summary Balance Sheet Data at Year End (in thousands):
Net property, plant and equipment	$	378,552		$	302,891		$	248,386		$	181,580		$	181,443
Total assets		487,691			359,690			304,297			243,534			240,358
Working capital		36,293			8,292			11,946			11,883			7,371
Long-term debt		—			87,000			69,000			40,000			96,000
Stockholders’ equity		368,311			201,735			174,677			140,995			68,032
D. Adjusted EBITDAX (in thousands) (1):
Net income attributable to GeoResources, Inc.	$	31,338		$	23,331		$	9,775		$	13,522		$	3,069
(Gain) on sale of property and equipment		(865	)		(953	)		(1,355	)		(4,362	)		(49	)
Interest and other income		(447	)		(1,496	)		(990	)		(765	)		(1,144	)
Interest expense		1,909			4,712			4,984			4,820			1,916
Income tax expense		19,991			11,923			5,067			7,769			4,880
Depletion and depreciation		27,659			24,686			22,409			16,007			7,507
Impairment expense		6,043			3,440			2,795			8,339			—
Exploration expense (2)		902			849			1,406			2,592			153
Hedge ineffectiveness		569			(891	)		137			(123	)		287
(Gain)/ loss on derivative contracts		—			(2	)		162			563			—
Non-cash compensation expense		2,115			1,071			1,424			661			553
Adjusted EBITDAX	$	89,214		$	66,670		$	45,814		$	49,023		$	17,172

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(1) Adjusted EBITDAX is a Non-GAAP measure that differs from the GAAP measure of Net Income. Adjusted EBITDAX is calculated as shown above. Adjusted EBITDAX should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not in accordance with, nor superior to, generally accepted accounting principles, but provides additional information for evaluation of our operating performance.

(2) Exploration expense for the year ended December 31, 2011 excludes $87,000; which is the non-controlling interest’s portion of exploration expense.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the consolidated financial statements and related notes thereto reflected in the index to the consolidated financial statements in this report.

General

We are an independent oil and gas company engaged in the acquisition, development and production of oil and gas reserves. As further discussed in this report, future growth in assets, earnings, cash flows and share values will be 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.

Our strategy includes a combination of acquisition, development drilling and exploration activities. Our capital structure and diverse asset portfolio allows us to shift our emphasis among these basic activities to take advantage of changing market conditions and to facilitate profitable growth. The majority of our efforts are currently focused on developing our oil-weighted acreage positions in the Bakken Shale trend of North Dakota and Montana, the Eagle Ford trend of Texas and to a lesser extent the Austin Chalk trend of Texas. In addition, it is essential that, over time, our personnel expand our current projects and/or generate additional projects so we have the potential of economically replacing our production and increasing our proved reserves. Following is a brief outline of our current plans:

• Accelerating the cost-effective development and exploitation of our existing acreage positions with a focus on our properties in the Bakken, Eagle Ford and Austin Chalk trends;

• Expanding our acreage positions and drilling inventory in and around our focus areas through acquisitions and farm-in opportunities with an emphasis on operated positions and selective non-operated participations with other capable operators;

• Generating additional exploration and development projects in and around our focus areas;

• Selectively divesting of legacy assets to high-grade our property portfolio and to lower corporate wide “per-unit” operating and administrative costs, and focus our attention on our current focus areas and new projects with greater development and exploitation potential;

• Pursuing value-accretive corporate merger and acquisition opportunities; and

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

While the impact and success of our corporate plans cannot be predicted with accuracy, our goal is to replace production and further increase our reserve base at an acquisition or finding cost that will yield attractive rates of return.

As part of our fundamental business strategy, we intend to pursue selective asset acquisitions and corporate acquisitions and mergers. We believe that asset acquisitions and/or corporate acquisitions or mergers could potentially accelerate growth, increase market visibility and allow us to realize operating and administrative benefits. Accordingly, we intend to consider any such opportunities which may become available that we consider beneficial to our shareholders. The primary financial considerations in the evaluation of any such potential transactions include, but are not limited to: (1) the potential to increase assets and drilling inventory in our focus areas, (2) the opportunity to increase our earnings and cash flow on a per share basis, (3) opportunities for development and/or exploration upside, and (4) potential realization of operating and/or administrative savings. Further, we believe a corporate acquisition could lead to increased visibility in the market place, greater trading volume and therefore greater shareholder liquidity and possibly access to capital with lower costs.

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Recent Property Acquisitions and Divestitures

During 2011 and into early 2012 we expanded our reserves and acreage positions through continued leasing efforts, farm-in opportunities and acquisitions.

Most recently, on February 29, 2012, we closed an acquisition of producing wells and acreage in the Austin Chalk trend of east Texas in the Brookeland field area. We acquired varying working interests, with an average of approximately 72%, in producing and productive wells across approximately 170,000 net acres. Estimated total proved reserves associated with the acquisition were 2.5 Mmboe compromised of 24% oil, 28% NGLs and 48% gas (January 1, 2012 management estimates at SEC prices). The properties averaged 914 BOE/day of net production in December 2011 being 24% oil, 28% NGLs and 48% residue gas. Our net acquisition cost was $40.4 million, plus closing adjustments for normal operating activity and other customary purchase price adjustments. We funded this acquisition though borrowings on our credit facility.

On January 20, 2012, we closed an acquisition of unproved leasehold interests in McKenzie County, North Dakota. We acquired approximately 3,700 net acres. Our net acquisition cost was $12.7 million and was funded with working capital and borrowings on our credit facility.

In December 2011, we sold approximately 1,800 net acres in Atascosa County, Texas for $4.6 million. For accounting purposes we used the cost recovery method; under this method proceeds have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties.

In August 2011, we acquired producing oil and gas properties in the Austin Chalk trend of east Texas. We acquired varying working interests in 11 producing and productive wells across 3,700 net acres in Tyler and Polk counties in Texas. Estimated total proved reserves associated with the acquisition were 0.6 Mmboe comprised of 25% oil, 17% NGLs and 58% gas (June 30, 2011, management estimates using forward NYMEX strip prices). Our net acquisition cost was approximately $11 million plus closing adjustments for normal operating activity and other customary purchase price adjustments. We funded the acquisition with working capital.

In November 2010, we purchased an 86.67% membership interest in Trigon Energy Partners LLC (“Trigon”) which held leases in the Eagle Ford shale trend of Texas and recorded a $2.2 million non-controlling interest in our financial statements. The acquisition cost was approximately $11.8 million. In June 2011, our membership interest decreased to 73.34% as a result of a $2.2 million capital contribution by the non-controlling interest holder. In September 2011, we deconsolidated the non-controlling interest in the financial statements due to a distribution of all of Trigon’s assets to Trigon’s other owners.

In July 2010, we closed an acquisition of producing oil and gas properties in the Giddings field of central Texas. The purchase price was $16.6 million plus closing adjustments for normal operating activity. The acquisition included approximately 9,700 net acres and was funded through borrowings under our credit facility.

In September 2010, we entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford trend of Texas. As part of this agreement, we sold a 50% working interest in approximately 20,000 acres for $20 million. For accounting purposes, we use the cost recovery method; under this method proceeds from purchasers are recorded in the balance sheet as a reduction of the carrying value of unproved properties. The purchaser also agreed to pay 100% of the drilling costs for the first six wells to be drilled in a contractually specified area of mutual interests (“AMI”). The agreement also provides for an additional $20 million for additional joint leasing within the AMI ($10 million net to joint owner). Subsequent to the initial closing, we have, along with our joint owner, continued to acquire leases within the AMI pursuant to the terms of the agreement.

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Results of Operations

Year ended December 31, 2011, compared to the year ended December 31, 2010.

We realized net income of $31.3 million and $23.3 million for the years ended December 31, 2011, and 2010, respectively. The $8.0 million increase in net income resulted primarily from the following factors.

Net amounts contributing to increase (decrease) in net income (in 000s):
Oil and gas sales	30,695
Lease operating expenses	(3,862	)
Production taxes	(1,439	)
Exploration expense	(140	)
Re-engineering and workovers	(666	)
Impairment of oil and gas properties	(2,603	)
General & administrative expense (“G&A”)	(4,401	)
Depletion, depreciation and amortization expenses (“DD&A”)	(2,973	)
Hedge ineffectiveness	(1,460	)
Gain / (loss) on derivative contracts	(2	)
Gain / (loss) on sale of property	(88	)
Interest expense	2,803
Other income	124
Income before income taxes	15,988
Provision for income taxes	(8,068	)
Net income	7,920

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Oil and gas revenues increased by $30.7 million, or 31%. Increased commodity prices accounted for $22.3 million of the increase and increased production volumes accounted for the remaining $8.4 million. Production volume growth was driven by increased oil production attributable primarily to new wells drilled in the Bakken trend in 2011, as well as recent acquisitions, partially offset by normal production declines associated with previously existing gas-weighted wells. Price and production comparisons are set forth in the following table.

	Percent increase (decrease)			Year Ended December 31,
				2011		2010
Oil Production (MBbl)		15	%		1,222		1,060
Gas Production (MMcf)		-12	%		4,209		4,789
Barrel of Oil Equivalent (MBOE)		4	%		1,924		1,858
Average Price Oil Before Hedge Settlements (per Bbl)		31	%	$	94.21	$	72.05
Average Realized Price Oil (per Bbl)		26	%	$	88.42	$	70.33
Average Price Gas Before Hedge Settlements (per Mcf)		2	%	$	4.15	$	4.07
Average Realized Price Gas (per Mcf)		1	%	$	5.36	$	5.30

Lease Operating Expenses – Lease operating expenses (“LOE”) increased from approximately $20.9 million for 2010 to $24.8 million for 2011, an increase of $3.9 million or 18%. Included in lease operating expenses are ad valorem taxes of $1.2 million and $1.3 million for 2011 and 2010, respectively. While the value of our property has increased significantly from year to year we did not have a corresponding increase in ad valorem tax because of a greater weight distribution of properties in jurisdictions with lower rates or no ad valorem taxes. Our lease operating expenditures, excluding ad valorem taxes, increased primarily due to increased production volumes as well as higher costs on a per unit basis; on a unit-of-production basis, LOE costs (excluding ad valorem taxes) increased by $1.65 per BOE to $12.25 per BOE in 2011. The increase in LOE per BOE is primarily due to increased service costs experienced across most of our project areas in 2011 vs. 2010.

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Re-engineering and workover—Re-engineering and workover costs increased from $2.0 million to $2.6 million primarily due to major re-engineering and workover programs in 2011 on our Austin Chalk properties as well as certain properties in South Louisiana.

Production Taxes—Production taxes increased by $1.4 million or 22%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for 2011 and 2010 were 6.1% and 6.9%, respectively, of oil and gas sales before the effects of hedging. Our severance tax rate decreased from year to year as a result of obtaining exemptions on a number of our Northern Region non-operated properties.

Exploration and Impairment Costs—Our exploration costs were $989,000 for 2011 and $849,000 for 2010. In 2011 and 2010, we incurred $986,000 and 657,000, respectively for geological and geophysical data. We also incurred residual dry hole and other costs during 2011 and 2010 of $3,000 and $192,000, respectively. We recorded non-cash impairment charges of $6.0 million and $3.4 million in 2011 and 2010, respectively, due to the write-down of proved properties. The book value of these properties exceeded our estimate of future undiscounted cash flows as a direct result of the decline in our estimate of future natural gas prices. In both periods, low gas prices adversely affected the value of certain dry gas properties primarily in Oklahoma.

General and Administrative Expenses—During 2011, we were successful in expanding our staffing, particularly in geological and engineering areas with the intent of effectively executing on our drilling programs, expanding our acreage and continuing our growth. Consistent with these goals we have modified our compensation practices to insure we will continue to retain and attract capable employees. Accordingly, G&A costs increased from $9.5 million in 2010 to $13.9 million in 2011, an increase of $4.4 million, or 46%. Cash G&A costs increased by $3.3 million or 40% as a result of increases in salaries and the overall head count as well as other general overhead expenses. Non-cash charges related to stock-based compensation, which are included in general and administrative expenses increased by $1.1 million or 97% as result of additional incentive stock awards granted during 2011.

Depreciation, Depletion and Amortization—DD&A expense increased by $3.0 million or 12% due to higher capitalized costs and increased production in 2011. Capitalized costs increased due to acquisitions of additional property interests and continued successful drilling in the Eagle Ford and the Bakken trends. On a unit-of- production basis, DD&A per BOE increased from $13.29 in 2010 to $14.37 in 2011.

Hedge Ineffectiveness—During 2011 the loss from hedge ineffectiveness was $569,000, compared to a gain of $891,000 for 2010. The ineffectiveness in both 2011 and 2010 primarily related to our gas derivatives accounted for as a cash flow hedges. In 2010 these hedges increased in value and therefore the change in the ineffective portion of these derivatives was a gain. In 2011 the most significant of these gas hedges decreased in value, due to the continued settlement of the hedge, and therefore the change in the ineffective portion of this derivative was a loss.

Interest Expense—Interest expense, inclusive of commitment fees and amortization of deferred financing costs, decreased by $2.8 million or 59% due to lower average debt levels during 2011, compared to 2010. Our average outstanding debt was $4.8 million and $73.6 million during 2011 and 2010, respectively. Substantially all of the interest expense recognized in 2011 represents the amortization of deferred financing costs and the payment of loan fees. The 2010 interest rates reflect the effects of interest swap contract settlements, amortization of deferred financing costs and loan fees. The effective annual interest rate, excluding amortization of deferred financing costs and loan fees, was 2.7% and 4.8% for 2011 and 2010, respectively.

Other Income—Other income increased by $124,000 or 2% in 2011 compared to 2010 primarily due to property operating income increasing by $1.7 million as a result of an increase in the number of operated wells and fees earned on operated wells drilled. This increase was offset by a decrease in severance tax refunds. In 2010, we recognized $1.2 million related to both high cost gas wells in Texas and certain qualifying oil wells in Louisiana, compared to $302,000 in 2011. Our share of partnership income in 2011 also decreased by $481,000 due to lower prices for natural gas.

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Income Tax Expense—Income tax expense for 2011 was $20.0 million compared to $11.9 in 2010. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rates for 2011 and 2010 were 39.0% and 33.8%, respectively. The lower rate for 2010 is attributable to statutory deductions for excess depletion and domestic production activities, both of which represent permanent differences between financial statement income and taxable income.

Year ended December 31, 2010, compared to the year ended December 31, 2009.

We realized net income of $23.3 million and $9.8 million for the years ended December 31, 2010, and 2009, respectively. The $13.6 million increase in net income resulted primarily from the following factors.

Net amounts contributing to increase (decrease) in net income (in 000s):
Oil and gas sales	$	28,295
Lease operating expenses		(2,181	)
Production taxes		(2,396	)
Exploration expense		557
Re-engineering and workovers		845
Impairment of oil and gas properties		(645	)
General & administrative expense (G&A)		(974	)
Depletion, depreciation and amortization expenses (DD&A)		(2,277	)
Net interest income (expense)		(176	)
Hedge ineffectiveness		1,028
Gain / (loss) on derivative contracts		164
Gain / (loss) on sale of property		(402	)
Other income—net		(1,426	)
Income before income taxes		20,412
Provision for income taxes		(6,856	)
Net income	$	13,556

The following discussion applies to the above changes.

Oil and Natural Gas Sales. Oil and gas revenues increased by $28.3 million, or 40%. Increased commodity prices accounted for $16.1 million of the increase and increased production volumes accounted for the remaining $12.2 million. Production volume growth was driven by increased oil production attributable primarily to new wells drilled in the Bakken trend in 2010 as well as recent acquisitions, partially offset by normal production declines associated with previously existing gas-weighted wells. Price and production comparisons are set forth in the following table.

	Percent increase (decrease)			Year Ended December 31,
				2010		2009
Oil Production (MBbl)		25	%		1,060		851
Gas Production (MMcf)		-3	%		4,789		4,944
Barrel of Oil Equivalent (MBOE)		11	%		1,858		1,675
Average Price Oil Before Hedge Settlements (per Bbl)		28	%	$	72.05	$	56.37
Average Realized Price Oil (per Bbl)		15	%	$	70.33	$	61.09
Average Price Gas Before Hedge Settlements (per Mcf)		24	%	$	4.07	$	3.28
Average Realized Price Gas (per Mcf)		34	%	$	5.30	$	3.97

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Lease Operating Expenses—Lease operating expenses increased from approximately $18.8 million for 2009 to $20.9 million for 2010, an increase of $2.2 million or 12%. Included in these expenses are ad valorem taxes of $1.3 and $1.1 million for 2010 and 2009, respectively. Our lease operating expenditures, excluding ad valorem taxes have increased primarily due to increased production volumes; on a unit-of-production basis, LOE costs slightly increased by $.06 per BOE from $10.54 to $10.60 per BOE.

Re-engineering and workover—Re-engineering and workover costs decreased from $2.8 million to $2.0 million primarily due to a major re-engineering and workover program concluded in 2009.

Production Taxes—Production taxes increased by $2.4 million or 57%, due to increased production volumes and revenues. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenues before the effects of hedging. Our production taxes for 2010 and 2009 were 6.9% and 6.5%, respectively, of oil and gas sales before the effects of hedging.

Exploration and Impairment Costs—Our exploration costs were $849,000 for 2010 and $1.4 million for 2009. We incurred residual costs of $192,000 during 2010 on an exploratory well deemed to be a dry hole prior to December 31, 2009. The remaining $657,000 of these costs were geological and geophysical costs. In 2009, we incurred $1.3 million for geological and geophysical data and incurred dry hole and other costs of $83,000. We recorded non-cash impairments charges of $3.4 million and $2.8 million in 2010 and 2009, respectively, due to the write-down of proved properties. The book value of these properties exceeded our estimate of future undiscounted cash flows as a direct result of the decline in our estimate of future natural gas prices.

General and Administrative Expenses—Our G&A costs increased from $8.5 million in 2009 to $9.5 million in 2010, an increase of $1.0 million, or 11% as a result of increases in salaries and other overhead expenses offset by a decrease in non-cash charges related to our stock-based compensation.

Depreciation, Depletion and Amortization—DD&A expense increased by $2.3 million or 10% due to higher capitalized costs and higher production. Capitalized costs increased due to acquisitions of additional property interests in both the Giddings field and Bakken shale trend and continued successful drilling in the Bakken. On a units-of- production basis, DD&A per BOE decreased slightly from $13.38 in 2009 to $13.29 in 2010.

Interest Income and Expense—Interest expense decreased by $272,000 due to capitalized interest. We capitalized interest of $234,000 in 2010 and none in 2009. Our average outstanding debt was $73.6 million and $74.2 million during 2010 and 2009, respectively. . The effective annual interest rate, excluding amortization of deferred financing costs and loan fees, was 4.8% and 5.4% for 2010 and 2009, respectively. The interest rates reflect the effects of interest swap contract settlements. Interest income decreased by $448,000 during 2010 compared to 2009 due to $415,000 of interest earned on severance tax refunds in 2009 and none in 2010.

Hedge Ineffectiveness—During 2010 the gain from hedge ineffectiveness was $891,000, compared to a loss of $137,000 for 2009. The ineffectiveness in 2010 relates to our gas derivatives accounted for as a cash flow hedges, which increased in value. The change in the ineffective portion of these derivatives was a gain. During 2009, our derivatives accounted for as cash flow hedges decreased in value; therefore, the change in the ineffective portion of these derivatives was a loss.

Loss on Derivative Contracts—In December, 2008, we split up a $50 million notional value interest rate swap that was previously accounted for as a cash flow hedge. The swap was split up into a $10 million swap and $40 million notional amount swap. We continued hedge accounting for the $40 million swap and accounted for the $10 million swap as a trading security. These swap contracts expired in October 2010. We recognized gains of $2,000 in 2010 and losses of $162,000 in 2009.

Other Income—Other income decreased by $1.4 million in 2010 compared to 2009 due to a decreases in partnership income and partnership management fees, offset by an increase in severance tax refunds. During 2010, we recorded partnership income of $2.2 million and during 2009 we recorded $4.3 million. The 2009 partnership income included $1.3 million of gains on sales of properties to the general partner and $1.3 million of refunds on severance taxes for which the state of Texas granted exemptions. These decreases in partnership income were

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partially offset by our increased share of revenues and expenses from the partnership. As a result of the property sales, our interest in revenues and expenses from most of the properties in SBE Partners, LP increased from 2% to 30% during the second quarter of 2009. While we expect partnership income to continue to be significant due to our increased interest in SBE Partners we do not expect the partnership to record significant gains similar to those in 2009 on property sales in the future. Since the partnership, subsequent to the sale, holds a smaller interest in its properties, our partnership management fee decreased by $457,000. During 2009 we recorded severance tax refunds of $571,000 on qualifying high cost gas wells in Texas. During 2010 we recorded severance tax refunds of $1.2 million related to both high cost gas wells in Texas and certain qualifying oil wells in Louisiana.

Income Tax Expense—Income tax expense for 2010 was $11.9 million compared to $5.1 million for 2009. Our income tax expense increased due to higher pre-tax earnings. Our effective tax rate for 2010 and 2009 were 33.8% and 34.1%, respectively. The lower rate for 2010 is attributable to statutory deductions for excess depletion and domestic production activities, both of which represent permanent differences between financial statement income and taxable income.

Hedging Activities

We seek to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing terms by entering into hedging transactions which may include fixed price swaps, price collars, puts and other derivatives. We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations. The following is a summary of our current oil and gas hedge contracts as of March 9, 2012.

	Total Annual Volume		Floor Price		Ceiling / Swap Price
Crude Oil Contracts (Bbls):
Swap contracts:
2012		120,000			$	86.85
2012		120,000			$	87.22
2012		60,000			$	99.55
2012		120,000			$	103.95
2012		60,000			$	105.00
2012		60,000			$	107.30
2012		100,000			$	108.45
2013		60,000			$	97.60
2013		60,000			$	100.70
2013		120,000			$	101.85
2013		120,000			$	105.55
Costless collars contracts:
2012		120,000	$	85.00	$	110.00
Natural Gas Contracts (Mmbtu)
Swap contracts:
2012		220,000			$	2.925
2012		150,000			$	6.450
2012		450,000			$	6.415
2012		900,000			$	4.850
2013		240,000			$	3.560
2013		225,000			$	4.850

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The fair market value of our gas hedge contracts in place at December 31, 2011 and 2010, were assets of $3.7 million and $5.1 million, respectively, of which $3.4 million and $4.3 million were classified as current assets, respectively. The fair market value of our oil hedge contracts in place at December 31, 2011 and 2010 were net liabilities of $1.7 million and $9.1 million, respectively. At December 31, 2011 the net fair market value liability was made up of a current asset of $583,000 and a long-term asset of $647,000 offset by a current liability of $2.9 million. Approximately $7.4 million of the December 31, 2010 liability was classified as current liability and $1.7 million was classified as a long-term liability. For the year ended December 31, 2011, we recognized, in oil and gas revenues, realized cash settlement losses on commodity derivative of $2.0 million. For the year ended December 31, 2010 and 2009, we recognized, in oil and gas revenues, realized cash settlement gains on commodity derivatives of $4.1 million and $7.4 million, respectively. During 2011 and 2009, we recognized non-cash losses due to hedge ineffectiveness of $569,000 and $137,000, respectively. We recognized a non-cash gain of $891,000 due to hedge ineffectiveness on hedge contracts during 2010.

Based on the estimated fair market value of our derivatives, designated as hedges at December 31, 2011, we expect to reclassify net gains on commodity derivatives of $1.1 million into earnings from accumulated other comprehensive income (loss) during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

At December 31, 2011, a 10% increase in per unit commodity prices would cause the net fair value asset of our commodity derivative financial instruments to change to a net liability of approximately $1 million to $3 million due to an estimated decrease of $3 million to $5 million. A 10% decrease in per unit commodity prices would cause the net fair value asset to increase by $6 million to $8 million. There would also be a similar increase or decrease in other comprehensive income (loss) included in total equity in the balance sheet. Since we have designated all of our commodity derivative instruments as cash flow hedges and therefore the change in market value of the effective portion of the hedge is included in other comprehensive income, a 10% change in fair value would not have a significant effect on our net income.

Additionally, should commodity prices increase in the future periods by 10%, our realized settlement losses on commodity derivatives, which are included in oil and gas revenues, would increase by approximately $3 million in 2012. If commodity prices decrease in the future by 10%, our realized settlement losses on commodity hedges would decrease by $5 million in 2012.

Hedging commodity prices for a portion of our production is a fundamental part of our corporate financial management. We do not engage in speculative commodity trading activities and do not hedge all available or anticipated quantities of our production. In implementing our hedging strategy we seek to:

• Effectively manage cash flow to minimize price volatility and generate internal funds available for operations, capital development projects and additional acquisitions; and

• Ensure our ability to support our exploration activities as well as administrative and debt service obligation.

Estimating the fair value of derivative instruments requires complex calculations, including the use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices which, although posted for trading purposes, are merely the market consensus of forecasted price trends. The results of the fair value calculation cannot be expected to represent exactly the fair value of our commodity hedges. We currently obtain fair value positions from our counterparties and compare that value to our internally calculated value. We believe that our practice of comparing our value to that of our counterparties, who are more specialized and knowledgeable in preparing these complex calculations, reduces our risk of error and approximates the fair value of the contracts, as the fair value obtained from our counterparties would be the cost to us to terminate a contract at that point in time.

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Commitments and Contingencies

We have the following contractual obligations and commitments as of December 31, 2011:

	Long-term Debt (1)		Commodity Derivatives  (2)		Payments Due by Year (in thousands) Operating Leases		Asset Retirement Obligations (3)		Drilling Rig Contracts (4)
2012	$	—	$	2,890	$	409	$	107	$	17,517
2013		—		—		417		50		10,071
2014		—		—		426		14		10,071
2015		—		—		267		—		2,937
2016		—		—		21		—		—
Thereafter		—		—		—		38,174		—
	$	—	$	2,890	$	1,540	$	38,345	$	40,596

(1) There was no long-term debt outstanding under our Credit Agreement at December 31, 2011. This table does not include future commitment fees, interest expense or other fees because the Credit Agreement is a floating rate instrument, and we cannot determine with accuracy the timing of future loans, advances, repayments or future interest rates to be charged.

(2) Represents the estimated future payments under our oil and natural gas derivative contracts based on the future market prices as of December 31, 2011. These amounts will change as oil and natural gas commodity prices change. The estimated fair market value of all of our oil and natural gas commodity derivatives at December 31, 2011, was a net asset of $2.0 million.

(3) Represents the estimates of future asset retirement obligations on an undiscounted basis. The discounted present value of the asset retirement obligations at December 31, 2011 is $7.9 million.

(4) We currently have one drilling rig under a long-term contract. This rig will be used in the Bakken trend in our Williams County, North Dakota and/or eastern Montana project areas. As of December 31, 2011, early termination of the contract would require termination penalties of $19.4 million in lieu of paying the remaining drilling commitments of $30.2 million. We also have two additional drillings rigs, a completion/workover rig and a piece of equipment used in the fracturing process in the same project areas under short-term contracts that renew semi-annually or annually. Since these are short-term contracts they do not have early termination penalties.

Capital, Operating and Administrative Costs

On an ongoing basis, we focus on cost-containment efforts related to capital, operating and administrative costs. The demand for equipment, services and personnel in our industry is significant, particularly in our focus areas. In spite of the pressures on cost resulting from such demand we have generally been able to achieve cost reductions in our drilling and completion operations in our focus areas, largely due to efficiency and logistical improvements resulting from pad drilling, efficiencies associated with running multiple rigs, and other initiatives. We believe that as our production increases in our focus areas we will reduce per unit operating expenses through various means, including but not limited to, increasing Company employed (rather than third-party employed) operating personnel and installation of salt-water disposal facilities, among other means. We must continue to attract and retain competent management, technical, operating and administrative personnel to successfully pursue our business strategy. Our industry has experienced a shortage of such personnel over the past few years, and we expect this shortage to continue as long as oil prices and demand for services in our key operating areas remain at high levels.

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Liquidity and Capital Resources

We expect to finance future acquisition, development and exploration activities through available working capital, cash flows from operating activities, our credit facility, sale of non-strategic assets, various means of corporate and project finance and possibly through issuance of additional debt and or/equity securities. In addition, we may continue to partially finance our drilling activities through the sale of participations to industry or institutional partners on a promoted basis, whereby we may earn working interests in reserves and production greater than our proportionate capital costs. Financing activities during 2011 resulted in an $87 million decrease in our debt with no outstanding indebtedness as of December 31, 2011. In January 2011, we completed a public offering of common stock and used a portion of the $122.5 million net proceeds to repay our outstanding balance of $87 million on our credit facility. Financing activities during 2010 resulted in a net increase in our debt of $18 million from the outstanding debt of $69 million at December 31, 2009. We borrowed $38 million to fund the acquisitions of producing properties and acreage in our Bakken and Eagle Ford areas and made principal debt payments of $20 million. Financing activities during 2009 resulted in a net increase in debt of $29 million from the outstanding debt of $40 million at December 31, 2008. During the second quarter of 2009, we borrowed an additional $64 million to fund the SBE Partners and Bakken acquisitions discussed above. During the fourth quarter of 2009, we completed a public offering of common stock and repaid $35 million in debt using the $33 million net proceeds from the stock issuance plus $2 million in cash flows from operations.

	December 31,
	2011			2010			2009
				(Millions)
Balances outstanding, beginning of year	$	87.0		$	69.0		$	40.0
Borrowings		—			38.0			64.0
Repayments of debt		(87.0	)		(20.0	)		(35.0	)
Balances outstanding, end of year	$	—		$	87.0		$	69.0
Issuance of common stock	$	122.5		$	—		$	33.1

In February 2012, we borrowed $60 million under our credit facility. These proceeds were principally used to fund the two property acquisitions that closed at the end of January and February 2012.

Senior Secured Revolving Credit Facility

At December 31, 2011, we had a $180 million borrowing base, with available borrowing capacity of $180 million in accordance with our Credit Agreement. The borrowing base is reviewed and redetermined in May and November of each year.

Shelf Registration Statement

We have on file with the SEC a shelf registration statement to allow us to offer up to $500 million in common stock, preferred stock, debt securities, warrants and depository shares or any combination of such securities in amounts, prices and on terms to be announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of such offering.

Cash Flows From Operating Activities

For 2011, net cash provided by operating activities was $96.3 million, an increase of $36.8 million from 2010. We believe that we have sufficient liquidity and capital resources to execute our business plans over the next twelve months and for the foreseeable future. We expect to fund our planned capital program through our existing credit facility, working capital and projected cash flows. In 2010 as compared to 2009, net cash provided by operating activities increased by $35.5 million. These year-over-year increases were directly attributable to increases in commodity prices and production.

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Cash Flows From Investing Activities

Cash applied to oil and gas capital expenditures was $111.2 million in 2011, $82.0 million in 2010, and $89.4 million in 2009. In 2011, 2010 and 2009, we realized cash of $442,000, $1.0 million, and $2.0 million, respectively, from the sale of non-core properties. During 2011, we completed one acquisition of producing oil and gas properties for a cost of $11.0 million. During 2010, we completed one acquisition of producing oil and gas properties for a cost of $16.6 million, which was financed with borrowings under our credit facility. During 2009, we completed two acquisitions of producing oil and gas properties for a combined cost of $56.7 million.

Capital Expenditures Budget

We continue to expand our portfolio of drilling and development projects and therefore have increased our projected drilling and development expenditures. As summarized below, our current expectation is for the 2012 capital budget (including January/February 2012 acquisitions closed) to be between approximately $247 million and $325 million. Actual 2012 capital expenditures incurred will depend on many of the risk factors identified in “Item 1A Risk Factors” of this report and on how quickly we expand to three or four drilling rigs in both the Eagle Ford and the Bakken trends. The table below illustrates the components of the 2012 budget, as presently contemplated. A benefit of our property portfolio is that it consists of relatively new acreage positions and therefore we generally have two to four years to drill the bulk of our undeveloped leases. In addition, many of our drilling opportunities, including the bulk of our gas drilling locations, are “held by production” or long term leases and therefore not subject to lease expiration or significant future incremental carrying costs. Accordingly, we have a substantial ability to adjust our capital spending as industry circumstances dictate or as opportunities arise.

We have initiated drilling on our operated Bakken acreage in the Williston Basin and our operated Eagle Ford acreage in Texas. Further, our Bakken non-operated holdings continue to be actively developed by our operating partners. However, we continue to evaluate adjusting our expenditures between geographic areas and projects in an attempt to maximize production, reserve growth and cash flow and take advantage of regional differences in net commodity prices and service costs, while effectively transforming our acreage to held-by-production status.

While industry circumstances may require us to make capital expenditure adjustments, our capital budget reflects our current intent to develop our Bakken and Eagle Ford positions and further expand our acreage. To a lesser extent, we intend to drill certain locations in the Austin Chalk and certain of our prospects on conventional properties, but those projects could be deferred in favor of increased activity in these other areas or so long as low natural gas prices prevail. Recent success within our Eagle Ford acreage block in Fayette County, Texas may allow us to establish a secondary Austin Chalk development program in our Eagle Ford area where the Austin Chalk is more oily.

The projects, estimated costs and timing of actual expenditures seen below are subject to significant change as we continue to technically and economically evaluate existing and alternative projects, as we further expand our property portfolio, and as industry conditions dictate. There can be no assurance that all of the projects identified and summarized in the table below will remain economically viable and therefore certain projects may be sold or deferred by us to redeploy capital elsewhere. However, in the opinion of management, at present, we have sufficient cash flows and liquidity to fulfill lease obligations or otherwise maintain all of our material mineral leases. Our current estimate of capital expenditures for 2012 is as follows:

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2012 Capital Expenditure Guidance					($ in millions)
	Low		High		Notes
Bakken (Williams County Project Area)	$	45	$	58	20-24 gross wells at $7.5-$8.0MM (30% WI)
Bakken (Eastern Montana Project Area)		10		18	3-5 gross wells at $7.5-$8.0MM (45% WI)
Bakken (Mountrail Project Area)		19		28	46-60 gross wells at $5.5-$8.5 MM (65% WI)
Bakken (McKenzie Line Project Area)		6		8	6-8 gross wells at $9.5-$10.5MM (10% WI)
Eagle Ford		73		98	20-24 gross wells at $8.0-$9.00MM (46% WI)
Austin Chalk		3		7	2-4 gross wells at $2.8-$3.3MM (50% WI)
Other Drilling		10		14	Other
Total Drilling Capital Expenditures	$	166	$	231
Acreage and Seismic		25		35	Bakken and Eagle Ford Primarily
Infrastructure and Other		3		6	Saltwater disposal, etc.
Total Capital Expenditure Excl. Acquisitions	$	194	$	272
1Q 2012 Acquisitions (Bakken and Chalk)		53		53	McKenzie Line & Brookeland Acquisitions
Total Capital Expenditures	$	247	$	325

NOTE: The data in the “High” column above is based on well cost assumptions using figures we previously experienced early on in our drilling activities in these areas. Our goal is to reduce well costs below the amounts indicated above. See the “Low” column. Management believes that Bakken well costs of $7.5 million and Eagle Ford wells costs of $8.0 million are attainable under current market conditions.

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Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies is detailed in Note A to our consolidated financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

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, geological, geophysical as well as cost of carrying and retaining unproved properties are charged to operations as incurred. Depreciation, depletion and amortization (“DD&A”) of the capitalized costs associated with proved oil and gas properties is computed using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by our independent petroleum engineers. Oil and gas properties are periodically assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. Long-lived assets committed by management for disposal are accounted for at the lower of cost or fair value, less transaction costs. All of our properties are located within the continental United States and the Gulf of Mexico.

Oil and Natural Gas Reserve Quantities

Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion, impairment of our oil and natural gas properties, and asset retirement obligations. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of our reserve estimates is a function of:

• The quality and quantity of available data;

• The interpretation of that data;

• The accuracy of various mandated economic assumptions; and

• The judgments of the persons preparing the estimates.

Our proved reserves information included in this report is based on estimates prepared by our independent petroleum engineers, Cawley, Gillespie & Associates, Inc. The independent petroleum engineers evaluated 100% of our estimated proved reserve quantities and their related future net cash flows as of January 1, 2012. Estimates prepared by others may be higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. We make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates, impairment calculations, and asset retirement obligations in the same period that changes to reserve estimates are made.

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Depreciation, Depletion and Amortization (“DD&A”)

Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Impairment of Oil and Gas Properties

We review the value of our oil and gas properties whenever management determines that events and circumstances relating to the significant deterioration in the future cash flow expected to be generated by an asset group indicate that the recorded carrying value of the properties may not be recoverable. This process is performed no less frequently than at the end of each annual reporting period. Impairments of producing properties are determined by comparing the pretax future net undiscounted cash flows to the net capitalized costs at the end of each period. If the net capitalized costs exceeds undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined based on comparable market data or expected future cash flows using discounted rates commensurate with the risks involved, using prices and costs consistent with those used for internal decision making relative to acquisitions and divestitures. During 2011, we recorded impairments and wrote down the carrying values of certain oil and gas properties in the amount of $6 million on proved properties during the fourth quarter. These impairments are described in “Note A – Organization and Summary of Significant Accounting Policies” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report. Different pricing assumptions or discount rates could result in a different calculation of impairment. The significant assumptions used in the current period’s calculation are described in “Note G – Fair Value Disclosures” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report. We provide for impairments on significant undeveloped properties when we determine that the property will not be developed or a permanent impairment in value has occurred.

Asset Retirement Obligation

Our asset retirement obligations (“AROs”) consist primarily of estimated future costs before considering estimated salvage value associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas field.

Derivative Instruments and Hedging Activity

We periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We use hedging to help ensure that we have adequate cash flows to fund our capital expenditure programs and manage price risks and returns on some of our acquisitions and drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based, in part, on our view of current and future market conditions. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. We primarily utilize swaps and costless collars, which are placed with major financial institutions. The oil and natural gas reference prices of these commodity derivative contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive. All derivative instruments are recorded on the consolidated balance sheet

Page 55

at fair value. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the fair value gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective and is reclassified to oil and gas revenues in our consolidated statements of income in the period that the hedged production is delivered. Hedge effectiveness is measured quarterly based on the relative changes in the fair value between the derivative contract and the hedged item over time.

Our 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. Our swaps are valued based on a discounted future cash flow model. Our primary input for the model is the NYMEX futures index. Our model is validated by the counterparty’s marked-to-market statements. The discount rate used in determining the fair values of these instruments includes a measure of nonperformance risk. The values we report in our consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

Our results of operations each period can be impacted by our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at the inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control. If our derivative contracts would not qualify for cash flow hedge treatment, then our consolidated statements of income could include large non-cash fluctuations, particularly in volatile pricing environments, as our contracts are marked to their period end market values.

The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We evaluate the ability of our counterparties to perform at the inception of a hedging relationship and on a periodic basis as appropriate.

Income Taxes and Uncertain Tax Positions

We record deferred tax assets and liabilities to account for the expected future tax consequences of events that are recognized in our financial statements and our tax returns in different periods. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

We will consider a tax position settled if the taxing authority has completed its examination, we do not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. We use the benefit recognition model which contains a two-step approach, a more likely than not recognition criteria and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, then we will not record the tax benefit. The amount of interest expense that we recognize related to uncertain tax positions is computed by applying the applicable statutory rate of interest to the difference between the tax position recognized and the amount previously taken or expected to be taken in a tax return.

We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be.

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Revenue Recognition

We predominantly derive our revenue from the sale of produced oil and gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, these differences have been insignificant.

Accounting for Business Combinations

Our business has grown through acquisitions, and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations to date using the purchase method.

Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the net assets received. The assets, liabilities and non-controlling interests acquired are measured at their fair value including the recognition of acquisition-related costs and anticipated restructuring costs that are separate from the acquired net assets. The purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net amounts assigned to the fair value of assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is recognized immediately to earnings as a gain from bargain purchase. Certain contingent assets acquired and liabilities assumed in a business combination are recognized at fair value on the acquisition date if we can reasonably estimate a fair value during the measurement period.

Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities, and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Off Balance Sheet Arrangements

We have no off balance sheet arrangements, special purpose entities, financing partnerships or guarantees.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodities. 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 December 31, 2011:

Transaction       Date

Transaction Type

Beginning

Ending

Price Per Unit

Remaining Annual Volumes

Fair Value Outstanding as of December 31, 2011

(in thousands)

Natural Gas

December-09

Swap

04/01/11

03/31/12

$

6.450

150,000 Mmbtu

490

December-09

Swap

04/01/12

12/31/12

$

6.415

450,000 Mmbtu

1,449

January-11

Swap

01/01/12

03/31/13

4.85

1,125,000 Mmbtu

1,735

3,674

Crude Oil

August-10

Swap

01/01/12

12/31/12

$

86.85

120,000 Bbls

(1,445

)

October-10

Swap

01/01/12

12/31/12

$

87.22

120,000 Bbls

(1,401

)

January-11

Collar

01/01/12

12/31/12

$

85.00 - $110.00

120,000 Bbls

(30

)

March-11

Swap

01/01/12

12/31/12

$

103.95

120,000 Bbls

584

March-11

Swap

01/01/13

12/31/13

$

101.85

120,000 Bbls

647

November-11

Swap

01/01/12

12/31/12

$

105.00

60,000 Bbls

(14

)

(1,659

)

$

2,015

Interest rates. We are exposed to financial risk from changes in future interest rates to the extent that we incur future indebtedness. As of December 31, 2011, we did not have any outstanding indebtedness under our Credit Agreement, which matures in November 2016. The credit facility provides for a variable interest rate. In the event interest rates rise significantly, and we incur future indebtedness without mitigating or fixing future interest rates, our interest expense will increase in accordance with any future borrowings and at rates in effect at the time of those borrowings.

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Item 8. Financial Statements and Supplementary Data

See “Index to Consolidated Financial Statements and Supplementary Information” in Page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

None.

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Item 9A. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

In accordance with Rule 13a-15(b) of the Exchange Act, our Chief Executive Officer, Chief Financial Officer and other members of management evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of December 31, 2011. Based upon their evaluation of these disclosure controls and procedures, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of December 31, 2011, in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive and principal financial officers to allow timely discussion regarding required disclosure.

(b) Management’s Report on Internal Control over Financial Reporting

The management of GeoResources, Inc. and its subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements of external purposes in accordance with generally accepted accounting principles.

Because of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011 using criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management believes that, as of December 31, 2011, our internal control over financial reporting was effective based on those criteria.

The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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(c) Attestation Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders of GeoResources, Inc.:

We have audited GeoResources, Inc.’s (a Colorado corporation) and subsidiaries internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GeoResources, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on GeoResources, Inc. and subsidiaries’ internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

In our opinion, GeoResources, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of GeoResources, Inc. and subsidiaries as of December 31, 2011 and 2010 and the related consolidated statements of income, equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2011, and our report dated March 13, 2012, expressed an unqualified opinion on those consolidated financial statements.

/s/ Grant Thornton LLP

Houston, Texas

March 13, 2012

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(d) Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is included in our definitive proxy material under the heading “Election of Directors” and “Board of Directors” to be filed with the SEC within 120 days after December 31, 2011.

Item 11. Executive Compensation

The information required by this item is included in our definitive proxy material under the heading “Executive Compensation and Other Transactions” to be filed with the SEC within 120 days after December 31, 2011.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item is included in our definitive proxy material under the heading “Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters” and “Equity Compensation Plan Information” to be filed with the SEC within 120 days after December 31, 2011.

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Item 13. Certain Relationships, Related Transactions and Director Independence

The information required by this item is included in our definitive proxy material under the heading “Certain Relationships and Related Transactions and Director Independence” to be filed with the SEC within 120 days after December 31, 2011.

Item 14. Principal Accountant Fees and Services

The information required by this item is included in our definitive proxy material under the heading “Independent Registered Public Accountants” to be filed with the SEC within 120 days after December 31, 2011.

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Item 15. Exhibits and Financial Statement Schedules

Exhibit Index for the Form 10-K for the year ended December 31, 2011
			Incorporated by Reference			Filed
Exhibit No.	Description	Form	SEC File No.	Exhibit	Filing Date	Here with	Furnished Herewith
3.1	Amended and Restated Articles of Incorporation as amended April 17, 2007 and November 6, 2007.	10-QSB	000-08041	3.1	5/13/2008
3.2	Bylaws, as amended March 2, 2004.	10-KSB	000-08041	3.2	3/30/2004
10.1	Agreement and Plan of Merger dated September 14, 2006 and as amended February 16, 2007, among GeoResources, Inc., Southern Bay Energy Acquisition, LLC, Chandler Acquisition, LLC, Southern Bay Oil & Gas, L.P., Chandler Energy, LLC and PICA Energy, LLC.	Def. Proxy Statement	000-08041	Annex A	2/23/2007
10.2	January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street Building, Suite 860, 475 17th Street, Denver, Colorado 80202.	10-QSB	000-08041	10.26	8/14/2007
10.3	First Amendment to January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated September 28, 2001.	10-QSB	000-08041	10.27	8/14/2007
10.4	Second Amendment to January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated October 23, 2002.	10-QSB	000-08041	10.28	8/14/2007
10.5	Third Amendment to January 31, 2000 Office Building Lease by and between 475-17th Street, CO. and Collis P. Chandler III for 475 17th Street, Suite 860, Denver, Colorado 80202, dated June 28, 2004.	10-QSB	000-08041	10.29	8/14/2007
10.6	Form of Purchase Agreement.	8-K	000-08041	10.33	6/11/2008
10.7	Form of Warrant.	8-K	000-08041	10.34	6/11/2008
10.8	Form of Registration Rights Agreement.	8-K	000-08041	10.35	6/11/2008
10.9	Agreement of Limited Partnership for OKLA Energy Partners LP dated May 20, 2008.	10-Q	000-08041	10.37	8/11/2008
10.10	Lease Agreement by and between Southern Bay Energy, L.L.C. and Cypress Court Operating Associates, L.P. for office space at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated September 25, 2008.	10-Q	000-08041	10.38	11/12/2008
10.11	Purchase and Sale Agreement between SBE Partners LP and Catena Oil and Gas LLC, dated May 29, 2009.	10-Q	000-08041	10.39	8/6/2009

Page 65

10.12	Consent and Amendment No. 1 to Agreement of Limited Partnership of SBE Partners LP as of May 29, 2009.	10-Q	000-08041	10.40	8/6/2009
10.13	Second Amended and Restated Credit Agreement between the Registrant and Wachovia Bank, National Association as Administrative Agent dated July 13, 2009.	10-Q	000-08041	10.41	11/5/2009
10.14	Consent, Distribution Agreement, and Amendment No. 2 to Agreement of Limited Partnership of SBE Partners LP, dated August 31, 2009.	10-Q	000-08041	10.42	11/5/2009
10.15	First Amendment to Lease by and between Southern Bay Energy, L.L.C. and Cypress Court Operating Associates, Limited Partnership for office space at 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, dated January 29, 2010.	10-K	000-08041	10.43	3/12/2010
10.16	Exploration and Development Agreement-New Home II Project, between G3 Energy, LLC and Resolute Northern Rockies, LLC, effective February 2, 2010.	10-Q	000-08041	10.44	8/6/2010
10.17	Amendment to Exploration and Development Agreement-New Home II Project, between G3 Energy, LLC and Resolute Northern Rockies, LLC, effective February 2, 2010.	10-Q	000-08041	10.45	8/6/2010
10.18	Purchase and Sale Agreement dated June 25, 2010, by and among Hop-Mar Energy, L.P., Sydri Energy Investments I, Ltd., Snyder Energy Investments, Ltd., Woodbine Energy Partners, L.P. and Southern Bay Energy, LLC.	10-Q	000-08041	10.46	11/5/2010
10.19	Participation Agreement-Eagle Ford Project entered into September 29, 2010 between Southern Bay Energy, LLC, Southern Bay Operating, LLC and Ramshorn Investments, Inc.	10-Q	000-08041	10.47	11/5/2010
10.20	Amended and Restated Limited Liability Company Agreement of Trigon Energy Partners LLC dated October 30, 2010.	10-K	000-08041	10.48	3/11/2011
10.21	Lease Acquisition and Development Agreement By and Between Trigon Energy Partners LLC and CEU Eagle Ford, LLC, dated May 4, 2010.	10-K	000-08041	10.49	3/11/2011
10.22	Exploration and Development Agreement with Area of Mutual Interest between Slawson Exploration Company, Inc. and G3 Operating, LLC (as successor-in-interest to Chandler Energy, LLC) dated January 1, 2007. [Confidential treatment has been granted with respect to a portion of this Agreement.]	10-K	000-08041	10.50	3/11/2011
10.23*	Amended and Restated 2004 Employees’ Stock Incentive Plan.	S-8	333-175697	4.3	7/21/2011
10.24*	Form of Restricted Stock Unit Agreement.	S-8	333-175697	4.4	7/21/2011
10.25*	Form of Stock Option Agreement.	S-8	333-175697	4.5	7/21/2011

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10.26	Third Amended and Restated Credit Agreement between the Registrant and Wells Fargo Bank, National Association as Administrative Agent dated November 9, 2011.	8-K	000-08041	10.51	11/15/2011
14.1	Code of Business Conduct and Ethics adopted March 2, 2004.	10-KSB	000-08041	14.1	3/30/2004
21.1	Subsidiaries of the Registrant.					X
23.1	Consent of Grant Thornton LLP (for GeoResources, Inc.).					X
23.2	Consent of Grant Thornton LLP (for SBE Partners LP).					X
23.3	Consent of Cawley, Gillespie & Associates, Inc.					X
24.1	Power of Attorney. (included on the signature page hereof)					X
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
32.1	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X
32.2	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.						X
99.1	Financial Statements and Report of Independent Certified Public Accountants for SBE Partners LP for the years ended December 31, 2011, 2010 and 2009.					X
99.2	Report of Cawley, Gillespie & Associates, Inc. dated February 27, 2012.					X
101.INS	INS XBRL Instance Document.						X
101.SCH	SCH XBRL Schema Document.						X
101.CAL	CAL XBRL Calculation Linkbase Document.						X
101.DEF	DEF XBRL Definition Linkbase Document.						X
101.LAB	LAB XBRL Label Linkbase Document.						X
101.PRE	PRE XBRL Presentation Linkbase Document.						X

* Management compensatory plan.

Page 67

GEORESOURCES, INC. and SUBSIDIARIES

Index to Consolidated Financial Statements and Supplementary Information

CONSOLIDATED FINANCIAL STATEMENTS
Audited Financial Statements:
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2011 and 2010	F-3
Consolidated Statements of Income for the Years Ended December 31, 2011, 2010 and 2009	F-5
Consolidated Statements of Equity and Comprehensive Income (Loss) for the Years December  31, 2011, 2010, and 2009	F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010, and 2009	F-7
Notes to Consolidated Financial Statements	F-8
Unaudited Information:
Supplemental Information to Consolidated Financial Statements	F-33

Page F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of GeoResources, Inc.:

We have audited the accompanying consolidated balance sheets of GeoResources, Inc. (a Colorado corporation) and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes, examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoResources, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), GeoResources, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2011 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 13, 2012 expressed an unqualified opinion that GeoResources, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting.

/s/ Grant Thornton LLP

Houston, Texas

March 13, 2012

Page F-2

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

	December 31,
	2011			2010
ASSETS
Current assets:
Cash	$	39,144		$	9,370
Accounts receivable
Oil and gas revenues		26,485			17,627
Joint interest billings and other, less allowance for doubtful accounts of $609 and $370, respectively		21,328			16,021
Affiliated partnerships		371			969
Notes receivable		545			120
Derivative financial instruments		4,037			4,282
Income taxes receivable		7,753			222
Prepaid expenses and other		3,681			2,645
Total current assets		103,344			51,256
Oil and gas properties, successful efforts method:
Proved properties		428,871			341,582
Unproved properties		44,613			32,403
Office and other equipment		1,675			1,140
Land		146			146
		475,305			375,271
Less accumulated depreciation, depletion and amortization		(96,753	)		(72,380	)
Net property and equipment		378,552			302,891
Equity in oil and gas limited partnerships		2,240			2,272
Derivative financial instruments		868			851
Deferred financing costs and other		2,687			2,420
	$	487,691		$	359,690

The accompanying notes are an integral part of these statements.

Page F-3

GEORESOURCES, INC and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

	December 31,
	2011		2010
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	25,483	$	14,616
Accounts payable to affiliated partnerships		3,597		2,931
Revenue and royalties payable		17,043		12,450
Drilling advances		12,965		4,203
Accrued expenses		5,073		1,331
Derivative financial instruments		2,890		7,433
Total current liabilities		67,051		42,964
Long-term debt		—		87,000
Deferred income taxes		44,389		19,289
Asset retirement obligations		7,940		7,052
Derivative financial instruments		—		1,650
Stockholders’ equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 25,595,930 shares in 2011 and 19,726,566 in 2010		256		197
Additional paid-in capital		281,515		148,172
Accumulated other comprehensive income (loss)		1,069		(3,000	)
Retained earnings		85,471		54,133
Total GeoResources, Inc. stockholders’ equity		368,311		199,502
Noncontrolling interest		—		2,233
Total equity		368,311		201,735
	$	487,691	$	359,690

The accompanying notes are an integral part of these statements.

Page F-4

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except share and per share amounts)

	Year Ended December 31,
	2011			2010			2009
Revenue:
Oil and gas revenues	$	130,608		$	99,913		$	71,618
Partnership management fees		507			550			1,007
Property operating income		3,562			1,865			1,710
Gain on sale of property and equipment		865			953			1,355
Partnership income		1,759			2,240			4,318
Interest and other		447			1,496			990
Total revenue		137,748			107,017			80,998
Expenses:
Lease operating expense		24,806			20,944			18,763
Production taxes		8,028			6,589			4,193
Re-engineering and workovers		2,628			1,962			2,807
Exploration expense		989			849			1,406
Impairment of oil and gas properties		6,043			3,440			2,795
General and administrative expense		13,875			9,474			8,500
Depreciation, depletion and amortization		27,659			24,686			22,409
Hedge ineffectiveness		569			(891	)		137
(Gain) / loss on derivative contracts		—			(2	)		162
Interest		1,909			4,712			4,984
Total expense		86,506			71,763			66,156
Income before income taxes		51,242			35,254			14,842
Income tax expense (benefit):
Current		(2,644	)		8,861			412
Deferred		22,635			3,062			4,655
		19,991			11,923			5,067
Net income		31,251		$	23,331		$	9,775
Less: Net loss attributable to noncontrolling interest		(87	)		—			—
Net income attributable to GeoResources, Inc.	$	31,338		$	23,331		$	9,775
Net income per share (basic)	$	1.24		$	1.18		$	0.59
Net income per share (diluted)	$	1.22		$	1.16		$	0.59
Weighted average shares outstanding:
Basic		25,171,896			19,720,652			16,532,003
Diluted		25,598,770			20,142,297			16,559,431

The accompanying notes are an integral part of these statements

Page F-5

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY and COMPREHENSIVE INCOME (LOSS)

(In thousands, except share data)

	Common Stock				Additional Paid-in		Retained		Accumulated Other Comprehensive			Non- Controlling			Total
	Shares		Par value		Capital		Earnings		Income (Loss)			Interest
Balance, January 1, 2009		16,241,717	$	162	$	112,523	$	21,027	$	7,283		$	—		$	140,995
Issuance of common stock
For cash, net of issuance costs of $2,136		3,450,000		35		33,019										33,054
For services		13,645		—		59										59
Comprehensive income:
Net income								9,775								9,775
Change in fair market value of hedged positions, net of taxes of $4,357										(7,123	)					(7,123	)
Hedging gains realized in income, net of taxes of $2,388										(3,448	)					(3,448	)
Total comprehensive loss																(796	)
Equity based compensation expense						1,365										1,365
Balance, December 31, 2009		19,705,362		197		146,966		30,802		(3,288	)		—			174,677
Exercise of employee stock options
Cash exercises		13,150		—		135										135
Cashless exercises		8,054		—		2										2
Comprehensive income:
Net income								23,331								23,331
Change in fair market value of hedged positions, net of taxes of $1,488										2,024						2,024
Hedging gains realized in income, net of taxes of $1,048										(1,736	)					(1,736	)
Total comprehensive income																23,619
Purchase of Trigon LLC													2,233			2,233
Equity based compensation expense						1,069										1,069
Balance, December 31, 2010		19,726,566		197		148,172		54,133		(3,000	)		2,233			201,735
Issuance of common stock
For cash, net of issuance costs of $6,889		5,175,000		52		122,434										122,486
Exercise of employee stock options
Cash exercises		694,364		7		6,263										6,270
Excess tax benefit from share-based compensation						2,531										2,531
Comprehensive income:
Net income								31,338					(87	)		31,251
Change in fair market value of hedged positions, net of taxes of $1,705										2,833						2,833
Hedging losses realized in income, net of taxes of $760										1,236						1,236
Total comprehensive income																35,320
Equity based compensation expense						2,115										2,115
Deconsolidation of noncontrolling interest													(2,146	)		(2,146	)
Balance, December 31, 2011		25,595,930	$	256	$	281,515	$	85,471	$	1,069		$	—		$	368,311

The accompanying notes are an integral part of these statements.

Page F-6

GEORESOURCES, INC. and SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income	$	31,251		$	23,331		$	9,775
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		27,659			24,686			22,409
Proved property impairments		6,043			3,440			2,795
Gain on sale of property and equipment		(865	)		(953	)		(1,355	)
Provision for doubtful accounts		300			—			312
Accretion of asset retirement obligations		444			405			368
Settlement of asset retirement obligations		(213	)		—			—
Unrealized (gain) loss on derivative contracts		—			(325	)		(238	)
Amortization of loss on cancelled hedges		—			—			482
Hedge ineffectiveness (gain) loss		569			(891	)		137
Partnership income		(1,759	)		(2,240	)		(4,318	)
Partnership distributions		1,791			3,500			2,406
Deferred income taxes		22,635			3,062			4,655
Non-cash compensation		2,115			1,071			1,424
Excess tax benefit from share-based compensation		(2,531	)		—			—
Changes in assets and liabilities:
Increase in accounts receivable		(19,036	)		(499	)		(7,960	)
Decrease (increase) in prepaid expense and other		(1,472	)		707			(1,116	)
Increase (decrease) in revenues and royalties payable		4,801			(1,478	)		2,227
Increase (decrease) in accounts payable and accrued expense		24,607			5,715			(7,959	)
Net cash provided by operating activities		96,339			59,531			24,044
Cash flows from investing activities:
Proceeds from sale of property and equipment		442			1,018			1,991
Additions to property and equipment, net of cost recoveries of $4,555 in 2011, $40,230 in 2010, and none in 2009		(111,294	)		(70,126	)		(89,396	)
Purchase of Trigon Energy Partners, LLC		—			(11,848	)		—
Net cash used in investing activities		(110,852	)		(80,956	)		(87,405	)
Cash flows from financing activities:
Proceeds from stock options exercised		6,270			135			—
Issuance of common stock		122,486			—			33,054
Excess tax benefit from share-based compensation		2,531			—			—
Issuance of long-term debt		—			38,000			64,000
Reduction of long-term debt		(87,000	)		(20,000	)		(35,000	)
Net cash provided by (used in) financing activities		44,287			18,135			62,054
Net increase (decrease) in cash and cash equivalents		29,774			(3,290	)		(1,307	)
Cash and cash equivalents at beginning of period		9,370			12,660			13,967
Cash and cash equivalents at end of period	$	39,144		$	9,370		$	12,660
Supplementary information:
Interest paid	$	909		$	3,958		$	4,064
Income taxes paid	$	2,502		$	8,629		$	664
Stock issue for services		—		$	2		$	59

The accompanying notes are an integral part of these statements.

Page F-7

GEORESOURCES, INC. and SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

NOTE A: Organization and Summary of Significant Accounting Policies

Organization and Basis of Presentation

GeoResources, Inc. (“GeoResources” or the “Company”) operates a single business segment involving the acquisition, development and production of, and exploration for, crude oil, natural gas and related products primarily in Texas, North Dakota, Louisiana, Oklahoma, and Montana.

Summary of Significant Accounting Policies

Basis of Consolidation

The consolidated financial statements include the accounts of the Company and its majority-owned subsidiaries. The equity method is used to account for investments in affiliates in which the Company does not have majority ownership, but has the ability to exert significant influence. Intercompany accounts and transactions have been eliminated. The Company’s investments in oil and gas limited partnerships for which it serves as general partner and has significant influence on are accounted for under the equity method. The Company consolidated our non-controlling interest in Trigon LLC (“Trigon”) until September 2011, at which time the non-controlling interest was deconsolidated due to a distribution of all of Trigon’s assets to its owners. A non-controlling interest represents the minority members’ proportionate share of membership equity. All other subsidiaries are wholly owned. Certain reclassifications were made to the year ended December 31, 2009 amounts on the Company’s Consolidated Statement of Income to conform to the current presentation of severance tax expense and interest and other income. The Company also reclassified certain amounts from joint interest and other receivable to oil and gas receivables. Such reclassifications had no impact on net income, working capital, or total equity previously reported.

The parent, GeoResources, Inc., has no assets or operations independent of its subsidiaries. The long-term debt of GeoResources, Inc. under its Credit Agreement discussed in Note C is fully and unconditionally guaranteed on a joint and several basis by all of its significant subsidiaries, all of which are wholly owned. Subject to a pledge of all the significant subsidiary assets pursuant to the Credit Agreement, there are no restrictions on the ability of GeoResources, Inc. to obtain funds from its significant subsidiaries. The significant subsidiaries of GeoResources, Inc. are: AROC (Texas) Inc., a Texas corporation; Catena Oil & Gas, LLC; a Texas limited liability company; G3 Energy, LLC, a Colorado limited liability company; G3 Operating, LLC, a Colorado limited liability company; Southern Bay Energy, LLC, a Texas limited liability company; Southern Bay Louisiana, L.L.C., a Texas limited liability company; and Southern Bay Operating, L.L.C., a Texas limited liability company.

Cash and Cash Equivalents

Cash and cash equivalents consists of all demand deposits and funds invested in highly liquid investments with an original maturity of three months or less.

The Company maintains its cash and cash equivalents in various financial institutions. The combined account balances at several institutions typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage. Management believes that this risk is not significant.

Page F-8

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for oil and gas operations whereby the costs to acquire mineral investments in oil and gas properties, to drill successful exploratory wells, to drill and equip development wells, and to install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. The Company’s acquisition and development costs of proved oil and gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers. Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of production basis.

The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Proved oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flow expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to its estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. Fair value of impaired assets may be estimated using comparable market data or based on expected future cash flows using discount rates commensurate with the risks involved and using prices and costs consistent with those used for internal decision making or a combination of the two. Long-lived assets committed by the Company for disposal are accounted for at the lower of cost or fair value, less cost to sell. The Company recognized impairments of $6.0 million, $3.4 million and $2.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. Impairments recognized in 2011, 2010 and 2009 were on proved properties and are classified as impairments on the Company’s income statement.

Office and Other Property

Acquisitions and improvements of office and other property are capitalized at cost; maintenance and repairs are expensed as incurred. Depreciation of equipment is calculated using the straight-line method over the assets estimated useful lives of 5-7 years. Leasehold improvements are amortized over the remaining term of the lease. When assets are sold, retired, or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and a gain or loss is recognized.

Net Income Per Common Share

Basic earnings per share is computed by dividing net income attributable to common shares by the basic weighted-average shares of common stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents. Dilutive common stock equivalents consist of unvested restricted stock unit awards and outstanding stock options. The number of potential common shares outstanding relating to stock options and restricted stock units is computed using the treasury stock method. Net income per share computations to reconcile basic and diluted net income for 2011, 2010 and 2009 consist of the following (in thousands, except per share data):

	Year ended December 31,
	2011		2010		2009
Numerator:
Net income available for common stock	$	31,338	$	23,331	$	9,775
Denominator:
Basic weighted average shares		25,172		19,721		16,532
Effect of dilutive securities - share-based compensation		427		421		27
Diluted weighted average shares		25,599		20,142		16,559
Earning per share
Basic	$	1.24	$	1.18	$	0.59
Diluted	$	1.22	$	1.16	$	0.59

Page F-9

Options to purchase 5,830, 52,086 and 412,540 shares were excluded from the diluted earnings per share calculation in 2011, 2010 and 2009, respectively, because the effect would have been anti-dilutive. For the year ended December 31, 2011, 37 restricted stock units were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Stock-Based Compensation

The Company recognizes in the financial statements all share-based payments made to employees, including grants of employee stock options and restricted stock units, based on their fair values at the time of award.

Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, accounts receivable and payable and revenue royalties payable are estimated to approximate their fair values due to the short maturities of these instruments. The Company’s long-term debt obligations will bear interest at floating market rates, so carrying amounts and fair values will be approximately equal. Derivative financial instruments are carried at fair value; for further information see Note F: Derivative Financial Instruments.

Income Taxes

The provision for income taxes is based on taxes payable or refundable for the current year and deferred taxes on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, which result from temporary differences between the amount of taxable income and pretax financial income. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. Tax positions are evaluated for recognition and measurement, with deferred tax balances recorded at their anticipated settlement amounts. A valuation allowance is provided for deferred tax assets not expected to be realized.

Other Comprehensive Income (Loss)

The Company reports comprehensive income on its Consolidated Statement of Equity and Comprehensive Income (Loss). Other comprehensive income (loss) at December 31, 2011, 2010 and 2009 consists of unrealized gains (losses) of derivatives qualifying as cash flow hedges in accordance with current accounting standards.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Oil and gas reserve estimates, which are the basis for units-of-production depreciation, depletion, and amortization are inherently imprecise and are expected to change as future information becomes available.

Derivative Instruments and Hedging Activities

The Company enters into derivative contracts, primarily options, collars and swaps, to hedge future crude oil and natural gas production, as well as interest rates, in order to mitigate the risk of downward movements of oil and gas market prices and the upward movement of interest rates. All derivatives are recognized on the balance sheet and measured at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the realized gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the realized gain or loss on the derivative is deferred in other comprehensive income to the extent the hedge is effective for cash flow hedges. To qualify for hedge accounting, the derivative must qualify either as a fair value, cash flow or foreign currency hedge.

Page F-10

The hedging relationship between the hedged instruments and hedged transactions must be highly effective in achieving the offset of changes in fair values and cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis to qualify for hedge accounting. The Company measures hedge effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedging instrument becomes ineffective. The Company assesses hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes in intrinsic value only. As a result, changes in the entire value of option contracts are deferred in accumulated other comprehensive income until the hedged transaction affects earnings to the extent such contracts are effective. Gains and losses that were previously deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered.

Gains and losses resulting from hedge settlements of commodity hedges are included in oil and gas revenues and are included in realized prices in the period that the related production is delivered. Gains and losses on hedging instruments that represent hedge ineffectiveness are included in the caption hedge effectiveness on the consolidated statement of income in the period in which they occur. Gains and losses on derivative instruments that do not qualify for hedge accounting are included in the caption gain/loss on derivative contracts. The resulting cash flows are reported as cash flows from operating activities.

Asset Retirement Obligations

The Company recognizes the present value of the estimated future abandonment costs of its oil and gas properties in both assets and liabilities. If a reasonable estimate of the fair value can be made, the Company will record a liability for legal obligations associated with the future retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of the assets. The fair value of a liability for an asset retirement obligation is recognized in the period in which the liability is incurred. The fair value is measured using expected future cash outflows (estimated using current prices that are escalated by an assumed inflation rate) discounted at the Company’s credit-adjusted risk-free interest rate. The liability is then accreted each period until it is settled or the asset is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded. The initial fair value of the asset retirement obligation is capitalized and subsequently depreciated or amortized as part of the carrying amount of the related asset.

The Company has recorded asset retirement obligations related to its oil and gas properties. There are no assets legally restricted for the purpose of settling asset retirement obligations.

Revenue Recognition

Oil and gas revenues represent income from production and delivery of oil and gas, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has been transferred and if collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. A liability is recorded only if the Company’s takes of gas volumes exceed its share of estimated recoverable reserves from the respective well or field. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. Volumetric production is monitored to minimize imbalances, and such imbalances were not significant at December 31, 2011, 2010 or 2009.

Accounts Receivable

The Company sells crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of crude oil and natural gas or participants in crude oil and natural gas wells for which subsidiaries of the Company serve as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Crude oil and natural gas sales are generally unsecured.

Page F-11

As is common industry practice, the Company generally does not require collateral or other security as a condition of sale, rather relying on credit approval, balance limitation and monitoring procedures to control the credit use on accounts receivable. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance.

The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2011 and 2010, the Company has an allowance for doubtful accounts of $609,000 and $370,000, respectively.

Drilling Advances

The Company, in its execution of its drilling program has other working interest partners. The Company, through its joint operating agreements, requires its working interest partners to pay a drilling advance for their share of the estimated drilling and completion costs. Until such advances are applied to actual drilling and completion invoices, the Company carries the advance as a current liability on its balance sheet. The Company expects such advances to be applied against the partners’ joint interest billings for its share of drilling operations within 60 days from when the advance is paid.

Industry Segment and Geographic Information

The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.

Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance Sheet (Topic 210) – Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting under current accounting literature or are subject to master netting arrangements irrespective of whether they are offset. The objective of the new disclosures is to facilitate comparison between entities that prepare financial statements on the basis of U.S. GAAP and entities that prepare financial statements under IFRS. The disclosure requirements will be effective for periods beginning on or after January 1, 2013 and must be applied retrospectively to all periods presented on the balance sheet. The Company will adopt the requirements of ASU No. 2011-11 on January 1, 2013, which may require additional footnote disclosures for derivative instruments and these requirements are not expected to have a material effect on the Company’s financial position, results of operations or cash flows.

In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, companies are also required to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. The Company will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This ASU issued authoritative guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. The ASU expands existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the

Page F-12

measurement, (2) a description of the valuation processes in place, and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. Entities will also be required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

Other amendments include clarifying the highest and best use and valuation premise for nonfinancial assets, premiums and discounts in fair value measurement, and fair value of an instrument classified in a reporting entity’s shareholders’ equity.

ASU 2011-04 is effective during interim and annual periods beginning after December 15, 2011, and therefore will become effective for the Company on January 1, 2012 for the quarter ending March 31, 2012. Other than the disclosure requirements, ASU 2011-04 is not expected to have a significant impact on the Company’s consolidated financial statements.

NOTE B: Acquisitions and Divestitures

Bakken Acquisition

In May 2009, the Company closed an acquisition, through an existing joint venture partner, of producing wells and acreage in the Bakken shale trend of the Williston Basin. The Company acquired a 15% interest in approximately 60,000 net acres, and also acquired 15% of varying working interests in 59 producing and productive wells. The Company’s net acquisition cost was approximately $10.4 million, subject to closing adjustments for normal operations activity and other customary purchase price adjustments. The Company funded the acquisition with borrowings under its credit facility.

Giddings Field Acquisition

On May 29, 2009, effective May 1, 2009, the Company, though its subsidiary, Catena Oil and Gas LLC (“Catena”), entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with an affiliated limited partnership, SBE Partners LP (the “Seller”) for the acquisition (the “Acquisition”) of certain oil and gas producing properties in Giddings field, Grimes and Montgomery counties, Texas (the “Interests”). Under the Purchase Agreement, the Interests were purchased for a cash purchase price of $48.7 million, net of closing adjustments for normal operations activity (the “Purchase Price”). In addition, the Company also acquired rights to certain post-closing severance tax refunds which amounted to $2.4 million. The Acquisition increased the Company’s partnership sharing ratio from 2% to 30% in the Seller. Catena is the general partner of the Seller. The Seller distributed to Catena $978,000 of the gross proceeds from the sale. The Acquisition increased the Company’s direct working interests in the Interests from a range of 6.5% to 7.8% to a range of 34% to 37%. The Company funded the Purchase Price with borrowings under its credit facility. The Purchase Agreement contains representations and warranties, covenants, and indemnifications that are customary for oil and gas producing property acquisitions.

Page F-13

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

Total revenue	$	93,536
Income before taxes		21,491
Net income		13,718
Net income per share:
Basic	$	0.83
Diluted	$	0.83
Weighted average shares:
Basic		16,532,003
Diluted		16,559,431

Other

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

On August 29, 2009, the Company, through its subsidiary, Catena, received a distribution of proved undeveloped property and unproved acreage in the Giddings field from SBE Partners LP (“SBE”), an affiliated partnership. The property was recorded at the estimated fair market value of $1.6 million, which exceeded its carrying value in the partnership. In conjunction with the distribution, SBE recorded a gain. The Company, which accounts for SBE as an equity method investment, included its share of the gain, $1.0 million, in the Company’s partnership income during the third quarter 2009.

In October 2009, the Company initiated a leasing program in Williams County, North Dakota with the objective of establishing a significant operated position in the Bakken trend. In February 2010, the Company entered into agreements with two unaffiliated third parties to jointly develop the project. Cash proceeds to the Company totaled approximately $20 million and the Company retained a 47.5% working interest in the project area. The agreement also provided for up to $10 million ($4.75 million net) of additional joint leasing in a contractually specified area of mutual interest (“AMI”). As of December 31, 2011 the net acreage position of the Company in the project area totaled approximately 27,800 acres. For accounting purposes the Company uses the cost recovery method; under this method proceeds from joint owners have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties.

In July 2010, the Company closed an acquisition of producing oil and gas properties located near the Giddings field of central Texas. The purchase price was $16.6 million plus closing adjustments for normal operating activity. The acquisition included approximately 9,700 net acres and was funded through borrowings under the Company’s credit facility. The amount of revenue from the acquisition included in the Company’s Consolidated Statement of Income for years ended December 31, 2011 and 2010 was $6.7 million and $2.7 million, respectively. The amount of net income from the acquisition included in the Company’s Consolidated Statements of Income for years ended December 31, 2011 and 2010 was $1.3 million and $700,000, respectively.

In September 2010, the Company entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford shale trend of Texas. As part of this agreement, the Company sold a 50% working interest in approximately 20,000 acres to a third party for $20 million. For accounting purposes, the Company uses the cost recovery method; under this method proceeds from joint owners are recorded in the balance sheet as a reduction of the carrying value of unproved properties. The purchaser also agreed to pay 100% of the drilling costs for the first six wells to be drilled in a contractually specified AMI. The agreement also provides for an additional $20 million for additional joint leasing within the AMI ($10 million net to each joint owner). Subsequent to the initial closing, the Company and the joint owner have continued to acquire leases within the AMI pursuant to the terms of the agreement.

Page F-14

In November 2010, the Company purchased an 86.67% membership interest in Trigon which held leases in the Eagle Ford shale trend of Texas and recorded a $2.2 million non-controlling interest in the Company’s financial statements. The acquisition cost was approximately $11.8 million. In June 2011, the Company’s membership interest decreased to 73.34% as a result of a $2.2 million capital contribution by the non-controlling interest holder. In September 2011, the Company deconsolidated the non-controlling interest in the financial statements due to a distribution of all of Trigon’s assets to its owners.

In August 2011, the Company closed an acquisition of producing oil and gas properties located in the Austin Chalk trend of east Texas. The purchase price was $11 million plus closing adjustments for normal operating activity. The acquisition included approximately 3,700 net acres. The amount of revenue and net income from the acquisition included in the Company’s Consolidated Statement of Income for year ended December 31, 2011, was $1.5 million and $400,000, respectively.

In December 2011, the Company sold approximately 1,800 net acres in Atacosa County, Texas for $4.6 million. For accounting purposes the Company used the cost recovery method; under this method proceeds have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties.

NOTE C: Long-term Debt

On July 13, 2009, the Company entered into a Second Amended and Restated Credit Agreement (“Second Amended Credit Agreement”). The Second Amended Credit Agreement increased the credit facility from $200 million to $250 million and extended the term of the Credit Agreement to October 16, 2012. The initial borrowing base of the facility was $135 million, which was increased to $145 million in November 2009 and was $145 million as of December 31, 2010.

On November 9, 2011, the Company entered into a Third Amended and Restated Credit Agreement (the “Credit Agreement”), which increased its senior secured revolving credit facility from $250 million to $450 million and extended the term of the Credit Agreement to November 9, 2016. The initial borrowing base of the credit facility was $180 million, subject to review and redetermination on May 1 and November 1 of each year. The Credit Agreement provides for interest rates at (a) LIBOR plus 1.75% to 2.75% or (b) the prime lending rate plus 0.75% to 1.75%, depending upon the amount borrowed and also requires the payment of commitment fees to the lender in respect of the unutilized commitments. The commitment rate is 0.375% per annum for a borrowing base of less than 50% and .500% for a borrowing base greater than or equal to 50%. The Company is also required to pay customary letter of credit fees. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. The Company incurred costs of approximately $1.5 million to complete the amendment and it is amortizing these costs over the remaining life of the Credit Agreement; the amortization is included in interest expense. The banks participating in the credit facility include: Wells Fargo Bank, Comerica Bank, Compass Bank, U.S. Bank, The Frost National Bank, BMO Harris Financing, Inc., Royal Bank of Canada, and SunTrust Bank.

The 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 lease back transactions, pay dividends and distributions or repurchase its capital stock, engage in mergers or consolidations, make significant changes to management, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the Credit Agreement requires the maintenance of certain financial ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at December 31, 2011.

The Company had no principal outstanding under its credit facility at December 31, 2011. The principal outstanding under the Credit Agreement was $87 million at December 31, 2010. The remaining borrowing capacity under the Credit Agreement was $180 million as of December 31, 2012. The maturity date for amounts outstanding under the Credit Agreement is November 9, 2016.

Page F-15

Interest expense for 2011, 2010, and 2009 includes amortization of deferred financing costs of $981,000, $1.1 million, and $785,000 respectively. During 2010, the Company capitalized interest of $234,000. The Company did not capitalize any interest in 2011 or 2009.

In October 2007, the Company entered into an interest rate swap agreement with one of the banks participating in its credit facility, providing a fixed rate of 4.79% on a notional $50 million through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million swap each with a fixed annual interest rate of 4.29%. The $40 million swap was accounted for as a cash flow hedge while the $10 million swap was accounted for as a trading security. These swaps expired in October 2010. During 2010, the Company recognized a net gain of $2,000 on the $10 million swap due to the cash settlement losses approximating the mark-to-market gain. The Company recognized a net loss of $162,000 on the $10 million swap during the year ended December 31, 2009.

For the years ended December 31, 2010 and December 31, 2009, the Company recognized realized cash settlement losses of $1.3 million and $1.6 million, respectively, related to the $40 million swap.

The weighted average interest rate on borrowings outstanding, excluding amortization of deferred financing costs and loans fees but including interest rate swaps, during 2011, 2010 and 2009 was 2.7%, 4.8%, and 5.4%.

NOTE D: Stock Options, Performance Awards and Stock Warrants

In March 2007, the shareholders of the Company approved the GeoResources, Inc, Amended and Restated 2004 Employees’ Stock Incentive Plan (the “Plan”), which authorizes the issuance of options and other stock-based incentives to officers, employees, directors and consultants of the Company to acquire up to 2,000,000 shares of the Company’s common stock at prices which may not be less than the stock’s fair market value on the date of grant. The options can be designated as either incentive options or nonqualified options. In June 2011, the shareholders of the Company approved an amendment to the Plan which increased the number of authorized issuances of stock-based incentives to 3,250,000 shares. The amendment also allows the issuance of performance units, including restricted stock units.

Stock options generally vest ratably over approximately a four-year service period from grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.

On February 3, 2009, and March 26, 2009, the Company granted options under the Plan to officers and other employees to purchase 300,000 and 225,000 shares of common stock, respectively. Also on February 3, 2009, the Company granted options to outside directors to purchase 200,000 shares of common stock. On October 20, 2009, the Company granted options to certain employees to purchase 25,000 shares of common stock. The closing market prices of the Company’s common stock on the date of the February, March and October 2009 grants were $7.62, $7.16, and $12.70, respectively.

On April 7, 2010, the Company granted options under the Plan to an outside director to purchase 40,000 shares of common stock. Additionally, on June 1, 2010, the Company granted options under the Plan to purchase 35,000 shares of common stock to key employees. The closing market prices of the Company’s common stock on the dates of the April and June 2010 grants were $17.27 and $13.69, respectively.

On June 7, 2011, the Company granted options under the Plan to an outside director to purchase 40,000 shares of common stock. The closing market price of the Company’s common stock on June 7, 2011 was $21.57. All of the foregoing options, if not exercised, will expire 10 years from the date of grant. The following is a summary of the terms of the 2011 grant by exercise price:

Page F-16

	2011 Stock Option Grants
Vesting Date	$23.00		$27.00
Director
June 6, 2012		5,000		5,000
June 6, 2013		5,000		5,000
June 6, 2014		5,000		5,000
June 6, 2015		5,000		5,000
		20,000		20,000

Page F-17

A summary of the Company’s stock option activity for the years ended December 31, 2011, 2010 and 2009

is as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (year)		Weighted Average Fair Value		Aggregate Intrinsic Value
Outstanding, January 1, 2009		790,000		$	9.39		8.81	$	2.29	$	158,750
Granted		750,000		$	9.42			$	4.45
Exercised		—		$	—				—
Forfeited		—		$	—				—
Outstanding, December 31, 2009		1,540,000		$	9.40		8.30	$	3.34	$	6,827,275
Granted		75,000		$	17.66			$	8.52
Exercised		(33,150	)	$	9.19				4.29	$	205,189
Forfeited		(87,500	)	$	11.50				4.64
Outstanding, December 31, 2010		1,494,350		$	9.70		7.34	$	3.49	$	18,701,164
Granted		40,000		$	25.00			$	11.50
Exercised		(702,864	)	$	9.27				2.93	$	12,206,204
Forfeited		(50,000	)	$	9.40				3.22
Outstanding, December 31, 2011		781,486		$	10.88		6.93	$	4.42	$	14,402,787
Exercisable at year-end
2011		387,736
2010		742,850
2009		382,500

The weighted average grant date fair value of the options that vested during the year 2011 was $3.49 per option. The average intrinsic value for the 387,736 options exercisable as of December 31, 2011 is $7.7 million. These options have a weighted average exercise price of $9.56 and a weighted average remaining life of 6.29 years.

Unvested options at year-end:

	Number of Awards		Weigthed Average Exercise Price		Weighted Average Fair Value
December 31, 2009		1,157,500	$	9.77	$	3.69
December 31, 2010		751,500	$	10.28	$	4.22
December 31, 2011		393,750	$	12.18	$	5.75

The Company recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. Compensation expense is recognized over the respective vesting periods on a straight-line basis. For the years ended December 31, 2011, 2010, and 2009, the Company recognized compensation expense of $969,000, $1.1 million, and $1.4 million respectively, related to these options. As of December 31, 2011, the future pre-tax expense of non-vested stock options is $1.5 million ($913,000 after taxes) to be recognized through the second quarter of 2014.

Page F-18

During 2011, 2010 and 2009 the weighted-average fair value of the options granted during the year was $11.50, $8.52, and $4.45 per share respectively, using the following assumptions:

	2011			2010			2009
Risk-free annual interest rate		1.58	%		2.03	%		1.27	%
Dividend yield		None			None			None
Volatility		67	%		75	%		86	%
Expected life of option		5 Years			4 Years			4 Years

In measuring compensation associated with these options, an annual pre-vesting forfeiture rate of 1% was used. The expected volatility at the grant date is based on the historical volatility of the Company’s common stock and the risk-free interest rate is determined based on the U.S. treasury yield curve rate with a maturity similar to that of the expected term of the stock option.

In addition to the stock option grants discussed above, during 2011, the Company granted certain officers, employees and directors 197,050 restricted stock units. Each restricted stock unit represents a contingent right to receive one share of the Company’s common stock upon vesting. Compensation expense, determined by multiplying the number of restricted stock units granted by the closing market price of the Company’s stock on the grant date, is recognized over the respective vesting periods on a straight-line basis. For the year ended December 31, 2011, compensation expense related to restricted stock units was $1.1 million. The Company has an assumed forfeiture rate of 1% on restricted stock units issued. As of December 31, 2011, the future unamortized pre-tax compensation expense associated with unvested restricted stock units totaled approximately $4.3 million ($2.7 million after taxes) to be recognized through November 2014. The weighted average vesting period related to unvested restricted stock units at December 31, 2011 was approximately 2.38 years. A summary of the Company’s restricted stock unit activity for the year ended December 31, 2011 is as follows:

	Shares		Fair Values  (1)
Outstanding, December 31, 2010		—		—
Granted		197,050	$	27.72
Vested		—		—
Forfeited		—		—
Outstanding, December 31, 2011		197,050	$	27.72

(1) Represents the weighted average grant date market value

On June 5, 2008, the Company issued 613,336 warrants to purchase common stock to non-affiliated accredited investors pursuant to exemptions from registration under federal and state securities laws. The warrants have a term of five years ending June 5, 2013, with an exercise price $32.43 per share.

Page F-19

NOTE E: Income Taxes

The following table shows the components of the Company’s income tax provision for 2011, 2010 and 2009:

	Year ended December 31,
	2011			2010		2009
	(in thousands)
Current:
Federal	$	(2,337	)	$	8,111	$	283
State		(307	)		750		129
Total current		(2,644	)		8,861		412
Deferred
Federal		21,323			2,570		4,318
State		1,312			492		337
Total deferred		22,635			3,062		4,655
Total	$	19,991		$	11,923	$	5,067

The following is a reconciliation of taxes computed at the corporate federal statutory income tax rate of 35% to the reported income tax provision for the years ended December 31, 2011, 2010 and 2009:

	2011			2010			2009
	(in thousands)
Income before income taxes	$	51,242		$	35,254		$	14,842
Tax computed at federal statutory rate		17,965		$	12,339		$	5,195
Statutory depletion in excess of tax basis		—			(1,060	)		—
Domestic production activities deduction		—			(513	)		—
State income taxes, net of federal benefit		1,752			876			521
Expense not deductible for tax purposes and other		274			281			(649	)
Total income tax expense	$	19,991		$	11,923		$	5,067
Effective tax rate		39.01	%		33.82	%		34.14	%

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

Page F-20

The following table shows the components of the Company’s net deferred tax liability at December 31, 2011, 2010 and 2009:

	2011			2010			2009
	(in thousands)
Deferred tax asset or (liability)
Current:	$	—		$	—		$	—
Noncurrent:
Oil and gas properties		(49,598	)		(24,536	)		(20,178	)
Other property and equipment		434			482			473
Equity in limited partnerships		(704	)		(465	)		(685	)
Asset retirement obligations		3,024			2,652			1,703
Stock-based compensation		865			875			518
Commodity hedges and other		1,590			1,703			2,391
Net deferred tax liability	$	(44,389	)	$	(19,289	)	$	(15,778	)

As of December 31, 2011, the Company had statutory depletion available for carryforward of approximately $3.6 million, which may be used to offset future taxable income. The amount that may be used in any year is subject to an annual limit of $1.1 million arising from a change in control in 2007.

Uncertain Tax Positions

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

At December 31, 2011, the Company did not have any uncertain tax positions that would require recognition. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.

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

The Company’s continuing practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statement of Income. As of December 31, 2011, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statutes of limitations prior to December 31, 2012.

NOTE F: Derivative Financial Instruments

The Company enters into various crude oil and natural gas hedging contracts, primarily costless collars and swaps, in an effort to manage its exposure to product price volatility. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has designated its commodity derivative contracts as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they also limit future revenues from favorable price movements. The Company does not enter into commodity derivative instruments for speculative or trading purposes.

Page F-21

At December 31, 2011, accumulated other comprehensive income (loss) included unrecognized gains of $1.1 million, net of taxes of $658,000, representing the inception to date change in mark-to-market value of the effective portion of the Company’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2010, accumulated other comprehensive income (loss) included unrecognized losses of $3.0 million, net of taxes of $1.8 million. For the year ended December 31, 2011, the Company recognized a realized net cash settlement loss on commodity derivatives of $2.0 million. For the years ended December 31, 2010 and 2009, the Company recognized realized net cash settlement gains on commodity derivatives of $4.1 million and $7.4 million, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at December 31, 2011, the Company expects to reclassify net gains of $1.1 million into earnings from accumulated other comprehensive income (loss) during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

On October 17, 2008, the Company paid $3.0 million to cancel its 2009 natural gas swaps that were previously accounted for as cash flow hedges. At the time of cancelation, accumulated other comprehensive (loss) contained $482,000 of acquisition to date change in mark-to-market of the effective portion of these commodity derivative contracts. These accumulated losses were amortized during 2009 and reduce net income by $482,000.

During the first quarter of 2011, the Company entered into one additional natural gas swap contract, three crude oil collars, and two crude oil swaps. The natural gas swap has a term of January 2012 to March 2013 with a volume amount of 75,000 MMBTUs per month. The swap has a fixed price of $4.85 per MMBTU. The first crude oil collar has a term of February 2011 through December 2011 with a volume amount of 5,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $106.08 per Bbl on this contract. The second crude oil collar has a term of January 2012 through December 2012 and provides for 10,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $110.00 per Bbl. The third crude oil collar has a term of March 2011 through December 2011 and provides for 5,000 Bbls per month. The floor price is $100.00 per Bbl and the ceiling price is $114.00 per Bbl. The first crude oil swap has a term of January 2012 through December 2012 and provides for 10,000 Bbls per month. The swap has a fixed price of $103.95 per Bbl. The second crude oil swap has a term of January 2013 through December 2013 and provides for 10,000 Bbls per month. The swap has a fixed price of $101.85 per Bbl.

During the second quarter of 2011, the Company entered into a crude oil swap. The crude oil swap has a term of May 2011 through December 2011 and provides for 6,250 Bbls per month. The swap has a fixed price of $110.00 per Bbl.

During the fourth quarter of 2011, the Company entered into a crude oil swap. The crude oil swap has a term of January 2012 through December 2012 and provides for 5,000 Bbls per month. The swap has a fixed price of $105.00 per Bbl.

Page F-22

At December 31, 2011, the Company had hedged its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:

	Total Remaining Volume		Floor Price		Ceiling / Swap Price
Crude Oil Contracts (Bbls):
Swap contracts:
2012		120,000			$	87.22
2012		120,000			$	86.85
2012		120,000			$	103.95
2012		60,000			$	105.00
2013		120,000			$	101.85
Costless collar contracts
2012		120,000	$	85.00	$	110.00
Natural Gas Contracts (Mmbtu)
Swap contracts:
2012		150,000			$	6.450
2012		450,000			$	6.415
2012		900,000			$	4.850
2013		225,000			$	4.850

The fair market value of the Company’s gas hedge contracts in place at December 31, 2011 and 2010, were assets of $3.7 million and $5.1 million, respectively, of which $3.4 million and $4.3 million were classified as current assets, respectively. The fair market value of the Company’s oil hedge contracts in place at December 31, 2011 and 2010 were net liabilities of $1.7 million and $9.1 million, respectively. At December 31, 2011 the net fair market value liability was made up of a current asset of $583,000 and a long-term asset of $647,000 offset by a current liability of $2.9 million. $7.4 million of the December 31, 2010 liability was classified as current liability and $1.7 million was classified as a long-term liability. For the year ended December 31, 2011, the Company recognized, in oil and gas revenues, realized cash settlement loss on commodity derivatives of $2.0 million. For the years ended December 31, 2010 and 2009, the Company recognized, in oil and gas revenues, realized cash settlement gains on commodity derivatives of $4.1 million and $7.4 million, respectively. During 2010, the Company recognized gains due to hedge ineffectiveness of $891,000. Due to hedge ineffectiveness on hedge contracts during 2011 and 2009 the Company recognized a loss of $569,000 and $137,000, respectively.

To reduce the impact of changes in interest rates on the Company’s variable rate term loan, the Company entered into a two-year interest rate swap contract on $50 million of the debt, designed to protect against interest rate increases. During 2008, the Company extended the term of this interest rate swap through October, 2010, and broke the swap up into two pieces, a $40 million swap and a $10 million swap. The Company accounted for the $40 million swap as a cash flow hedge while the $10 million swap was accounted for as a trading security. The interest rate swaps are further discussed in Note C above.

Page F-23

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

Derivatives designated as ASC 815 hedges:	Asset Derivatives					Liability Derivatives
	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
		Dec. 31, 2011		Dec. 31, 2010			Dec. 31, 2011			Dec. 31, 2010
Commodity contracts	Current derivative financial instruments asset	$	4,037	$	4,282	Current derivative financial instruments liability	$	(2,890	)	$	(7,433	)
Commodity contracts	Long-term derivative financial instruments asset		868		851	Long-term derivative financial instruments liability		—			(1,650	)
		$	4,905	$	5,133		$	(2,890	)	$	(9,083	)

Derivative contracts – The following tables summarize the effects of commodity and interest rate derivative instruments on the consolidated statements of income for the years ended December 31, 2011, 2010 and 2009 (in thousands):

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivatives  (Effective Portion)
	2011		2010		2009
Commodity contracts	$	4,538	$	3,512	$	(10,834	)
Interest rate swap contracts		—		—		(646	)
	$	4,538	$	3,512	$	(11,480	)

Page F-24

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Reclassified from OCI into Income  (Effective Portion)									Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
	2011			2010			2009
Commodity contracts	$	(1,996	)	$	4,078		$	7,434		Oil and gas revenues
Interest rate swap contracts		—			(1,294	)		(1,598	)	Interest expense
	$	(1,996	)	$	2,784		$	5,836

Derivatives in ASC 815 cash flow hedging relationships:	Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative  (Ineffective Portion)
		2011			2010		2009
Commodity contracts	Hedge ineffectiveness	$	(569	)	$	891	$	(137	)

Derivative not designated as ASC 815 hedges:	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
		2011		2010			2009
Realized cash settlements on interest rate swap	Gain (loss) on derivative contracts		—	$	(323	)	$	(399	)
Unrealized gain (loss) on interest rate swap	Gain (loss) on derivative contracts		—		325			237
			—	$	2		$	(162	)

Contingent features in derivative instruments – None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s derivative contracts are high credit quality financial institutions that are lenders under the Company’s credit facility. The Company uses credit facility participants to hedge with, since these institutions are secured equally with the holders of the Company’s debt, which eliminates the potential need to post collateral when the Company is in a large derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

NOTE G: Fair Value Disclosures

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

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

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

Page F-25

• 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. There were no transfers between Level 1 and Level 2 of the fair value hierarchy during the years ended December 31, 2011 or 2010. Further, there were no transfers in and/or out of Level 3 of the fair value hierarchy during the years ended December 31, 2011 and 2010.

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

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

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

The tables below present information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

Page F-26

Derivative Assets and Liabilities—December 31, 2011

(in thousands)

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2011
Current portion of derivative financial instrument asset (1)		—	$	4,037		—	$	4,037
Long-term portion of derivative financial instrument asset (1)		—		868		—		868
Current portion of derivative financial instrument liability (1)		—		2,890		—		2,890
Long-term portion of derivative financial instrument liability (1)		—		—		—		—

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

Derivative Assets and Liabilities—December 31, 2010

(in thousands)

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2010
Current portion of derivative financial instrument asset (1)		—	$	4,282			—	$	4,282
Long-term portion of derivative financial instrument asset (1)		—		851			—		851
Current portion of derivative financial instrument liability (1)		—		(7,433	)		—		(7,433	)
Long-term portion of derivative financial instrument liability (1)		—		(1,650	)		—		(1,650	)

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

At December 31, 2011 and 2010, the Company did not have any assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3.

Nonrecurring Fair Value Measurements—The Company applies the provision of the fair value measurement standard to its nonrecurring, non-financial measurements. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The following non-financial assets and liabilities measured at fair value on a nonrecurring basis.

Page F-27

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

The Company recorded asset impairments of $6.0 million, $3.4 million and $2.8 million on proved properties during the years ended December 31, 2011, 2010 and 2009, respectively. All of the 2011, 2010 and 2009 impairments on proved properties were included in impairment expense. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of future natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

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

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

NOTE H: 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, and removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. The Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations (“ARO”) for oil and gas properties and related equipment during the years ended December 31, 2011 and 2010 are as follows (in thousands):

	Year ended December 31
	2011			2010
Balance, beginning of year	$	7,052		$	6,110
Additional liabilities incurred		838			314
Settlement of liabilities		(213	)		—
Accretion Expense		444			405
Disposals of properties		(557	)		(105	)
Revisions of estimates		376			328
Balance, end of year	$	7,940		$	7,052

Page F-28

NOTE I: Concentration of Credit Risk

Credit risk represents the accounting loss which the Company would record if its customers failed to perform pursuant to the contractual terms. The Company’s largest customers are large companies. In addition, the Company transacts business with independent oil producers, crude oil trading companies and a variety of other entities. The Company’s credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables.

In 2011, three purchasers each accounted for 12% of the Company’s consolidated oil and gas revenue. In 2010, two purchasers each accounted for 12% of the Company’s consolidated oil and gas revenues and one purchaser accounted for 11%. In 2009, one purchaser accounted for 17% of the Company’s consolidated oil and gas revenues, two purchasers accounted for 15% each, and one more accounted for 11%. No other single purchaser accounted for 10% or more of the Company’s consolidated oil and gas revenues in 2011, 2010, or 2009. There are adequate alternate purchasers of production such that the loss of one or more of the above purchasers would not have a material adverse effect on the Company’s results of operations or cash flows.

Page F-29

NOTE J: Commitments and Contingencies

Commitments

The Company is obligated under non-cancelable operating leases for its office facilities as follow (in thousands):

2012	$	409
2013		417
2014		426
2015		267
2016		21
Thereafter		—
	$	1,540

Total rental expense under operating leases for 2011, 2010 and 2009 was $400,000, $369,000, and $374,000, respectively.

The Company is also obligated under non-cancelable contracts for drilling rigs and related equipment for its drilling operations as follows (in thousands):

2012	$	17,517
2013		10,071
2014		10,071
2015		2,937
2016		—
Thereafter		—
	$	40,596

The Company has committed to one long-term natural gas sales contract in its Williams County North Dakota project area in the Bakken trend. Under the terms of this contract the Company has committed substantially all of the natural gas production for the life of its leases to one purchaser. In return for the life of lease commitment, the purchaser has committed to building a gas gathering system across the Company’s project area. The sales price under this contract is based on a posted market rate.

Contingencies

No significant legal proceedings are pending which are expected to have a material adverse effect on the Company. The Company is unaware of any potential claims or lawsuits involving environmental, operating or corporate matters which are expected to have a material adverse effect on the Company’s financial position or results of operations.

NOTE K: Related Party Transactions

Accounts receivable at December 31, 2011 and 2010 include $258,000 and $753,000, respectively, due from SBE Partners LP (“SBE Partners”). Accounts receivable at December 31, 2011 and 2010, also includes $113,000 and $219,000, respectively, due from OKLA Energy Partners LP (“OKLA Energy”). 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 December 31, 2011 and 2010, includes $2.8 million and $2.3 million, respectively, due to SBE Partners for oil and gas revenues and severance tax refunds collected on its behalf. Accounts payable at December 31, 2011 and 2010, also includes $817,000 and $654,000, respectively due to OKLA Energy for oil and gas revenues collected on its behalf.

The Company earned partnership management fees during the years ended December 31, 2011, 2010, and 2009 of $507,000, $550,000 and $1.0 million, respectively.

Page F-30

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. These revenues are paid monthly to each partnership, which in turn reimburses the Company for the partnership’s share of expenditures.

In May 2009, the Company, through its subsidiary, Catena, entered into a Purchase and Sale Agreement with an affiliated limited partnership, SBE Partners. Catena purchased the properties for $49.3 million. As the General Partner of SBE Partners, Catena received a distribution from the partnership as a result of the sale of $987,000. The net purchase price for the properties was $48.4 million. This acquisition is discussed in Note B above.

NOTE L: Equity Investments

The Company accounts for its investment in SBE Partners L.P. and OKLA Energy using the equity method of accounting. Under this accounting method the Company records its share of income and expenses. Contributions to the investment increase the Company’s investment while distributions from the partnership decrease the Company’s carrying value of the investment.

OKLA Energy, formed during 2008, holds direct working interests in producing oil and gas properties located throughout Oklahoma. The Company’s 2% general partner interest reverts to 35.66% when the limited partner realizes a contractually specified rate of return. The Company recorded a loss in partnership income related to this investment for the years ended December 31, 2011, 2010 and 2009 of $22,600, $39,000 and $34,000, respectively.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings field in Texas. Previously, the Company held a 2% general partner interest which increased after reaching a cumulative payout. As result of the sale of certain properties and subsequent distribution of proceeds by the Partnership cumulative payout was achieved and the Company’s general partner interest increased to 30%. For further information about the sale see Note B above. For the years ended December 31, 2011, 2010 and 2009 the Company recorded partnership income of $1.8 million, $2.3 million, and $4.4 million, respectively.

The Company’s carrying value for its equity investment in OKLA Energy at December 31, 2011 and 2010 was $646,000 and $709,000, respectively. The Company’s carrying value for its equity investment in SBE Partners at December 31, 2011 and 2010 was $1.6 million and $1.6 million, respectively. During 2011, the Company received cash distributions of $1.8 million and $41,000 from SBE Partners and OKLA Energy, respectively.

Page F-31

The following is a summary of selected financial information of SBE Partners, LP as of and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	2011		2010		2009
Summary of Partnership selected balance sheet information:
Current assets	$	7,677	$	5,831	$	11,933
Oil and gas properties, net	$	55,604	$	59,745	$	60,834
Total assets	$	66,876	$	68,993	$	73,686
Current liabilities	$	591	$	1,032	$	1,047
Total liabilities	$	1,519	$	2,161	$	1,876
Partner’s capital	$	65,357	$	66,832	$	71,810
Summary of Partnership operations:
Revenues	$	17,957	$	19,181	$	52,429
Income from continuing operations	$	7,025	$	6,419	$	29,726
Net income	$	7,025	$	6,419	$	29,726
The Company’s equity in partnership net income	$	1,782	$	2,279	$	4,352
The Company’s capital balance in the partnership	$	1,597	$	1,565	$	2,686

Page F-32

NOTE M: Supplemental Financial Quarterly Results (Unaudited):

The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree with year-to-date basic and diluted earnings (loss) per share amounts as a result of each period’s computation being based on the weighted average number of common shares outstanding during that period.

	Three Months Ended
	March 31, 2011			June 30, 2011			September 30, 2011			December 31, 2011
	(in thousands, except per share data)
Year ended December 31, 2011
Oil and gas revenues	$	26,614		$	29,292		$	35,229		$	39,473
Other revenues (1)		2,025			1,588			1,873			1,654
Operating expenses (2)		(12,846	)		(14,826	)		(17,882	)		(18,556	)
Operating income		15,793			16,054			19,220			22,571
Other income (expense), net (3)		(5,388	)		(1,853	)		(3,523	)		(11,632	)
Income tax (expense) benefit		(4,092	)		(5,422	)		(6,282	)		(4,195	)
Net income	$	6,313		$	8,779		$	9,415		$	6,744
Basic net income per share	$	0.26		$	0.35		$	0.37		$	0.26
Diluted net income per share	$	0.26		$	0.34		$	0.36		$	0.26

	Three Months Ended
	March 31, 2010			June 30, 2010			September 30, 2010			December 31, 2010
	(in thousands, except per share data)
Year ended December 31, 2010
Oil and gas revenues	$	24,729		$	24,343		$	25,612		$	25,229
Other revenues (1)		1,549			1,021			1,294			1,744
Operating expenses (2)		(13,875	)		(13,089	)		(13,914	)		(14,152	)
Operating income		12,403			12,275			12,992			12,821
Other income (expense), net (4)		(2,552	)		(4,947	)		(2,735	)		(5,003	)
Income tax (expense) benefit		(3,777	)		(2,885	)		(2,621	)		(2,640	)
Net income (loss)	$	6,074		$	4,443		$	7,636		$	5,178
Basic net income per share	$	0.31		$	0.23		$	0.39		$	0.25
Diluted net income per share	$	0.30		$	0.22		$	0.38		$	0.26

(1) Partnership management fees, property operating income, gain (loss) on sale of property and partnership income.

(2) Lease operating expense, production taxes, re-engineering and workover, exploration, and depreciation depletion and amortization.

(3) Other income (expense), net for the fourth quarter of 2011 included impairment expenses of $6.0 million

(4) Other income (expense), net for the second and fourth quarters of 2010 included impairment expenses of $2.7 million and $697,000, respectively.

Page F-33

NOTE N: Supplemental Financial Information for Oil and Gas Producing Activities (Unaudited)

1. Costs Incurred Related to Oil and Gas Activities

The Company’s oil and gas activities for 2011, 2010 and 2009 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Acquisition cost:
Proved	$	10,120	$	18,739	$	59,686
Unproved	$	20,795	$	22,880	$	6,908
Exploration cost:
Exploratory drilling	$	12,053	$	5,225		83
Geological and geophysical	$	898	$	630		1,323
Development cost	$	67,977	$	35,349	$	23,623

Unproved acquisition costs for 2011 and 2010 is net of cost recoveries of $4.6 million and $40.2 million received from the sale of interests in undeveloped properties from third parties. During 2011, 2010 and 2009, additions to oil and gas properties of $838,000, $314,000 and $262,000 were recorded for estimated costs of future abandonment related to new wells drilled or acquired.

Net capitalized costs related to the Company’s oil and gas producing activities were as follows:

	December 31,
	2011			2010
	(in thousands)
Proved properties	$	428,871		$	341,582
Unproved properties		44,613			32,403
		473,484			373,985
Accumulated depreciation, depletion and amortization		(96,045	)		(71,805	)
Net capitalized cost	$	377,439		$	302,180

The amounts included in unproved properties are projects for which the Company intends to commence exploration or evaluation projects in the near future. The Company will begin to amortize these costs when proved reserves are established or an impairment is determined.

Page F-34

The net changes in capitalized exploratory wells costs were as follows:

	Year ended December 31
	2011			2010
Balance, beginning of year	$	5,006		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		12,053			5,006
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(17,056	)		—
Capitalized exploratory well costs charged to expense		(3	)		—
Balance, end of year	$	—		$	5,006

As of December 31, 2011 the Company did not have any costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling and no capitalized exploratory well costs pending the determination of proved reserves.

2. Estimated Quantities of Proved Oil and Gas Reserves

For all years presented, the estimate of proved reserves and related valuations were based on reports prepared by the Company’s independent petroleum engineers. The reports were prepared by Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to the definitions prescribed by the U.S. Securities and Exchange Commission. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions existing as of the end of each respective year. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.

Page F-35

Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are located in the United States, for the years ended December 31, 2011, 2010 and 2009:

Oil and Gas Reserve Quantities:

	Oil (MBbl)			Gas (MMcf)
Proved reserve quantities, December 31, 2008		8,793			34,796
Purchase of minerals-in-place		586			25,728
Sales of minerals-in-place		(59	)		(80	)
Extensions and discoveries		972			9,227
Production		(851	)		(4,944	)
Revisions of quantity estimates		1,978			(9,291	)
Proved reserve quantities, December 31, 2009		11,419			55,436
Purchase of minerals-in-place		531			1,388
Extensions and discoveries		1,553			1,390
Production		(1,060	)		(4,789	)
Revisions of quantity estimates		1,950			4,129
Proved reserve quantities, December 31, 2010		14,393			57,554
Purchase of minerals-in-place		134			2,195
Extensions and discoveries		5,265			4,687
Production		(1,222	)		(4,209	)
Revisions of quantity estimates		1,123			(2,922	)
Proved reserve quantities, December 31, 2011		19,693			57,305
Proved developed reserve quantities:
December 31, 2009		9,221			38,138
December 31, 2010		11,231			39,097
December 31, 2011		13,906			38,514
Proved undeveloped reserve quantities:
December 31, 2009		2,198			17,298
December 31, 2010		3,162			18,457
December 31, 2011		5,787			18,791

Notable changes in proved reserves for the year ended December 31, 2011, 2010 and 2009 included:

In 2009, the revision increase in estimated oil quantities related to price increases was 2,204,000 Bbls, which was partially offset by reductions of 1,030,000 Bbls due to a change in pricing method as prescribed by the SEC. Other increases of 804,000 Bbls accounted for the remainder of the total positive revision of 1,978,000 Bbls. The revision decrease in estimated gas quantities related to price increases was 960,000 Mcf, offset by a decrease of 10,572,000 Mcf attributable to the change in pricing methods prescribed by the SEC. Other increases in gas reserves of 321,000 Mcf accounted for the remainder of the negative revision of 9,291,000 Mcf. The change in pricing method prescribed by the SEC is from the use of a year-end price to the use of a 12-month average price.

In 2010, the revision increase in estimated oil quantities related to price increases was approximately 1,024,000 Bbls as SEC prescribed oil prices increased from the December 31, 2009 price of $61.18 per Bbl to the December 31, 2010 price of $79.43 per Bbl. Net positive performance revisions of approximately 926,000 Bbls accounted for the remainder of the total positive revision of 1,950,000 Bbls. The revision increase in estimated gas quantities related to the price increases was approximately 6,032,000 Mcf as SEC prescribed gas prices increased from December 31, 2009 of $3.83 per Mmbtu to the December 31, 2010 price of $4.37 per Mmbtu. Net negative performance revisions of approximately 1,903,000 Mcf accounted for the remainder of the total positive revisions of 4,129,000 Mcf. In 2010, the majority of the 1,553,000 Bbls and 1,390,000 Mcf of proved reserves added through extensions and discoveries are a direct result of our successful Bakken drilling activities in North Dakota and eastern Montana.

Page F-36

In 2011, the revision increase in estimated oil quantities related to price increases was approximately 523,000 Bbls as SEC prescribed oil prices increased from the December 31, 2010 price of $79.43 per Bbl to the December 31, 2011 price of $96.16 per Bbl. Net positive performance revisions of approximately 600,000 Bbls accounted for the remainder of the total positive revision of 1,123,000 Bbls. The revision decrease in estimated gas quantities related to price decreases was 46,000 Mcf as SEC prescribed gas prices decreased from December 31, 2010 of $4.37 per Mmbtu to the December 31, 2011 price of $4.11 per Mmbtu. Net negative performance revisions of 2,876,000 Mcf accounted for the remainder of the total negative revisions of 2,922,000 Mcf. In 2011, the majority of the 5,265,000 Bbls and 4,687,000 Mcf of proved reserves added through extensions and discoveries are a direct result of our successful drilling activities in the Bakken trend of North Dakota and Eagle Ford trend of Texas.

3. Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with FASB ASC topic Extractive Activities – Oil and Gas. Future cash inflows as of December 31, 2011, 2010, and 2009 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2011, 2010 and 2009, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions.

Future income tax expense is calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of the properties involved. Future income tax expense gives effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.

Presented below is the standardized measure of discounted future net cash flows as of December 31, 2011, 2010 and 2009.

Standardized Measure of Estimated Future Net Cash Flows

	December 31,
	2011		2010		2009
	(in thousands)
Future cash inflows	$	2,036,390	$	1,266,679	$	789,647
Future production costs		657,929		455,685		316,815
Future development costs		197,247		90,814		64,560
Future income taxes		353,452		188,887		83,182
Future net cash flows		827,762		531,293		325,090
10% annual discount for estimated timing of cash flows		400,936		254,278		150,990
Standardized measure of discounted future cash flows	$	426,826	$	277,015	$	174,100

Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end. If the effects of hedging transaction were included in the computation, undiscounted future cash flows would have increased by $2.0 million in 2011, decreased by $4.0 million in 2010, and decreased by $4.3 million in 2009.

Page F-37

The principal sources of changes in the standardized measure of discounted future net cash flows for 2011, 2010 and 2009 are as follows:

Changes in Standardized Measure

	Year Ended December 31,
	2011			2010			2009 *
	(in thousands, except product prices)
Standardized measure, beginning of period	$	277,015		$	174,100		$	120,619
Changes in prices, net of production cost		116,768			111,342			47,246
Extensions, discoveries and enhanced production		134,530			36,111			20,989
Revision of quantity estimates		29,494			42,413			14,876
Development costs incurred, previously estimated		4,620			5,613			7,045
Change in estimated future development costs		(7,231	)		(7,972	)		(17,629	)
Purchases of minerals-in-place		12,747			16,161			36,002
Sales of minerals-in-place		—			—			(786	)
Sale of oil and gas produced, net of production costs		(97,142	)		(66,341	)		(53,860	)
Accretion of discount		41,730			23,268			16,663
Change in estimated future income taxes		(86,789	)		(57,792	)		(13,495	)
Changes in timing of estimated cash flows and other		1,084			112			(3,570	)
	$	426,826		$	277,015		$	174,100
Prices, used in standardized measure:
Oil (per barrel)	$	96.19		$	79.43		$	61.18
Gas (per Mcf)	$	4.11		$	4.37		$	3.83

* In 2009, standardized measure was reduced by $90.0 million due to the use of a 12-month average price as prescribed by the new reserve rules versus an end of the year price. Had the Company not changed its pricing method to comply with the SEC’s new rules the standardized measure at December 31, 2009 would have been $264.1 million.

Page F-38

Equity in Partnership Reserves

1. Costs Incurred Related to Oil and Gas Activities

The following two unaudited tables set forth the Company’s share of costs incurred in the affiliated partnerships during the years ended December 31, 2011, 2010, and 2009. During 2009, the Company’s interest in one of the partnerships, SBE Partners, increased significantly from 2% to 30%. For further information see note L above.

Costs incurred in acquisition, development and exploration:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Acquisition cost	$	31	$	250	$	346
Development cost	$	321	$	304	$	771
Exploration cost	$	7	$	7	$	—

Capitalized cost of oil and gas properties:

	December 31,
	2011			2010
	(in thousands)
Proved properties	$	4,019		$	3,997
Unproved properties		—			—
		4,019			3,997
Accumulated depreciation, depletion and amortization		(1,042	)		(811	)
Net capitalized cost	$	2,977		$	3,186

2. Estimated Quantities of Proved Oil and Gas Reserves and Discounted Future Net Cash Flows

The reserve information presented above does not include the Company’s share of reserves held by two limited partnerships which are accounted for under the equity method of accounting. The following table presents the Company’s estimated share of the oil and gas reserves held by both limited partnerships as of December 31, 2011, 2010 and 2009.

	Year Ended December 31,
	2011				2010				2009
	Oil (Mbbls)		Gas (Mmcf)		Oil (Mbbls)		Gas (Mmcf)		Oil (Mbbls)		Gas (Mmcf)
Oil and gas volumes:
Proved developed		48		6,196		45		6,993		45		7,821
Proved undeveloped		6		784		7		861		10		613
Total		54		6,980		52		7,854		55		8,434

Page F-39

Presented below is a summary of the changes in estimated proved reserves of the Company’s equity investments, all of which are located in the United States, for the year ended December 31, 2011:

Oil and Gas Reserve Quantities:

	Oil (MBbl)			Gas (MMcf)
Proved reserve quantities, January 1, 2010		55			8,434
Production		(5	)		(1,007	)
Revision of quantity estimates		2			427
Proved reserve quantities, December 31, 2010		52			7,854
Sales of minerals-in-place		—			(1	)
Production		(5	)		(761	)
Revisions of quantity estimates		7			(112	)
Proved reserve quantities, December 31, 2011		54			6,980
Proved developed reserve quantities:
December 31, 2010		45			6,993
December 31, 2011		48			6,196
Proved undeveloped reserve quantities:
December 31, 2010		7			861
December 31, 2011		6			784

Presented below is the Company’s share of standardized measure of discounted future net cash flows as of December 31, 2011 for its equity investments:

Standardized Measure of Estimated Future Net Cash Flows:

	For the year ended December 31,
	2011		2010
	(in thousands)
Future cash inflows	$	32,418	$	33,916
Future production costs		11,540		11,485
Future development costs		2,522		2,506
Future income taxes		6,744		6,512
Future net cash flows		11,612		13,413
10% annual discount for estimated timing of cash flows		4,571		5,345
Standardized measure of discounted future cash flows	$	7,041	$	8,068

The principal sources of change in the Company’s share of standardized measure of discounted future net cash flows for the Company’s equity investments for 2011 are as follows (in thousands except for product prices):

Page F-40

Changes in Standardized Measure:

	For the year ended December 31,
	2011			2010
	(in thousands)
Standardized measure, beginning of period	$	8,068		$	7,335
Changes in prices, net of production cost		2,288			3,525
Revision of quantity estimates		31			454
Development costs incurred, previously estimated		(14	)		824
Change in estimated future development costs		44			(867	)
Sales of minerals-in-place		(2	)		—
Sale of oil and gas produced, net of production costs		(2,164	)		(3,000	)
Accretion of discount		1,073			910
Change in estimated future income taxes		(167	)		(643	)
Changes in timing of estimated cash flows and other		(2,116	)		(470	)
	$	7,041		$	8,068
Current prices at year-end, used in standardized measure:
Oil (per barrel)	$	96.16		$	79.43
Gas (per Mcf)	$	4.11		$	4.37

NOTE O: Subsequent Events

In January, 2012, the Company awarded 167,520 in restricted stock units to directors and officers, including subsidiary officers. Each restricted stock unit represents a contingent right to receive one share of the Company’s common stock upon vesting. Vesting occurs over a three year period for 149,000 of these units and over one year for the remaining 18,520 units.

On January 20, 2012, the Company closed on an acquisition of unproved leasehold interests in McKenzie County, North Dakota. The Company acquired an average net interest of 10.2% in approximately 3,700 net acres. The Company’s net acquisition cost was $12.7 million and was funded with working capital and borrowings on its credit facility.

On February 29, 2012, the Company closed an acquisition of producing wells and acreage in the Austin Chalk trend of east Texas in the Brookeland field area. The Company acquired varying working interests in 96 producing and productive wells across approximately 170,000 net acres. The Company’s net acquisition cost was $40.4 million, subject to closing adjustments for normal operating activity and other customary purchase price adjustments. The acquisition was funded with borrowings on its credit facility.

As a result of the two acquisitions and other capital expenditures, the outstanding balance on the Company’s credit facility was $60 million as of March 9, 2012.

On January 30, 2012, the Company entered into one additional natural gas swap and two additional crude oil swaps. The natural gas swap has a term of February 2012 to December 2013. The swap has a quantity of 20,000 Mmbtus per month at a fixed price of $2.925 per Mmbtu during 2012 and $3.560 per Mmbtu during 2013. The first of the two crude oil swaps has a term of January 2012 to December 2013. The swap has a quantity of 5,000 Bbls per month at a fixed price of $99.55 per barrel during 2012 and $97.60 during 2013. The second of the two crude oil swaps has a term of January 2012 to December 2013. The swap has a quantity of 5,000 Bbls per month at a fixed price of $107.30 per barrel during 2012 and $100.70 during 2013.

On February 24, 2012, the Company entered into an additional crude oil swap. The swap has a term of March 2012 to December 2013. The swap has a quantity of 10,000 Bbls per month at a fixed price of $108.45 per Mmbtu during 2012 and $105.55 during 2013.

Page F-41

Signatures

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	GEORESOURCES, INC. (the “Registrant”)
Dated: March 13, 2012	By:	/s/ Frank A. Lodzinski
		Frank A. Lodzinski, President and Chief Executive Officer

(Power of Attorney)

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints FRANK A. LODZINSKI and HOWARD E. EHLER, and each of them severally his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this annual report on Form 10-K for the year ended December 31, 2011, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of and on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Frank A. Lodzinski	President, Chief Executive Officer	March 13, 2012
Frank A. Lodzinski	(principal executive officer) and Director
/s/ Howard E. Ehler	Principal Financial Officer and Principal Accounting Officer	March 13, 2012
Howard E. Ehler
/s/ Robert J. Anderson	Director	March 13, 2012
Robert J. Anderson
/s/ Bryant W. Seaman III	Director	March 13, 2012
Bryant W. Seaman III
/s/ Jay F. Joliat	Director	March 13, 2012
Jay F. Joliat
/s/ Donald J. Whelley	Director	March 13, 2012
Donald J. Whelley
/s/ Nicholas L. Voller	Director	March 13, 2012
Nicholas L. Voller
/s/ Michael A. Vlasic	Director	March 13, 2012
Michael A. Vlasic

EX-21.1

EXHIBIT 21.1

SUBSIDIARIES OF THE REGISTRANT

Name	Jurisdiction of Incorporation or Organization
AROC (Texas), Inc.	Texas
Catena Oil & Gas, LLC	Texas
G3 Energy, LLC	Colorado
G3 Operating, LLC	Colorado
Southern Bay Energy, LLC	Texas
Southern Bay Louisiana, L.L.C.	Texas
Southern Bay Operating, L.L.C.	Texas
Western Star Drilling Company	North Dakota

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated March 13, 2012, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of GeoResources, Inc. on Form 10-K for the year ended December 31, 2011. We hereby consent to the incorporation by reference of said reports in the Registration Statements of GeoResources, Inc. on Form S-3 (File No. 333-144831, effective August 13, 2007; File No. 333-152041, effective July 10, 2008; and File No. 333-178710, effective February 10, 2012) and on Form S-8 (File No. 333-145221, effective August 8, 2007, File No. 333-149216, effective February 13, 2008 and File No. 333-175697, effective July 21, 2011).

/s/ Grant Thornton LLP

Houston, Texas

March 13, 2012

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated March 13, 2012,with respect to the financial statements of SBE Partners LP included in the Annual Report of GeoResources, Inc. on Form 10-K for the year ended December 31, 2011. We hereby consent to the incorporation by reference of said report in the Registration Statements of GeoResources, Inc. on Form S-3 (File No. 333-144831, effective August 13, 2007; File No. 333-152041, effective July 10, 2008; and File No. 333-178710, effective February 10, 2012) and on Form S-8 (File No. 333-145221, effective August 8, 2007, File No. 333-149216, effective February 13, 2008 and File No. 333-175697, effective July 21, 2011).

/s/ Grant Thornton LLP

Houston, Texas

March 13, 2012

EX-23.3

EXHIBIT 23.3

Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS

1000 LOUISIANA STREET, SUITE 625	306 WEST SEVENTH STREET, SUITE 302	9601 AMBERGLEN BLVD., SUITE 117
HOUSTON, TEXAS 77002-5008	FORT WORTH, TEXAS 76102-4987	AUSTIN, TEXAS 78729-1106
713-651-9944	817-336-2461	512-249-7000
FAX 713-651-9980	FAX 817-877-3728	FAX 512-233-2618

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of GeoResources, Inc. for the year ended December 31, 2011. We hereby further consent to the use of information contained in our reports setting forth the estimates of revenues from GeoResources, Inc.’s oil and gas reserves as of December 31, 2011, 2010 and 2009 and to the inclusion of our report dated February 27, 2012 as an exhibit to the Annual Report on Form 10-K of GeoResources, Inc. for the year ended December 31, 2011. We hereby further consent to the incorporation by reference thereof into GeoResources, Inc.’s Registration Statements on Form S-3 (File No. 333-144831, effective August 13, 2007; File No. 333-152041, effective July 10, 2008; and File No. 333-178710, effective February 10, 2012) and on Form S-8 (File No. 333-145221, effective August 8, 2007; File No. 333-149216, effective February 13, 2008; and File No. 333-175697, effective July 21, 2011).

Sincerely,

Cawley, Gillespie & Associates, Inc.

Texas Registered Engineering Firm F-693

March 13, 2012

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Frank A. Lodzinski, certify that:

1. I have reviewed this Annual Report on Form 10-K of GeoResources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Frank A. Lodzinski

Frank A. Lodzinski

Chief Executive Officer

March 13, 2012

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Howard E. Ehler, certify that:

1. I have reviewed this Annual Report on Form 10-K of GeoResources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Howard E. Ehler

Howard E. Ehler

Chief Financial Officer

March 13, 2012

EX-32.1

EXHIBIT 32.1

CERTIFICATION

I, Frank A. Lodzinski, certify that:

In connection with the Annual Report on Form 10-K of GeoResources, Inc. (the “Company”) for the year ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Frank A. Lodzinski, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Frank A. Lodzinski

Frank A. Lodzinski

Chief Executive Officer

March 13, 2012

* The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

EX-32.2

EXHIBIT 32.2

CERTIFICATION

I, Howard E. Ehler, certify that:

In connection with the Annual Report on Form 10-K of GeoResources, Inc. (the “Company”) for the year ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Howard E. Ehler, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Howard E. Ehler

Howard E. Ehler

Chief Financial Officer

March 13, 2012

* The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

EX-99.1

EXHIBIT 99.1

Report of Independent Registered Public Accountants

The Partners

SBE Partners LP

We have audited the accompanying balance sheets of SBE Partners LP (a Texas limited partnership) as of December 31, 2011 and 2010, and the related statements of income, partners’ capital and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion of the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SBE Partners LP as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Houston, Texas

March 13, 2012

SBE Partners LP

(a Texas Limited Partnership)

BALANCE SHEETS

December 31, 2011 and 2010

	2011			2010
ASSETS
Current assets:
Cash	$	960,912		$	505,036
Accounts receivable:
General Partner		2,779,622			2,277,496
Other		101,180			205,152
Commodity hedges		3,786,727			2,805,168
Prepaid expenses		48,894			38,078
Total current assets		7,677,335			5,830,930
Oil and gas properties, successful efforts method		102,979,443			100,550,556
Less accumulated depreciation, depletion and amortization		(47,375,023	)		(40,806,032	)
Net property and equipment		55,604,420			59,744,524
Commodity hedges		3,594,101			3,417,957
	$	66,875,856		$	68,993,411
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable—General Partner	$	258,260		$	753,234
Commodity hedges		259,322			257,014
Accrued liabilities		73,734			21,666
Total current liabilities		591,316			1,031,914
Commodity hedges		298,364			463,191
Asset retirement obligations		629,277			665,858
Partners’ capital:
General Partner		1,596,958			1,565,304
Limited Partner		56,907,599			59,764,227
Accumulated other comprehensive income		6,852,342			5,502,917
Total partners’ capital		65,356,899			66,832,448
	$	66,875,856		$	68,993,411

The accompanying notes are an integral part of these statements.

2

SBE Partners LP

(a Texas Limited Partnership)

STATEMENTS OF INCOME

	Year Ended December 31,
	2011		2010		2009
Revenues:
Oil and gas revenues	$	17,663,238	$	19,179,581	$	31,432,434
Gain on sale of property and equipment		—		—		13,090,717
Gain on cancellation of hedges		—		—		3,706,175
Refund of severance taxes		—		—		4,186,108
Interest and other income		294,010		941		13,115
Total revenues		17,957,248		19,180,522		52,428,549
Expenses:
Lease operating expense		2,103,937		2,013,631		2,536,929
Severance taxes		461,502		409,606		704,562
Re-engineering and workovers		558,741		784,813		1,362,787
Ad valorem tax and well insurance		649,224		828,357		1,170,945
Exploration expense		181,750		24,814		3,403
Depreciation, depletion and amortization		6,568,991		7,743,854		15,906,494
Hedge ineffectiveness		29,203		206,274		146,085
Management fees		286,014		318,256		698,481
Texas franchise taxes		—		325,074		—
Other expense		92,860		106,840		172,534
Total expenses		10,932,222		12,761,519		22,702,220
Net income	$	7,025,026	$	6,419,003	$	29,726,329

The accompanying notes are an integral part of these statements.

3

SBE Partners LP

(a Texas Limited Partnership)

STATEMENTS OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME

For the years ended December 31, 2011, 2010 and 2009

	General Partner			Limited Partner			Accumulated other comprehensive income (loss)			Total
Balance, January 1, 2009	$	2,273,096		$	110,503,387		$	7,566,743		$	120,343,226
Partners’ capital distributions		(2,292,706	)		(68,353,578	)		—			(70,646,284	)
Partners’ capital property distributions		(1,646,000	)		—						(1,646,000	)
Comprehensive income:
Net income		4,351,678			25,374,651			—			29,726,329
Change in fair market value of hedged positions		—			—			5,289,622			5,289,622
Net realized gains credited to income		—			—			(11,256,927	)		(11,256,927	)
Total comprehensive income											23,759,024
Balance, December 31, 2009	$	2,686,068		$	67,524,460		$	1,599,438		$	71,809,966
Partners’ capital cash distributions		(3,400,000	)		(11,900,000	)		—			(15,300,000	)
Comprehensive income:
Net income		2,279,236			4,139,767			—			6,419,003
Change in fair market value of hedged positions		—			—			7,776,101			7,776,101
Net realized gains credited to income		—			—			(3,872,622	)		(3,872,622	)
Total comprehensive income											10,322,482
Balance, December 31, 2010		1,565,304			59,764,227			5,502,917			66,832,448
Partners’ capital cash distributions		(1,750,000	)		(8,100,000	)		—			(9,850,000	)
Comprehensive income:
Net income		1,781,654			5,243,372			—			7,025,026
Change in fair market value of hedged positions		—			—			4,660,914			4,660,914
Net realized gains credited to income		—			—			(3,311,489	)		(3,311,489	)
Total comprehensive income											8,374,451
Balance, December 31, 2011	$	1,596,958		$	56,907,599		$	6,852,342		$	65,356,899

The accompanying notes are an integral part of this statement.

4

SBE Partners LP

(a Texas Limited Partnership)

STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income	$	7,025,026		$	6,419,003		$	29,726,329
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		6,568,991			7,743,854			15,906,494
Gain on sale of properties		—			—			(13,090,717	)
Accretion of asset retirement obligations		46,051			29,829			29,776
Hedge ineffectiveness loss		29,203			206,274			146,085
Unrealized gain on hedge cancellation		—			—			(87,750	)
Changes in assets and liabilities:
(Increase) decrease accounts receivable		(398,154	)		5,249,396			1,600,970
(Increase) decrease prepaid expense and other		(10,816	)		10,498			21,785
Decrease accounts payable and accrued expenses		(442,906	)		(144,470	)		(1,429,071	)
Net cash provided by operating activities		12,817,395			19,514,384			32,823,901
Cash flows from investing activities:
Proceeds from sale of properties		—			—			49,340,386
Additions of property and equipment		(2,511,519	)		(6,419,592	)		(16,037,776	)
Net cash provided by (used in) investing activities		(2,511,519	)		(6,419,592	)		33,302,610
Cash flows from financing activities:
Partners’ capital distributions		(9,850,000	)		(15,300,000	)		(70,646,284	)
Net cash used in financing activities		(9,850,000	)		(15,300,000	)		(70,646,284	)
Net increase (decrease) in cash		455,876			(2,205,208	)		(4,519,773	)
Cash and cash equivalents at beginning of period		505,036			2,710,244			7,230,017
Cash and cash equivalents at end of period	$	960,912		$	505,036		$	2,710,244
Supplementary information:
Non-cash property distribution	$	—		$	—		$	1,646,000

The accompanying notes are an integral part of these statements.

5

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

NOTE A – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1. Organization and Basis of Presentation

SBE Partners LP (the “Partnership”) was formed January 15, 2007 as a Texas limited partnership, with Catena Oil and Gas LLC, a wholly-owned subsidiary of Southern Bay Oil & Gas, L.P. (now Southern Bay Energy, LLC) as general partner and EFS O&G, LLC, an affiliate of General Electric Company, as limited partner. On February 13, 2007, the Partnership acquired proved oil and gas properties located in Southeast Texas for approximately $75 million, subject to normal and customary adjustments, which was funded from partners’ capital contributions.

Partnership revenues, costs and expenses, except for hedging activities, were shared 98% by the limited partner and 2% by the general partner, until the limited partner achieved “Cumulative Payout” (as defined in the Agreement of Limited Partnership), which was achieved in June 2009. Subsequent to cumulative payout the sharing percentages for revenues and operating costs and expenses changed to 70% to the limited partner and 30% to the general partner for wells existing at the time of the payout. Revenues, operating costs and expenses associated with new wells acquired or developed subsequent to the payout are shared 98% by the limited partner and 2% by the general partner. Depletion is shared in a manner consistent with the capital expended to acquire the asset being depleted. The income and expense from hedging activity is allocated entirely to the limited partner.

The Agreement of Limited Partnership provides that the General Partner has the full and exclusive authority to manage, control, administer and operate the properties, business and affairs of the Partnership. However, the general partner may not perform certain acts without the consent of the Limited Partner. Those restrictions generally relate to the ability of the General Partner to borrow money on behalf of the Partnership, mortgage or otherwise encumber Partnership properties, dispose of Partnership properties, make guarantees on behalf of the Partnership, make advance payments of compensation to the general partner, loan money to the General Partner, merge the Partnership, acquire leases in the name of the Partnership, enter into, amend or terminate hedging transactions and to generally perform any acts which would be detrimental to the Partnership.

The Partnership’s oil and gas interests are located exclusively in the Giddings Field of the Austin Chalk trend of southeast Texas.

2. Financial Instruments

The carrying amounts of the Partnership’s financial instruments, which include accounts receivable, accounts payable and accrued expenses, approximate fair values because of their short-term nature. The Partnership’s derivative instruments are measured and recorded at fair value.

3. Revenue Recognition

Revenues represent income from production and delivery of oil and gas, recorded net of royalties. The Partnership follows the sales method of accounting for gas imbalances. A liability is recorded only if the Partnership’s takes of gas production exceed its share of estimated recoverable reserves from the respective

6

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE A – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

well. No receivables are recorded for those wells where the Partnership has taken less than its ownership share of production. Volumetric production is monitored to minimize imbalances, and such imbalances were not significant at December 31, 2011 and 2010.

4. Accounts Receivable

The Partnership sells crude oil and natural gas to various customers. Substantially all of the Partnership’s accounts receivables are due from purchasers of crude oil and natural gas. Crude oil and natural gas sales are generally unsecured.

As is common industry practice, the Partnership generally does not require collateral or other security as a condition of sale, rather relying on credit approval, balance limitation and monitoring procedures to control the credit use on accounts receivable. The allowance for doubtful accounts is an estimate of the losses in the Partnership’s accounts receivable. The Partnership periodically reviews the accounts receivable from customers for any collectibility issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged-off are added to the allowance.

Accounts receivable allowance for bad debts was $0 at December 31, 2011 and 2010.

5. Oil and Gas Properties

The Partnership follows the successful efforts method of accounting for oil and gas operations whereby costs to acquire mineral interests in oil and gas properties, to drill exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Exploration costs, including exploratory dry holes, geological and geophysical and costs of carrying and retaining unproved properties, are charged to operations as incurred.

The Partnership’s acquisition and development costs of proved oil and gas properties are amortized using the unit-of-production method based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers.

Oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. Fair value of impaired assets may be estimated using comparable market data or based on expected future cash flows using discount rate commensurate with the risks involved and using prices and costs consistent with those used by the general partner for internal decision making or a combination of the two. Long-lived assets committed by management for disposal are accounted for at the lower of cost or fair value, less cost to sell. There were no impairments recognized during 2011, 2010 or 2009.

7

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE A – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

6. Income Taxes

The Partnership is not subject to Federal or state income tax on its taxable income. The taxable income and deductions are reported by the partners in their respective income tax returns and all tax obligations are borne solely by the partners. Therefore, the Partnership generally makes no provision for income taxes in its financial statements. It is possible, however, that the partnership could in the future earn sufficient non-passive income to incur margin tax in the state of Texas.

At December 31, 2011, the Partnership did not have any uncertain tax positions that would require recognition. The Partnership’s uncertain tax positions may change in the next twelve months; however, the Partnership does not expect any possible change to have a significant impact on its results of operation or financial position. If incurred, the Company records income tax interest and penalties as a component of income tax expense.

7. Derivative Instruments and Hedging Activities

The Partnership enters into derivative contracts, primarily options and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of downward movements of market prices. As required, under current accounting standards, all derivatives are recognized on the balance sheet and measured at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in other comprehensive income to the extent the hedge is effective for cash flow hedges. To qualify for hedge accounting, the derivative must qualify either as a fair value, cash flow or foreign currency hedge.

The hedging relationship between the hedged instruments and hedged transactions must be highly effective in achieving the offset of changes in fair values and cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. The Partnership measures hedge effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedging instrument becomes ineffective. The Partnership assesses hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes in intrinsic value only. As a result, changes in the entire value of option contracts are deferred in accumulated other comprehensive income until the hedge transaction affects earnings to the extent such contracts are effective. Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered.

Gains and losses resulting from hedge settlements are included in oil and gas revenues and are included in realized prices in the period in which the related production is delivered. Gains and losses on hedging instruments that represent hedge ineffectiveness and gains and losses on derivative instruments that do not qualify for hedge accounting are included in other revenues or expenses in the period in which they occur. The resulting cash flows are reported as cash flows from operating activities.

8

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE A – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

8. Cash and Cash Equivalents

The Partnership treats all unrestricted investments with an original maturity of three months or less to be cash equivalents. The Partnership maintains its cash in one financial institution and periodically assesses the financial condition of the institution. The combined account balance typically exceeds Federal Deposit Insurance Corporations (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage. The General Partner believes that any possible credit risk is minimal.

9. Accounting Estimates

In the course of preparing financial statements in conformity with generally accepted accounting principles, management makes various assumptions and estimates to determine the reported amounts of assets, liabilities, revenues and expenses in relation to the disclosure of commitments and contingencies. Changes in these assumptions and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, the actual results could differ from the amounts estimated.

10. Comprehensive Income

The Partnership reports comprehensive income within its Statement of Partners’ Capital and Comprehensive Income. Other comprehensive income at December 31, 2011, 2010 and 2009 consists of unrealized gains (losses) of commodity hedges qualifying as cash flow hedges in accordance with current accounting standards.

11. Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance Sheet (Topic 210) – Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangement to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting under current accounting literature or are subject to master netting agreements irrespective of whether they are offset. The objective of the new disclosures is to facilitate comparison between entities that prepare financial statements on the basis of U.S. GAAP and entities that prepare financial statements under IFRS. The disclosure requirements will be effective for periods beginning on or after January 1, 2013 and must be applied retrospectively to all periods presented on the balance sheet. The Partnership will adopt the requirements of ASU No. 2011-11 on January 1, 2013, which may require additional footnote disclosures for derivative instruments and is not expected to have a material effect on the Partnership’s financial position, results of operations or cash flows.

In June 2011, the FASB issued ASU 2011-05 – Comprehensive Income (Topic 220) – Presentation of Comprehensive Income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, entities are required to present reclassification adjustments for items that are reclassified from other

9

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE A – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. The Partnership will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012.

In May 2011, the FASB issued ASU 2011-04 – Fair Value Measurements (Topic 820) – Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS. This This ASU issued authoritative guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. The ASU expands existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place, and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. Entities will also be required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

Other amendments include clarifying the highest and best use and valuation premise for nonfinancial assets, premiums and discounts in fair value measurement, and fair value of an instrument classified in a reporting entity’s shareholders’ equity.

ASU 2011-04 is effective during interim and annual periods beginning after December 15, 2011, and therefore will become effective for the Partnership on January 1, 2012. Other than the disclosure requirements, ASU 2011-04 is not expected to have a significant impact on the Partnership’s financial position, results of operations or cash flows.

NOTE B – RELATED PARTY TRANSACTIONS

Accounts receivable from the General Partner represent oil and gas revenues collected by the General Partner on behalf of the Partnership. Accounts payable to the General Partner represent the Partnership’s share of property operating expenditures and capital expenditures that were incurred by operating subsidiaries of the General Partner on behalf of the Partnership and accrued management fees.

A subsidiary of the General Partner operates the oil and gas properties in which the Partnership has an interest. Under this arrangement, that subsidiary collects the Partnership’s share of revenues from purchasers and incurs property operating and development expenditures on behalf of the Partnership. Monthly, the Partnership’s revenues are paid to the Partnership and the Partnership reimburses these entities for its share of expenditures.

The Partnership Agreement provides for a monthly management fee to be paid to the General Partner equal to 2% of the Partnership’s Net Monthly Income, as defined in the partnership agreement. During 2011, 2010 and 2009 the Partnership incurred management fees of $286,014, $318,256, and $698,481, respectively.

10

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE B – RELATED PARTY TRANSACTIONS – Continued

On May 29, 2009, effective May 1, 2009, the Partnership, entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Catena Oil and Gas LLC (“Catena”), the General Partner of this Partnership for the sale of certain oil and gas producing properties in Giddings Field, Grimes and Montgomery Counties, Texas (the “Interests”). Under the Purchase Agreement, the Interests were purchased for a net cash purchase price of $48,340,386 subject to adjustments at closing for normal operations activity and other customary purchase price adjustments (the “Purchase Price”). The Purchase Agreement contains representations and warranties, covenants, and indemnifications that are customary for oil and gas producing property acquisitions. The Partnership recorded a gain of $12,053,717 on this sale. The gain was shared 98% by the limited partner and 2% by the general partner. The proceeds of the sale were distributed to the partners as a cash distribution subsequent to the sale.

On August 29, 2009, the Partnership, distributed to Catena, the General Partner, its share of proved undeveloped property and unproved acreage in the Giddings Field. The distribution was recorded at fair value and a gain of $1,037,000 was recorded on the transaction. The gain was not shared by the partners; the General Partner’s capital account received 100% of the gain.

NOTE C – ASSET RETIREMENT OBLIGATIONS

The Partnership records the present value of estimated future abandonment costs as both a liability, asset retirement obligation (“ARO”), and as an addition to the capitalized cost of its oil and gas properties. The Partnership will increase the abandonment liability associated with its oil and gas wells as new wells are drilled. The changes to the ARO during the years ended December 31, 2011 and 2010 are as follows:

	2011			2010
Balance, beginning of year	$	665,858		$	401,738
Disposals		—			(6,125	)
Liabilities incurred		6,245			17,967
Revision of estimates		(88,877	)		222,449
Accretion expense		46,051			29,829
Balance, end of year	$	629,277		$	665,858

NOTE D – DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership enters into various crude oil and natural gas hedging contracts, primarily 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. Swaps are designed so that the Partnership receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Partnership has designated its commodity derivative contracts as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they also limit future revenues from favorable price movements. The Partnership does not enter into commodity derivative instruments for speculative or trading purposes.

11

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE D – DERIVATIVE FINANCIAL INSTRUMENTS – Continued

On May 29, 2009, in conjunction with the sale of certain partnership properties, discussed in Note B above, the Partnership canceled a portion of the cash flow hedges in place at the time of the sale. The Partnership’s hedging strategy, since inception, has been for the Partnership to enter into hedging contracts, primarily swaps, in order to hedge approximately 85% of the forecasted proved developed production allocated to the limited partner. Since a significant portion of forecast production, 36.2%, was sold to the general partner, and the sharing percentage of revenue changed as a result of achieving cumulative pay, the limited partner elected to cancel a portion of the hedges in place prior to the sale. The following table shows the quantities and prices of the portions of the hedges that were cancelled:

	Product	Price		Canceled Volumes			May 29, 2009 Value
2009	Natural Gas	$	7.5500		459,501	Mmbtu	$	1,537,389
2009	Natural Gas	$	8.6050		420,679	Mmbtu		1,856,843
2009	Natural Gas	$	4.0200		794,829	Mmbtu		(117,290	)
2010	Natural Gas	$	7.2500		787,716	Mmbtu		578,509
2010	Natural Gas	$	8.3750		477,864	Mmbtu		988,157
2010	Natural Gas	$	5.3000		721,020	Mmbtu		(672,699	)
2009	Oil	$	58.2500		5,390	Bbl		(60,366	)
2010	Oil	$	58.4000		7,560	Bbl		(108,795	)
2011	Oil	$	58.6500		6,696	Bbl		(110,396	)
2012	Oil	$	58.9000		5,808	Bbl		(101,241	)
2013	Oil	$	59.0000		5,088	Bbl		(91,018	)
2014	Oil	$	59.1000		4,404	Bbl		(80,668	)
			Total cash proceeds on cancelled hedges				$	3,618,425

The canceled hedges were previously designated as cash flow hedges. When a cash flow hedge is discontinued, the net derivative gain or loss remains in accumulated other comprehensive income unless it is probable that the forecasted transaction will not occur in the originally specified time period or within an additional two-month period thereafter. Due to the sale of properties and the subsequent payout and change in sharing ratios between the partners the forecast transaction associated with the above hedges was no longer probable of occurring; therefore, the derivative gain or loss reported in accumulated other comprehensive income at the time of cancellation was reclassified into earnings immediately. The partnership reclassified into earnings a net gain of $3,706,175, recognized a mark-to-market gain of $87,750 and received cash of $3,618,425.

In July 2010, the Partnership entered into an additional gas swap. The term of the swap is from January 2011 to December 2011. The swap has a fixed price of $5.02. The swap is for 54,515 Mmbtu per month.

12

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE D – DERIVATIVE FINANCIAL INSTRUMENTS – Continued

In July 2010, the Partnership entered into an additional oil swap. The term of the swap is from January 2011 through December 2013. The swap has a fixed price of $79.50 from January 2011 through December 2011, $80.87 from January 2012 through December 2012, and $81.90 from January 2013 through December 2013. The swap provides for 520 Bbls per month from January 2011 through December 2011, 378 per month Bbls from January 2012 through December 2012, and 314 Bbls per month from January 2013 through December 2013.

In July 2011, the Partnership into an additional gas swap. The term of the swap is from January 2012 to December 2012. The swap has a fixed price of $4.70. The swap is for 41,556 Mmbtu per month.

At December 31, 2011, accumulated other comprehensive income (loss) consisted of unrecognized gains of $6,852,342, representing the inception to date change in mark-to-market value of the effective portion of the Partnership’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2010, accumulated other comprehensive income (loss) consisted of $5,502,917 of unrecognized gains. For the year ended December 31, 2011 and 2010, the Partnership recognized realized cash settlement gains on commodity derivatives of $3,311,489 and $3,872,622, respectively. Based on the estimated fair market value of the Company’s derivative contracts designated as hedges at December 31, 2011, the Partnership expects to reclassify net gains on gas swaps of $3,786,727 and net losses on oil swaps of $259,322 into earnings from accumulated other comprehensive income during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

At December 31, 2011, the Partnership hedged its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:

	Total Remaining Volume		Swap Price
Crude Oil Swap Contracts (Bbls):
2012		4,200	$	58.90
2012		4,536	$	80.87
2013		3,612	$	59.00
2013		3,768	$	81.90
2014		3,228	$	59.10
Natural Gas Swap Contracts (Mmbtu)
2012		498,672	$	4.70
2012		865,596	$	6.73
2013		769,020	$	6.63
2014		680,916	$	6.61

13

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE D – DERIVATIVE FINANCIAL INSTRUMENTS – Continued

As of December 31, 2011, fair market value of the gas swap contracts was an asset of $7,380,828, of which $3,786,727 is included in current assets and $3,594,101 in non-current assets. As of that date, the fair market value of the oil swap contract was a liability of $557,686, of which $259,322 is included in current liabilities and $298,364 in non-current liabilities. As of December 31, 2010, fair market value of the gas swap contracts was an asset of $6,223,125, of which $2,805,168 is included in current assets and $3,417,957 in non-current assets. As of that date, the fair market value of the oil swap contract was a liability of $720,205, of which $257,014 is included in current assets and $463,191 in non-current liabilities.

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

	Asset Derivatives					Liability Derivatives
Derivatives		Fair Value					Fair Value
designated as ASC 815 hedges:	Balance Sheet Location	Dec. 31, 2011		Dec. 31, 2010		Balance Sheet Location	Dec. 31, 2011			Dec. 31, 2010
Commodity contracts	Current derivative financial instruments asset	$	3,786,727	$	2,805,168	Current derivative financial instruments liability	$	(259,322	)	$	(257,014	)
Commodity contracts	Long-term derivative financial instruments asset		3,594,101		3,417,957	Long-term derivative financial instruments liability		(298,364	)		(463,191	)
		$	7,380,828	$	6,223,125		$	(557,686	)	$	(720,205	)

14

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE D – DERIVATIVE FINANCIAL INSTRUMENTS – Continued

The following table summarizes the effects of commodity derivative instruments on the statements of income for the years ended December 31, 2011, 2010 and 2009:

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion)
	2011		2010		2009
Commodity contracts	$	4,660,914	$	7,776,101	$	5,289,622

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)						Location of Gain or (Loss) Reclassifed from OCI into Income (Effective Portion)
	2011		2010		2009
Commodity contracts	$	3,311,489	$	3,782,622	$	7,550,752	Oil and gas revenues
Commodity contracts		—		—		3,706,175	Gain on cancelation of hedges
	$	3,311,489	$	3,782,622	$	11,256,927

Derivatives in ASC 815 cash flow hedging relationships:	Amount of Gain or (Loss) Recognized in Income on Derivative  (Ineffective Portion)									Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)
	2011			2010			2009
Commodity contracts	$	(29,203	)	$	(206,274	)	$	(146,085	)	Hedge ineffectiveness

The Partnership does not have any derivatives that are not accounted for as cash flow hedges (ASC 815 hedges).

15

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE D – DERIVATIVE FINANCIAL INSTRUMENTS – Continued

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

NOTE E – FAIR VALUE DISCLOSURES

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

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

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

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

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

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

Derivative Financial Instruments – Derivative financial instruments are carried at fair value. Commodity derivative instruments consist of swaps for crude oil and natural gas. The Partnership’s swaps are valued based on a discounted future cash flow model. The primary input for the model is the NYMEX futures index. The Partnership’s model is validated by the counterparty’s marked-to-market statements. The swaps are 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.

16

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE E – FAIR VALUE DISCLOSURES – Continued

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 Partnership’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 Partnership’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Partnership to determine such fair value:

	As of December 31, 2011
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balances as of December 31, 2011
Current portion of derivative financial instrument asset		—	$	3,786,727			—	$	3,786,727
Long-term portion of derivative financial instrument asset		—		3,594,101			—		3,594,101
Current portion of derivative financial instrument liability		—		(259,322	)		—		(259,322	)
Long-term portion of derivative financial instrument liability		—		(298,364	)		—		(298,364	)

17

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE E – FAIR VALUE DISCLOSURES – Continued

	As of December 31, 2010
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balances as of December 31, 2010
Current portion of derivative financial instrument asset		—	$	2,805,168			—	$	2,805,168
Long-term portion of derivative financial instrument asset		—		3,417,957			—		3,417,957
Current portion of derivative financial instrument liability		—		(257,014	)		—		(257,014	)
Long-term portion of derivative financial instrument liability		—		(463,191	)		—		(463,191	)

At December 31, 2011 and 2010, the Partnership did not have any assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3. There were no transfers between Level 1 and Level 2 of the fair value hierarchy during the years ended December 31, 2011 or 2010. Further, there were no transfers in and/or out of Level 3 of the fair value hierarchy during the years ended December 31, 2011 and 2010.

Asset Impairments – The Partnership reviews proved oil and gas properties for impairment when events and circumstances indicate a significant decline in the recoverability of the carrying value of such properties. When events and circumstances indicate a significant decline in the recoverability of a property, the Partnership estimates the future cash flows expected in connection with the property and compares such future cash flows to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. The Partnership did not record any impairments during the years ended December 31, 2011, 2010 or 2009.

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

18

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE F – SIGNIFICANT CUSTOMERS

In 2011, 2010 and 2009 three purchasers accounted for 100% of the Partnership’s oil and gas revenues. There are adequate purchasers of the Partnership’s production such that the General Partner believes the loss of one or more of the above purchasers would not have a material adverse effect on its results of operations or cash flows.

NOTE G – SUBSEQUENT EVENTS

The General Partner has evaluated subsequent events for the Partnership through March 13, 2013, the date these financial statements were available to be issued. The General Partner is not aware of any subsequent events which would require recognition or disclosure in the Partnership’s financial statements.

NOTE H – OIL AND GAS ACTIVITES

The Partnership’s oil and gas activities for 2011, 2010 and 2009 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows:

	Year Ended December 31,
	2011		2010		2009
Acquisition	$	577,683	$	832,700	$	2,727,411
Development	$	1,933,836	$	5,586,952	$	12,537,779
Exploration	$	181,750	$	24,814	$	—

During 2011, 2010, and 2009 additions to oil and gas properties of $6,245, $234,291 and $42,510 were recorded for the estimated costs of future abandonment related to new wells drilled or revisions of the estimates for wells acquired or drilled in prior year. Acquisition costs for 2011, 2010 and 2009 consisted of smaller acreage additions and other leasehold costs.

The Partnership incurred exploratory costs for the years ended December 31, 2011, 2010 and 2009 of $181,750, $24,814, and $3,403, respectively.

NOTE I – SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

For all years presented, the estimate of proved reserves and related valuations were based 100% on reports prepared by the General Partner’s independent petroleum engineers on behalf of the Partnership. These reports were prepared by Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to definitions prescribed by the U.S. Securities and Exchange Commission. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

19

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE I – SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) – Continued

As of December 31, 2012, all of the Partnership’s oil and gas reserves are attributable to properties within the United States. A summary of the Partnership’s change in quantities of proved oil and gas reserves for the years ended December 31, 2011, 2010 and 2012 are as follows:

	Oil (Bbl)			Gas (Mcf)
Proved reserve quantities, January 1, 2009		406,501			62,675,631
Sales of minerials-in-place		(184,389	)		(25,611,226	)
Extensions and discoveries		35,630			6,405,080
Production		(17,955	)		(7,750,279	)
Revision of quantity estimates		23,798			983,993
Proved reserve quantities, December 31, 2009		263,585			36,703,199
Production		(25,560	)		(3,727,785	)
Revision of quantity estimates		(49,751	)		687,101
Proved reserve quantities, December 31, 2010		188,274			33,662,515
Production		(42,981	)		(2,891,921	)
Revision of quantity estimates		88,888			(89,351	)
Proved reserve quantities, December 31, 2011		234,181			30,681,243
Proved developed reserve quantities
December 31, 2009		175,802			27,600,395
December 31, 2010		148,364			24,816,658
December 31, 2011		219,646			22,112,522
Proved undeveloped reserve quantities
December 31, 2009		87,783			9,102,804
December 31, 2010		39,910			8,845,857
December 31, 2011		14,535			8,568,721

Notable changes in proved reserves for the year ended December 31, 2009 included:

• Revisions to previous estimate. In 2009, revisions to previous estimates increased proved developed and proved undeveloped reserves by a net amount of 23,798 Bbls of oil and 983,993 Mcf of natural gas. Included in these revisions were 27,100 Bbls of oil and 4,674,200 Mcf of natural gas of downward revisions due to the use of a 12-months average price as prescribed by the revised reserve rules adopted in 2009 instead of an end of the year price.

20

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE I – SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) – Continued

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC topic “Extractive Activities – oil and gas”. Future cash inflows as of December 31, 2011, 2010, and 2009, were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2011, 2010 and 2009) to estimate future production.

Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions.

Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily result in an estimate of the fair value of the Partnership’s oil and gas properties. Income taxes have not been taken into account, since future taxable income or loss is taxed directly to the partners, not to the Partnership.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

	December 31, 2011		December 31, 2010		December 31, 2009
Future cash inflows	$	136,393,719	$	139,228,781	$	126,349,047
Future production costs		41,946,313		42,363,506		38,521,186
Future development costs		17,898,421		17,575,241		16,899,002
Future net cash flows		76,548,985		79,290,034		70,928,859
10% annual discount for estimated timing of cash flows		30,427,870		31,939,046		27,027,324
Standardized measure of discounted future cash flows	$	46,121,115	$	47,350,988	$	43,901,535

Future net cash flows as shown above are reported without consideration of the effects of open hedge contracts at each period ended. If the effects of hedging transactions were included in the computations, then undiscounted future cash flows would have increased by $6.8 million, $5.5 million and $1.8 million in 2011, 2010 and 2009, respectively.

21

SBE Partners LP

(a Texas Limited Partnership)

NOTES TO FINANCIAL STATEMENTS - CONTINUED

December 31, 2011, 2010 and 2009

NOTE I – SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) – Continued

The changes in standardized measure of discounted future net cash flows (not including the effects of hedging) for the years ended December 31, 2011, 2010 and 2009 are as follows:

	Year Ended December 31,
	2011			2010			2009*
Standardized measure, beginning of period	$	47,350,988		$	43,901,535		$	113,150,203
Sales of minerials-in-place		—			—			(27,923,720	)
Changes in prices, net of production costs		9,572,434			11,475,746			(56,691,317	)
Extensions and discoveries		—			—			3,827,990
Revision of quantity estimates		787,427			646,100			7,711,315
Development costs incurred, previously estimated		(682,096	)		3,020,539			9,542,120
Change in estimated future development cost		487,349			(3,424,382	)		(1,022,302	)
Sales, net of production costs		(10,578,345	)		(11,270,550	)		(17,235,758	)
Accretion of discount		4,503,871			4,120,559			10,585,825
Changes in timing of estimated cash flows and other		(5,320,513	)		(1,118,559	)		1,957,179
Standardized measure, end of period	$	46,121,115		$	47,350,988		$	43,901,535
Current prices used in standardized measure:
Oil (per barrel)	$	96.19		$	79.43		$	61.18
Gas (per Mcf)	$	4.11		$	4.37		$	3.83

* In 2009, standardized measure was reduced by $35,645,000 due to the use of a 12-month average price as prescribed by the new rules versus as end of year price. Had the Partnership not changed its pricing method to comply with the SEC’s revised rules the standardized measure at December 31, 2009 would have been $79,573,000.

22

EX-99.2

EXHIBIT 99.2

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

February 27, 2012

Mr. Robert Anderson

Chief Operating Officer – Northern Region &

Executive VP – Engineering Acquisitions

GeoResources, Inc.

110 Cypress Station Dr. Suite 220

Houston, Texas 77090

Re:	Evaluation Summary – SEC Price Case
	GeoResources, Inc. Interests Total Proved Reserves Certain Oil & Gas Properties in Various States As of January 1, 2012

Dear Mr. Anderson:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the GeoResources, Inc. interests in certain oil and gas properties located in various states within the United States. This report, completed February 27, 2012 covers 100% of the proved reserves for GeoResources, Inc. The results of this evaluation are presented below:

		Proved Developed Producing		Proved Developed Non-Producing		Proved Undeveloped		Total Proved
Net Reserves
Oil	-  Mbbl		10,794.4		3,111.5		5,787.0		19,692.9
Gas	-  MMcf		28,738.6		5,379.6		17,096.3		51,214.5
NGL	-  Mbbl		534.5		198.2		282.4		1,015.1
Revenue
Oil	-  M$		985,511.7		286,404.5		518,046.8		1,789,962.6
Gas	-  M$		109,897.5		20,652.9		60,109.0		190,659.4
NGL	-  M$		28,344.2		10,815.3		16,608.8		55,768.3
Hedge	-  M$		0.0		0.0		0.0		0.0
Other	-  M$		0.0		0.0		0.0		0.0
Severance Taxes	-  M$		98,841.5		29,010.7		53,468.7		181,320.9
Ad Valorem Taxes	-  M$		12,858.5		1,989.5		4,344.9		19,192.9
Operating Expenses	-  M$		341,651.2		37,370.0		78,394.1		457,415.3
Workover Expenses	-  M$		0.0		0.0		0.0		0.0
3rd Party COPAS	-  M$		0.0		0.0		0.0		0.0
Other Deductions	-  M$		0.0		0.0		0.0		0.0
Investments	-  M$		3,071.6		28,345.8		165,830.1		197,247.4
Net Operating Income	-  M$		667,330.3		221,156.5		292,727.1		1,181,213.5
Discounted @ 10%	-  M$		376,689.5		109,501.9		128,707.9		614,899.2

GeoResources, Inc.

February 27, 2012

Page 2

The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc. (“CG&A”)

Hydrocarbon Pricing

As requested for the SEC Price scenario, oil and gas prices were adjusted to the following index prices.

Year	WTI Oil Price $/BBL	HH Gas Price $/MMBTU
2012	96.19	4.11

In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2011. Prices were not escalated in the SEC scenario. Adjustments to oil and gas prices were made based upon data provided by your office. These adjustments include treating cost, transportation charges and/or crude quality and gravity corrections.

Expenses and Taxes

Lease operating expenses and investments were forecast as furnished by your office and were not escalated. Severance tax values were determined by applying normal state severance tax rates. Ad valorem tax rates were forecast as provided by your office.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 230 proved undeveloped locations, which includes 17 locations in Louisiana, 6 locations in Montana, 1 location in New Mexico, 110 locations in North Dakota, 73 locations in Oklahoma and 23 locations in Texas. Each of these drilling locations proposed as part of GeoResources’ development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, GeoResources has indicated they have every intent to complete this development plan within the next five years. Furthermore, GeoResources has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

GeoResources, Inc.

February 27, 2012

Page 3

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for GeoResources properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by Robert D. Ravnaas, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or GeoResources, Inc. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

	Yours very truly,
	Robert D. Ravnaas, P.E. President Cawley, Gillespie & Associates Texas Registered Engineering Firm F-693

APPENDIX

Explanatory Comments for Summary Tables

HEADINGS

Table I

Description of Table Information

Identity of Interest Evaluated

Property Description – Location

Reserve Classification and Development Status

Effective Date of Evaluation

FORECAST

(Columns)
(1) (11) (21)	Calendar or Fiscal years/months commencing on effective date.
(2)(3)(4)	Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date and ultimate recovery at the effective date are shown following the annual/monthly forecasts.
(5)(6)(7)	Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.
(8)	Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)	Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)	Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)	Revenue derived from oil sales — column (5) times column (8).
(13)	Revenue derived from gas sales — column (6) times column (9).
(14)	Revenue derived from NGL sales — column (7) times column (10).
(15)	Revenue derived from hedge positions.
(16)	Revenue derived from other sources not included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc.
(17)	Total Revenue – sum of column (12) through column (16).
(18)	Production-Severance taxes deducted from gross oil, gas and NGL revenue.
(19)	Ad Valorem taxes.
(20)	$/BOE6 – is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil.
(22)	Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)	Average gross wells.
(24)	Average net wells are gross wells times working interest.
(25)	Workover Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(26)	3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(27)	Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
(28)	Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.
(29)(30)	Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.
(31)	Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

DCF Profile	•    The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.
Life	•    The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes	•    Comments regarding the evaluation may be shown in the lower left-hand footnotes.
Price Deck	•    A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.
Differentials	•    Total annual price adjustments may be shown in gray font to the left of column (8), column (9) and column (10).

Cawley, Gillespie & Associates, Inc.	Appendix
	Page 1

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Cawley, Gillespie & Associates, Inc.	Appendix
	Page 2

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Cawley, Gillespie & Associates, Inc.	Appendix
	Page 3

“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

Cawley, Gillespie & Associates, Inc.	Appendix
	Page 4

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

Professional Qualifications of Robert D. Ravnaas, P.E.

Executive Vice President of Cawley, Gillespie & Associates

Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became Executive Vice President in 1999. He has completed numerous field studies, reserve evaluations and reservoir simulation, waterflood design and monitoring, unit equity determinations and producing rate studies. He has testified before the Texas Railroad Commission in unitization and field rules hearings. Prior to CG&A he worked as a Production Engineer for Amoco Production Company. Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas, No. 61304, and a member of the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.

Cawley, Gillespie & Associates, Inc.

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Organization And Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Organization And Summary Of Significant Accounting Policies [Abstract]

Organization And Summary Of Significant Accounting Policies

NOTE A: Organization and Summary of Significant Accounting Policies

Organization and Basis of Presentation

GeoResources, Inc. ("GeoResources" or the "Company") operates a single business segment involving the acquisition, development and production of, and exploration for, crude oil, natural gas and related products primarily in Texas, North Dakota, Louisiana, Oklahoma, and Montana.

Summary of Significant Accounting Policies

Basis of Consolidation

The consolidated financial statements include the accounts of the Company and its majority-owned subsidiaries. The equity method is used to account for investments in affiliates in which the Company does not have majority ownership, but has the ability to exert significant influence. Intercompany accounts and transactions have been eliminated. The Company's investments in oil and gas limited partnerships for which it serves as general partner and has significant influence on are accounted for under the equity method. The Company consolidated our non-controlling interest in Trigon LLC ("Trigon") until September 2011, at which time the non-controlling interest was deconsolidated due to a distribution of all of Trigon's assets to its owners. A non-controlling interest represents the minority members' proportionate share of membership equity. All other subsidiaries are wholly owned. Certain reclassifications were made to the year ended December 31, 2009 amounts on the Company's Consolidated Statement of Income to conform to the current presentation of severance tax expense and interest and other income. The Company also reclassified certain amounts from joint interest and other receivable to oil and gas receivables. Such reclassifications had no impact on net income, working capital, or total equity previously reported.

The parent, GeoResources, Inc., has no assets or operations independent of its subsidiaries. The long-term debt of GeoResources, Inc. under its Credit Agreement discussed in Note C is fully and unconditionally guaranteed on a joint and several basis by all of its significant subsidiaries, all of which are wholly owned. Subject to a pledge of all the significant subsidiary assets pursuant to the Credit Agreement, there are no restrictions on the ability of GeoResources, Inc. to obtain funds from its significant subsidiaries. The significant subsidiaries of GeoResources, Inc. are: AROC (Texas) Inc., a Texas corporation; Catena Oil & Gas, LLC; a Texas limited liability company; G3 Energy, LLC, a Colorado limited liability company; G3 Operating, LLC, a Colorado limited liability company; Southern Bay Energy, LLC, a Texas limited liability company; Southern Bay Louisiana, L.L.C., a Texas limited liability company; and Southern Bay Operating, L.L.C., a Texas limited liability company.

Cash and Cash Equivalents

Cash and cash equivalents consists of all demand deposits and funds invested in highly liquid investments with an original maturity of three months or less.

The Company maintains its cash and cash equivalents in various financial institutions. The combined account balances at several institutions typically exceed Federal Deposit Insurance Corporation ("FDIC") insurance coverage and, as a result, there is a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage. Management believes that this risk is not significant.

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for oil and gas operations whereby the costs to acquire mineral investments in oil and gas properties, to drill successful exploratory wells, to drill and equip development wells, and to install production facilities are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. The Company's acquisition and development costs of proved oil and gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers. Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of production basis.

The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Proved oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flow expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to its estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. Fair value of impaired assets may be estimated using comparable market data or based on expected future cash flows using discount rates commensurate with the risks involved and using prices and costs consistent with those used for internal decision making or a combination of the two. Long-lived assets committed by the Company for disposal are accounted for at the lower of cost or fair value, less cost to sell. The Company recognized impairments of $6.0 million, $3.4 million and $2.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. Impairments recognized in 2011, 2010 and 2009 were on proved properties and are classified as impairments on the Company's income statement.

Office and Other Property

Acquisitions and improvements of office and other property are capitalized at cost; maintenance and repairs are expensed as incurred. Depreciation of equipment is calculated using the straight-line method over the assets estimated useful lives of 5-7 years. Leasehold improvements are amortized over the remaining term of the lease. When assets are sold, retired, or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and a gain or loss is recognized.

Net Income Per Common Share

Basic earnings per share is computed by dividing net income attributable to common shares by the basic weighted-average shares of common stock outstanding during the period. The calculation of diluted earnings per share is similar to basic, except the denominator includes the effect of dilutive common stock equivalents. Dilutive common stock equivalents consist of unvested restricted stock unit awards and outstanding stock options. The number of potential common shares outstanding relating to stock options and restricted stock units is computed using the treasury stock method. Net income per share computations to reconcile basic and diluted net income for 2011, 2010 and 2009 consist of the following (in thousands, except per share data):

	Year ended December 31,
	2011		2010		2009
Numerator:
Net income available for common stock	$	31,338	$	23,331	$	9,775
Denominator:
Basic weighted average shares		25,172		19,721		16,532
Effect of dilutive securities - share-based compensation		427		421		27
Diluted weighted average shares		25,599		20,142		16,559
Earning per share
Basic	$	1.24	$	1.18	$	0.59
Diluted	$	1.22	$	1.16	$	0.59

Options to purchase 5,830, 52,086 and 412,540 shares were excluded from the diluted earnings per share calculation in 2011, 2010 and 2009, respectively, because the effect would have been anti-dilutive. For the year ended December 31, 2011, 37 restricted stock units were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Stock-Based Compensation

The Company recognizes in the financial statements all share-based payments made to employees, including grants of employee stock options and restricted stock units, based on their fair values at the time of award.

Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, accounts receivable and payable and revenue royalties payable are estimated to approximate their fair values due to the short maturities of these instruments. The Company's long-term debt obligations will bear interest at floating market rates, so carrying amounts and fair values will be approximately equal. Derivative financial instruments are carried at fair value; for further information see Note F: Derivative Financial Instruments.

Income Taxes

The provision for income taxes is based on taxes payable or refundable for the current year and deferred taxes on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, which result from temporary differences between the amount of taxable income and pretax financial income. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. Tax positions are evaluated for recognition and measurement, with deferred tax balances recorded at their anticipated settlement amounts. A valuation allowance is provided for deferred tax assets not expected to be realized.

Other Comprehensive Income (Loss)

The Company reports comprehensive income on its Consolidated Statement of Equity and Comprehensive Income (Loss). Other comprehensive income (loss) at December 31, 2011, 2010 and 2009 consists of unrealized gains (losses) of derivatives qualifying as cash flow hedges in accordance with current accounting standards.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Oil and gas reserve estimates, which are the basis for units-of-production depreciation, depletion, and amortization are inherently imprecise and are expected to change as future information becomes available.

Derivative Instruments and Hedging Activities

The Company enters into derivative contracts, primarily options, collars and swaps, to hedge future crude oil and natural gas production, as well as interest rates, in order to mitigate the risk of downward movements of oil and gas market prices and the upward movement of interest rates. All derivatives are recognized on the balance sheet and measured at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the realized gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the realized gain or loss on the derivative is deferred in other comprehensive income to the extent the hedge is effective for cash flow hedges. To qualify for hedge accounting, the derivative must qualify either as a fair value, cash flow or foreign currency hedge.

The hedging relationship between the hedged instruments and hedged transactions must be highly effective in achieving the offset of changes in fair values and cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis to qualify for hedge accounting. The Company measures hedge effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedging instrument becomes ineffective. The Company assesses hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes in intrinsic value only. As a result, changes in the entire value of option contracts are deferred in accumulated other comprehensive income until the hedged transaction affects earnings to the extent such contracts are effective. Gains and losses that were previously deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered.

Gains and losses resulting from hedge settlements of commodity hedges are included in oil and gas revenues and are included in realized prices in the period that the related production is delivered. Gains and losses on hedging instruments that represent hedge ineffectiveness are included in the caption hedge effectiveness on the consolidated statement of income in the period in which they occur. Gains and losses on derivative instruments that do not qualify for hedge accounting are included in the caption gain/loss on derivative contracts. The resulting cash flows are reported as cash flows from operating activities.

Asset Retirement Obligations

The Company recognizes the present value of the estimated future abandonment costs of its oil and gas properties in both assets and liabilities. If a reasonable estimate of the fair value can be made, the Company will record a liability for legal obligations associated with the future retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of the assets. The fair value of a liability for an asset retirement obligation is recognized in the period in which the liability is incurred. The fair value is measured using expected future cash outflows (estimated using current prices that are escalated by an assumed inflation rate) discounted at the Company's credit-adjusted risk-free interest rate. The liability is then accreted each period until it is settled or the asset is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded. The initial fair value of the asset retirement obligation is capitalized and subsequently depreciated or amortized as part of the carrying amount of the related asset.

The Company has recorded asset retirement obligations related to its oil and gas properties. There are no assets legally restricted for the purpose of settling asset retirement obligations.

Revenue Recognition

Oil and gas revenues represent income from production and delivery of oil and gas, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has been transferred and if collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. A liability is recorded only if the Company's takes of gas volumes exceed its share of estimated recoverable reserves from the respective well or field. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. Volumetric production is monitored to minimize imbalances, and such imbalances were not significant at December 31, 2011, 2010 or 2009.

Accounts Receivable

The Company sells crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company's accounts receivable are due from either purchasers of crude oil and natural gas or participants in crude oil and natural gas wells for which subsidiaries of the Company serve as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Crude oil and natural gas sales are generally unsecured.

As is common industry practice, the Company generally does not require collateral or other security as a condition of sale, rather relying on credit approval, balance limitation and monitoring procedures to control the credit use on accounts receivable. The allowance for doubtful accounts is an estimate of the losses in the Company's accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance.

The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2011 and 2010, the Company has an allowance for doubtful accounts of $609,000 and $370,000, respectively.

Drilling Advances

The Company, in its execution of its drilling program has other working interest partners. The Company, through its joint operating agreements, requires its working interest partners to pay a drilling advance for their share of the estimated drilling and completion costs. Until such advances are applied to actual drilling and completion invoices, the Company carries the advance as a current liability on its balance sheet. The Company expects such advances to be applied against the partners' joint interest billings for its share of drilling operations within 60 days from when the advance is paid.

Industry Segment and Geographic Information

The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company's operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.

Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2011-11, Balance Sheet (Topic 210) – Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity's financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting under current accounting literature or are subject to master netting arrangements irrespective of whether they are offset. The objective of the new disclosures is to facilitate comparison between entities that prepare financial statements on the basis of U.S. GAAP and entities that prepare financial statements under IFRS. The disclosure requirements will be effective for periods beginning on or after January 1, 2013 and must be applied retrospectively to all periods presented on the balance sheet. The Company will adopt the requirements of ASU No. 2011-11 on January 1, 2013, which may require additional footnote disclosures for derivative instruments and these requirements are not expected to have a material effect on the Company's financial position, results of operations or cash flows.

In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This update will require the presentation of the components of net income and other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In addition, companies are also required to present reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The update is effective for fiscal years and interim periods beginning after December 15, 2011. The Company will adopt the new disclosure requirements for comprehensive income beginning January 1, 2012.

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This ASU issued authoritative guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. The ASU expands existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place, and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. Entities will also be required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

Other amendments include clarifying the highest and best use and valuation premise for nonfinancial assets, premiums and discounts in fair value measurement, and fair value of an instrument classified in a reporting entity's shareholders' equity.

ASU 2011-04 is effective during interim and annual periods beginning after December 15, 2011, and therefore will become effective for the Company on January 1, 2012 for the quarter ending March 31, 2012. Other than the disclosure requirements, ASU 2011-04 is not expected to have a significant impact on the Company's consolidated financial statements.

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Consolidated Statements Of Cash Flows (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Consolidated Statements Of Cash Flows [Abstract]
Cost recoveries	$ 4,555	$ 40,230

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash	$ 39,144	$ 9,370
Accounts receivable
Oil and gas revenues	26,485	17,627
Joint interest billings and other, less allowance for doubtful accounts of $609 and $370, respectively	21,328	16,021
Affiliated partnerships	371	969
Notes receivable	545	120
Derivative financial instruments	4,037	4,282
Income taxes receivable	7,753	222
Prepaid expenses and other	3,681	2,645
Total current assets	103,344	51,256
Oil and gas properties, successful efforts method:
Proved properties	428,871	341,582
Unproved properties	44,613	32,403
Office and other equipment	1,675	1,140
Land	146	146
Total property and equipment	475,305	375,271
Less accumulated depreciation, depletion and amortization	(96,753)	(72,380)
Net property and equipment	378,552	302,891
Equity in oil and gas limited partnerships	2,240	2,272
Derivative financial instruments	868	851
Deferred financing costs and other	2,687	2,420
Total Assets	487,691	359,690
Current liabilities:
Accounts payable	25,483	14,616
Accounts payable to affiliated partnerships	3,597	2,931
Revenue and royalties payable	17,043	12,450
Drilling advances	12,965	4,203
Accrued expenses	5,073	1,331
Derivative financial instruments	2,890	7,433
Total current liabilities	67,051	42,964
Long-term debt		87,000
Deferred income taxes	44,389	19,289
Asset retirement obligations	7,940	7,052
Derivative financial instruments		1,650
Stockholders' equity:
Common stock, par value $0.01 per share; authorized 100,000,000 shares; issued and outstanding: 25,595,930 shares in 2011 and 19,726,566 in 2010	256	197
Additional paid-in capital	281,515	148,172
Accumulated other comprehensive income (loss)	1,069	(3,000)
Retained earnings	85,471	54,133
Total GeoResources, Inc. stockholders' equity	368,311	199,502
Noncontrolling interest		2,233
Total equity	368,311	201,735
Total Liabilities and Equity	$ 487,691	$ 359,690

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Consolidated Statements Of Equity And Comprehensive Income (Loss) (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements Of Equity And Comprehensive Income (Loss) [Abstract]
Common stock, issuance costs	$ 6,889		$ 2,136
Tax on change in fair market value of hedged positions	1,705	1,488	4,357
Hedging gains realized in income, taxes	$ 760	$ 1,048	$ 2,388

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Supplemental Financial Information For Oil And Gas Producing Activities

12 Months Ended

Dec. 31, 2011

Supplemental Financial Information For Oil And Gas Producing Activities [Abstract]

Supplemental Financial Information For Oil And Gas Producing Activities

NOTE N: Supplemental Financial Information for Oil and Gas Producing Activities (Unaudited)

1. Costs Incurred Related to Oil and Gas Activities

The Company's oil and gas activities for 2011, 2010 and 2009 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Acquisition cost:
Proved	$	10,120	$	18,739	$	59,686
Unproved	$	20,795	$	22,880	$	6,908
Exploration cost:
Exploratory drilling	$	12,053	$	5,225		83
Geological and geophysical	$	898	$	630		1,323
Development cost	$	67,977	$	35,349	$	23,623

Unproved acquisition costs for 2011 and 2010 is net of cost recoveries of $4.6 million and $40.2 million received from the sale of interests in undeveloped properties from third parties. During 2011, 2010 and 2009, additions to oil and gas properties of $838,000, $314,000 and $262,000 were recorded for estimated costs of future abandonment related to new wells drilled or acquired.

Net capitalized costs related to the Company's oil and gas producing activities were as follows:

	December 31,
	2011			2010
	(in thousands)
Proved properties	$	428,871		$	341,582
Unproved properties		44,613			32,403
		473,484			373,985
Accumulated depreciation, depletion and amortization		(96,045	)		(71,805	)
Net capitalized cost	$	377,439		$	302,180

The amounts included in unproved properties are projects for which the Company intends to commence exploration or evaluation projects in the near future. The Company will begin to amortize these costs when proved reserves are established or an impairment is determined.

The net changes in capitalized exploratory wells costs were as follows:

	Year ended December 31
	2011			2010
Balance, beginning of year	$	5,006		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		12,053			5,006
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(17,056	)		—
Capitalized exploratory well costs charged to expense		(3	)		—
Balance, end of year	$	—		$	5,006

As of December 31, 2011 the Company did not have any costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling and no capitalized exploratory well costs pending the determination of proved reserves.

2. Estimated Quantities of Proved Oil and Gas Reserves

For all years presented, the estimate of proved reserves and related valuations were based on reports prepared by the Company's independent petroleum engineers. The reports were prepared by Cawley, Gillespie & Associates, Inc. Proved reserve estimates included herein conform to the definitions prescribed by the U.S. Securities and Exchange Commission. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions existing as of the end of each respective year. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.

Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are located in the United States, for the years ended December 31, 2011, 2010 and 2009:

Oil and Gas Reserve Quantities:

	Oil (MBbl)			Gas (MMcf)
Proved reserve quantities, December 31, 2008		8,793			34,796
Purchase of minerals-in-place		586			25,728
Sales of minerals-in-place		(59	)		(80	)
Extensions and discoveries		972			9,227
Production		(851	)		(4,944	)
Revisions of quantity estimates		1,978			(9,291	)
Proved reserve quantities, December 31, 2009		11,419			55,436
Purchase of minerals-in-place		531			1,388
Extensions and discoveries		1,553			1,390
Production		(1,060	)		(4,789	)
Revisions of quantity estimates		1,950			4,129
Proved reserve quantities, December 31, 2010		14,393			57,554
Purchase of minerals-in-place		134			2,195
Extensions and discoveries		5,265			4,687
Production		(1,222	)		(4,209	)
Revisions of quantity estimates		1,123			(2,922	)
Proved reserve quantities, December 31, 2011		19,693			57,305
Proved developed reserve quantities:
December 31, 2009		9,221			38,138
December 31, 2010		11,231			39,097
December 31, 2011		13,906			38,514
Proved undeveloped reserve quantities:
December 31, 2009		2,198			17,298
December 31, 2010		3,162			18,457
December 31, 2011		5,787			18,791

Notable changes in proved reserves for the year ended December 31, 2011, 2010 and 2009 included:

In 2009, the revision increase in estimated oil quantities related to price increases was 2,204,000 Bbls, which was partially offset by reductions of 1,030,000 Bbls due to a change in pricing method as prescribed by the SEC. Other increases of 804,000 Bbls accounted for the remainder of the total positive revision of 1,978,000 Bbls. The revision decrease in estimated gas quantities related to price increases was 960,000 Mcf, offset by a decrease of 10,572,000 Mcf attributable to the change in pricing methods prescribed by the SEC. Other increases in gas reserves of 321,000 Mcf accounted for the remainder of the negative revision of 9,291,000 Mcf. The change in pricing method prescribed by the SEC is from the use of a year-end price to the use of a 12-month average price.

In 2010, the revision increase in estimated oil quantities related to price increases was approximately 1,024,000 Bbls as SEC prescribed oil prices increased from the December 31, 2009 price of $61.18 per Bbl to the December 31, 2010 price of $79.43 per Bbl. Net positive performance revisions of approximately 926,000 Bbls accounted for the remainder of the total positive revision of 1,950,000 Bbls. The revision increase in estimated gas quantities related to the price increases was approximately 6,032,000 Mcf as SEC prescribed gas prices increased from December 31, 2009 of $3.83 per Mmbtu to the December 31, 2010 price of $4.37 per Mmbtu. Net negative performance revisions of approximately 1,903,000 Mcf accounted for the remainder of the total positive revisions of 4,129,000 Mcf. In 2010, the majority of the 1,553,000 Bbls and 1,390,000 Mcf of proved reserves added through extensions and discoveries are a direct result of our successful Bakken drilling activities in North Dakota and eastern Montana.

In 2011, the revision increase in estimated oil quantities related to price increases was approximately 523,000 Bbls as SEC prescribed oil prices increased from the December 31, 2010 price of $79.43 per Bbl to the December 31, 2011 price of $96.16 per Bbl. Net positive performance revisions of approximately 600,000 Bbls accounted for the remainder of the total positive revision of 1,123,000 Bbls. The revision decrease in estimated gas quantities related to price decreases was 46,000 Mcf as SEC prescribed gas prices decreased from December 31, 2010 of $4.37 per Mmbtu to the December 31, 2011 price of $4.11 per Mmbtu. Net negative performance revisions of 2,876,000 Mcf accounted for the remainder of the total negative revisions of 2,922,000 Mcf. In 2011, the majority of the 5,265,000 Bbls and 4,687,000 Mcf of proved reserves added through extensions and discoveries are a direct result of our successful drilling activities in the Bakken trend of North Dakota and Eagle Ford trend of Texas.

3. Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with FASB ASC topic Extractive Activities – Oil and Gas. Future cash inflows as of December 31, 2011, 2010, and 2009 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2011, 2010 and 2009, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions.

Future income tax expense is calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of the properties involved. Future income tax expense gives effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily result in an estimate of the fair value of the Company's oil and gas properties.

Presented below is the standardized measure of discounted future net cash flows as of December 31, 2011, 2010 and 2009.

Standardized Measure of Estimated Future Net Cash Flows

	December 31,
	2011		2010		2009
	(in thousands)
Future cash inflows	$	2,036,390	$	1,266,679	$	789,647
Future production costs		657,929		455,685		316,815
Future development costs		197,247		90,814		64,560
Future income taxes		353,452		188,887		83,182
Future net cash flows		827,762		531,293		325,090
10% annual discount for estimated timing of cash flows		400,936		254,278		150,990
Standardized measure of discounted future cash flows	$	426,826	$	277,015	$	174,100

Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end. If the effects of hedging transaction were included in the computation, undiscounted future cash flows would have increased by $2.0 million in 2011, decreased by $4.0 million in 2010, and decreased by $4.3 million in 2009.

The principal sources of changes in the standardized measure of discounted future net cash flows for 2011, 2010 and 2009 are as follows:

Changes in Standardized Measure

	Year Ended December 31,
	2011			2010			2009 *
	(in thousands, except product prices)
Standardized measure, beginning of period	$	277,015		$	174,100		$	120,619
Changes in prices, net of production cost		116,768			111,342			47,246
Extensions, discoveries and enhanced production		134,530			36,111			20,989
Revision of quantity estimates		29,494			42,413			14,876
Development costs incurred, previously estimated		4,620			5,613			7,045
Change in estimated future development costs		(7,231	)		(7,972	)		(17,629	)
Purchases of minerals-in-place		12,747			16,161			36,002
Sales of minerals-in-place		—			—			(786	)
Sale of oil and gas produced, net of production costs		(97,142	)		(66,341	)		(53,860	)
Accretion of discount		41,730			23,268			16,663
Change in estimated future income taxes		(86,789	)		(57,792	)		(13,495	)
Changes in timing of estimated cash flows and other		1,084			112			(3,570	)
	$	426,826		$	277,015		$	174,100
Prices, used in standardized measure:
Oil (per barrel)	$	96.19		$	79.43		$	61.18
Gas (per Mcf)	$	4.11		$	4.37		$	3.83

* In 2009, standardized measure was reduced by $90.0 million due to the use of a 12-month average price as prescribed by the new reserve rules versus an end of the year price. Had the Company not changed its pricing method to comply with the SEC's new rules the standardized measure at December 31, 2009 would have been $264.1 million.

Equity in Partnership Reserves

1. Costs Incurred Related to Oil and Gas Activities

The following two unaudited tables set forth the Company's share of costs incurred in the affiliated partnerships during the years ended December 31, 2011, 2010, and 2009. During 2009, the Company's interest in one of the partnerships, SBE Partners, increased significantly from 2% to 30%. For further information see note L above.

Costs incurred in acquisition, development and exploration:

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Acquisition cost	$	31	$	250	$	346
Development cost	$	321	$	304	$	771
Exploration cost	$	7	$	7	$	—

Capitalized cost of oil and gas properties:

	December 31,
	2011			2010
	(in thousands)
Proved properties	$	4,019		$	3,997
Unproved properties		—			—
		4,019			3,997
Accumulated depreciation, depletion and amortization		(1,042	)		(811	)
Net capitalized cost	$	2,977		$	3,186

2. Estimated Quantities of Proved Oil and Gas Reserves and Discounted Future Net Cash Flows

The reserve information presented above does not include the Company's share of reserves held by two limited partnerships which are accounted for under the equity method of accounting. The following table presents the Company's estimated share of the oil and gas reserves held by both limited partnerships as of December 31, 2011, 2010 and 2009.

	Year Ended December 31,
	2011				2010				2009
	Oil (Mbbls)		Gas (Mmcf)		Oil (Mbbls)		Gas (Mmcf)		Oil (Mbbls)		Gas (Mmcf)
Oil and gas volumes:
Proved developed		48		6,196		45		6,993		45		7,821
Proved undeveloped		6		784		7		861		10		613
Total		54		6,980		52		7,854		55		8,434

Presented below is a summary of the changes in estimated proved reserves of the Company's equity investments, all of which are located in the United States, for the year ended December 31, 2011:

Oil and Gas Reserve Quantities:

	Oil (MBbl)			Gas (MMcf)
Proved reserve quantities, January 1, 2010		55			8,434
Production		(5	)		(1,007	)
Revision of quantity estimates		2			427
Proved reserve quantities, December 31, 2010		52			7,854
Sales of minerals-in-place		—			(1	)
Production		(5	)		(761	)
Revisions of quantity estimates		7			(112	)
Proved reserve quantities, December 31, 2011		54			6,980
Proved developed reserve quantities:
December 31, 2010		45			6,993
December 31, 2011		48			6,196
Proved undeveloped reserve quantities:
December 31, 2010		7			861
December 31, 2011		6			784

Presented below is the Company's share of standardized measure of discounted future net cash flows as of December 31, 2011 for its equity investments:

Standardized Measure of Estimated Future Net Cash Flows:

	For the year ended December 31,
	2011		2010
	(in thousands)
Future cash inflows	$	32,418	$	33,916
Future production costs		11,540		11,485
Future development costs		2,522		2,506
Future income taxes		6,744		6,512
Future net cash flows		11,612		13,413
10% annual discount for estimated timing of cash flows		4,571		5,345
Standardized measure of discounted future cash flows	$	7,041	$	8,068

The principal sources of change in the Company's share of standardized measure of discounted future net cash flows for the Company's equity investments for 2011 are as follows (in thousands except for product prices):

Changes in Standardized Measure:

	For the year ended December 31,
	2011			2010
	(in thousands)
Standardized measure, beginning of period	$	8,068		$	7,335
Changes in prices, net of production cost		2,288			3,525
Revision of quantity estimates		31			454
Development costs incurred, previously estimated		(14	)		824
Change in estimated future development costs		44			(867	)
Sales of minerals-in-place		(2	)		—
Sale of oil and gas produced, net of production costs		(2,164	)		(3,000	)
Accretion of discount		1,073			910
Change in estimated future income taxes		(167	)		(643	)
Changes in timing of estimated cash flows and other		(2,116	)		(470	)
	$	7,041		$	8,068
Current prices at year-end, used in standardized measure:
Oil (per barrel)	$	96.16		$	79.43
Gas (per Mcf)	$	4.11		$	4.37

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net income	$ 31,251	$ 23,331	$ 9,775
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	27,659	24,686	22,409
Proved property impairments	6,043	3,440	2,795
Gain on sale of property and equipment	(865)	(953)	(1,355)
Provision for doubtful accounts	300		312
Accretion of asset retirement obligations	444	405	368
Settlement of asset retirement obligations	(213)
Unrealized (gain) loss on derivative contracts		(325)	(238)
Amortization of loss on cancelled hedges			482
Hedge ineffectiveness (gain) loss	569	(891)	137
Partnership income	(1,759)	(2,240)	(4,318)
Partnership distributions	1,791	3,500	2,406
Deferred income taxes	22,635	3,062	4,655
Non-cash compensation	2,115	1,071	1,424
Excess tax benefit from share-based compensation	(2,531)
Changes in assets and liabilities:
Increase in accounts receivable	(19,036)	(499)	(7,960)
Decrease (increase) in prepaid expense and other	(1,472)	707	(1,116)
Increase (decrease) in revenues and royalties payable	4,801	(1,478)	2,227
Increase (decrease) in accounts payable and accrued expense	24,607	5,715	(7,959)
Net cash provided by operating activities	96,339	59,531	24,044
Cash flows from investing activities:
Proceeds from sale of property and equipment	442	1,018	1,991
Additions to property and equipment, net of cost recoveries of $4,555 in 2011, $40,230 in 2010, and none in 2009	(111,294)	(70,126)	(89,396)
Purchase of Trigon Energy Partners, LLC		(11,848)
Net cash used in investing activities	(110,852)	(80,956)	(87,405)
Cash flows from financing activities:
Proceeds from stock options exercised	6,270	135
Issuance of common stock	122,486		33,054
Excess tax benefit from share-based compensation	2,531
Issuance of long-term debt		38,000	64,000
Reduction of long-term debt	(87,000)	(20,000)	(35,000)
Net cash provided by (used in) financing activities	44,287	18,135	62,054
Net increase (decrease) in cash and cash equivalents	29,774	(3,290)	(1,307)
Cash and cash equivalents at beginning of period	9,370	12,660	13,967
Cash and cash equivalents at end of period	39,144	9,370	12,660
Supplementary information:
Interest paid	909	3,958	4,064
Income taxes paid	2,502	8,629	664
Stock issue for services		$ 2	$ 59

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	25,595,930	19,726,566
Common stock, shares outstanding	25,595,930	19,726,566
Joint interest billings and other, allowance for doubtful accounts	$ 609	$ 370

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Concentration Of Credit Risk

12 Months Ended

Dec. 31, 2011

Concentration Of Credit Risk [Abstract]

Concentration Of Credit Risk

NOTE I: Concentration of Credit Risk

Credit risk represents the accounting loss which the Company would record if its customers failed to perform pursuant to the contractual terms. The Company's largest customers are large companies. In addition, the Company transacts business with independent oil producers, crude oil trading companies and a variety of other entities. The Company's credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables.

In 2011, three purchasers each accounted for 12% of the Company's consolidated oil and gas revenue. In 2010, two purchasers each accounted for 12% of the Company's consolidated oil and gas revenues and one purchaser accounted for 11%. In 2009, one purchaser accounted for 17% of the Company's consolidated oil and gas revenues, two purchasers accounted for 15% each, and one more accounted for 11%. No other single purchaser accounted for 10% or more of the Company's consolidated oil and gas revenues in 2011, 2010, or 2009. There are adequate alternate purchasers of production such that the loss of one or more of the above purchasers would not have a material adverse effect on the Company's results of operations or cash flows.

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Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Mar. 09, 2012	Jun. 30, 2011
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2011
Entity Registrant Name	GEORESOURCES INC
Entity Central Index Key	0000041023
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Well-known Seasoned Issuer	No
Entity Common Stock, Shares Outstanding		25,625,792
Entity Public Float			$ 451,046,891

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Commitments And Contingencies

NOTE J: Commitments and Contingencies

Commitments

The Company is obligated under non-cancelable operating leases for its office facilities as follow (in thousands):

2012	$	409
2013		417
2014		426
2015		267
2016		21
Thereafter		—
	$	1,540

Total rental expense under operating leases for 2011, 2010 and 2009 was $400,000, $369,000, and $374,000, respectively.

The Company is also obligated under non-cancelable contracts for drilling rigs and related equipment for its drilling operations as follows (in thousands):

2012	$	17,517
2013		10,071
2014		10,071
2015		2,937
2016		—
Thereafter		—
	$	40,596

The Company has committed to one long-term natural gas sales contract in its Williams County North Dakota project area in the Bakken trend. Under the terms of this contract the Company has committed substantially all of the natural gas production for the life of its leases to one purchaser. In return for the life of lease commitment, the purchaser has committed to building a gas gathering system across the Company's project area. The sales price under this contract is based on a posted market rate.

Contingencies

No significant legal proceedings are pending which are expected to have a material adverse effect on the Company. The Company is unaware of any potential claims or lawsuits involving environmental, operating or corporate matters which are expected to have a material adverse effect on the Company's financial position or results of operations.

XML

Consolidated Statements Of Income (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenue:
Oil and gas revenues	$ 130,608	$ 99,913	$ 71,618
Partnership management fees	507	550	1,007
Property operating income	3,562	1,865	1,710
Gain on sale of property and equipment	865	953	1,355
Partnership income	1,759	2,240	4,318
Interest and other	447	1,496	990
Total revenue	137,748	107,017	80,998
Expenses:
Lease operating expense	24,806	20,944	18,763
Production taxes	8,028	6,589	4,193
Re-engineering and workovers	2,628	1,962	2,807
Exploration expense	989	849	1,406
Impairment of oil and gas properties	6,043	3,440	2,795
General and administrative expense	13,875	9,474	8,500
Depreciation, depletion and amortization	27,659	24,686	22,409
Hedge ineffectiveness	569	(891)	137
(Gain) / loss on derivative contracts		(2)	162
Interest	1,909	4,712	4,984
Total expense	86,506	71,763	66,156
Income before income taxes	51,242	35,254	14,842
Income tax expense (benefit):
Current	(2,644)	8,861	412
Deferred	22,635	3,062	4,655
Income Tax Expense (Benefit), Total	19,991	11,923	5,067
Net income	31,251	23,331	9,775
Less: Net loss attributable to noncontrolling interest	(87)
Net income attributable to GeoResources, Inc.	$ 31,338	$ 23,331	$ 9,775
Net income per share (basic)	$ 1.24	$ 1.18	$ 0.59
Net income per share (diluted)	$ 1.22	$ 1.16	$ 0.59
Weighted average shares outstanding:
Basic	25,171,896	19,720,652	16,532,003
Diluted	25,598,770	20,142,297	16,559,431

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Stock Options, Performance Awards And Stock Warrants

12 Months Ended

Dec. 31, 2011

Stock Options, Performance Awards And Stock Warrants [Abstract]

Stock Options, Performance Awards And Stock Warrants

NOTE D: Stock Options, Performance Awards and Stock Warrants

In March 2007, the shareholders of the Company approved the GeoResources, Inc, Amended and Restated 2004 Employees' Stock Incentive Plan (the "Plan"), which authorizes the issuance of options and other stock-based incentives to officers, employees, directors and consultants of the Company to acquire up to 2,000,000 shares of the Company's common stock at prices which may not be less than the stock's fair market value on the date of grant. The options can be designated as either incentive options or nonqualified options. In June 2011, the shareholders of the Company approved an amendment to the Plan which increased the number of authorized issuances of stock-based incentives to 3,250,000 shares. The amendment also allows the issuance of performance units, including restricted stock units.

Stock options generally vest ratably over approximately a four-year service period from grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.

On February 3, 2009, and March 26, 2009, the Company granted options under the Plan to officers and other employees to purchase 300,000 and 225,000 shares of common stock, respectively. Also on February 3, 2009, the Company granted options to outside directors to purchase 200,000 shares of common stock. On October 20, 2009, the Company granted options to certain employees to purchase 25,000 shares of common stock. The closing market prices of the Company's common stock on the date of the February, March and October 2009 grants were $7.62, $7.16, and $12.70, respectively.

On April 7, 2010, the Company granted options under the Plan to an outside director to purchase 40,000 shares of common stock. Additionally, on June 1, 2010, the Company granted options under the Plan to purchase 35,000 shares of common stock to key employees. The closing market prices of the Company's common stock on the dates of the April and June 2010 grants were $17.27 and $13.69, respectively.

On June 7, 2011, the Company granted options under the Plan to an outside director to purchase 40,000 shares of common stock. The closing market price of the Company's common stock on June 7, 2011 was $21.57. All of the foregoing options, if not exercised, will expire 10 years from the date of grant. The following is a summary of the terms of the 2011 grant by exercise price:

	2011 Stock Option Grants
Vesting Date	$23.00		$27.00
Director
June 6, 2012		5,000		5,000
June 6, 2013		5,000		5,000
June 6, 2014		5,000		5,000
June 6, 2015		5,000		5,000
		20,000		20,000

A summary of the Company's stock option activity for the years ended December 31, 2011, 2010 and 2009

is as follows:

	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (year)		Weighted Average Fair Value		Aggregate Intrinsic Value
Outstanding, January 1, 2009		790,000		$	9.39		8.81	$	2.29	$	158,750
Granted		750,000		$	9.42			$	4.45
Exercised		—		$	—				—
Forfeited		—		$	—				—
Outstanding, December 31, 2009		1,540,000		$	9.40		8.30	$	3.34	$	6,827,275
Granted		75,000		$	17.66			$	8.52
Exercised		(33,150	)	$	9.19				4.29	$	205,189
Forfeited		(87,500	)	$	11.50				4.64
Outstanding, December 31, 2010		1,494,350		$	9.70		7.34	$	3.49	$	18,701,164
Granted		40,000		$	25.00			$	11.50
Exercised		(702,864	)	$	9.27				2.93	$	12,206,204
Forfeited		(50,000	)	$	9.40				3.22
Outstanding, December 31, 2011		781,486		$	10.88		6.93	$	4.42	$	14,402,787
Exercisable at year-end
2011		387,736
2010		742,850
2009		382,500

The weighted average grant date fair value of the options that vested during the year 2011 was $3.49 per option. The average intrinsic value for the 387,736 options exercisable as of December 31, 2011 is $7.7 million. These options have a weighted average exercise price of $9.56 and a weighted average remaining life of 6.29 years.

Unvested options at year-end:

	Number of Awards		Weigthed Average Exercise Price		Weighted Average Fair Value
December 31, 2009		1,157,500	$	9.77	$	3.69
December 31, 2010		751,500	$	10.28	$	4.22
December 31, 2011		393,750	$	12.18	$	5.75

The Company recognized compensation expense based upon the fair value of the options at the date of grant determined by the Black-Scholes option pricing model. Compensation expense is recognized over the respective vesting periods on a straight-line basis. For the years ended December 31, 2011, 2010, and 2009, the Company recognized compensation expense of $969,000, $1.1 million, and $1.4 million respectively, related to these options. As of December 31, 2011, the future pre-tax expense of non-vested stock options is $1.5 million ($913,000 after taxes) to be recognized through the second quarter of 2014.

During 2011, 2010 and 2009 the weighted-average fair value of the options granted during the year was $11.50, $8.52, and $4.45 per share respectively, using the following assumptions:

	2011			2010			2009
Risk-free annual interest rate		1.58	%		2.03	%		1.27	%
Dividend yield		None			None			None
Volatility		67	%		75	%		86	%
Expected life of option		5 Years			4 Years			4 Years

In measuring compensation associated with these options, an annual pre-vesting forfeiture rate of 1% was used. The expected volatility at the grant date is based on the historical volatility of the Company's common stock and the risk-free interest rate is determined based on the U.S. treasury yield curve rate with a maturity similar to that of the expected term of the stock option.

In addition to the stock option grants discussed above, during 2011, the Company granted certain officers, employees and directors 197,050 restricted stock units. Each restricted stock unit represents a contingent right to receive one share of the Company's common stock upon vesting. Compensation expense, determined by multiplying the number of restricted stock units granted by the closing market price of the Company's stock on the grant date, is recognized over the respective vesting periods on a straight-line basis. For the year ended December 31, 2011, compensation expense related to restricted stock units was $1.1 million. The Company has an assumed forfeiture rate of 1% on restricted stock units issued. As of December 31, 2011, the future unamortized pre-tax compensation expense associated with unvested restricted stock units totaled approximately $4.3 million ($2.7 million after taxes) to be recognized through November 2014. The weighted average vesting period related to unvested restricted stock units at December 31, 2011 was approximately 2.38 years. A summary of the Company's restricted stock unit activity for the year ended December 31, 2011 is as follows:

	Shares		Fair Values  (1)
Outstanding, December 31, 2010		—		—
Granted		197,050	$	27.72
Vested		—		—
Forfeited		—		—
Outstanding, December 31, 2011		197,050	$	27.72

(1) Represents the weighted average grant date market value

On June 5, 2008, the Company issued 613,336 warrants to purchase common stock to non-affiliated accredited investors pursuant to exemptions from registration under federal and state securities laws. The warrants have a term of five years ending June 5, 2013, with an exercise price $32.43 per share.

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Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-Term Debt [Abstract]

Long-Term Debt

NOTE C: Long-term Debt

On July 13, 2009, the Company entered into a Second Amended and Restated Credit Agreement ("Second Amended Credit Agreement"). The Second Amended Credit Agreement increased the credit facility from $200 million to $250 million and extended the term of the Credit Agreement to October 16, 2012. The initial borrowing base of the facility was $135 million, which was increased to $145 million in November 2009 and was $145 million as of December 31, 2010.

On November 9, 2011, the Company entered into a Third Amended and Restated Credit Agreement (the "Credit Agreement"), which increased its senior secured revolving credit facility from $250 million to $450 million and extended the term of the Credit Agreement to November 9, 2016. The initial borrowing base of the credit facility was $180 million, subject to review and redetermination on May 1 and November 1 of each year. The Credit Agreement provides for interest rates at (a) LIBOR plus 1.75% to 2.75% or (b) the prime lending rate plus 0.75% to 1.75%, depending upon the amount borrowed and also requires the payment of commitment fees to the lender in respect of the unutilized commitments. The commitment rate is 0.375% per annum for a borrowing base of less than 50% and .500% for a borrowing base greater than or equal to 50%. The Company is also required to pay customary letter of credit fees. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company's assets. The Company incurred costs of approximately $1.5 million to complete the amendment and it is amortizing these costs over the remaining life of the Credit Agreement; the amortization is included in interest expense. The banks participating in the credit facility include: Wells Fargo Bank, Comerica Bank, Compass Bank, U.S. Bank, The Frost National Bank, BMO Harris Financing, Inc., Royal Bank of Canada, and SunTrust Bank.

The 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 lease back transactions, pay dividends and distributions or repurchase its capital stock, engage in mergers or consolidations, make significant changes to management, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates. In addition, the Credit Agreement requires the maintenance of certain financial ratios, contains customary affirmative covenants, and provides for customary events of default. The Company was in compliance with all covenants at December 31, 2011.

The Company had no principal outstanding under its credit facility at December 31, 2011. The principal outstanding under the Credit Agreement was $87 million at December 31, 2010. The remaining borrowing capacity under the Credit Agreement was $180 million as of December 31, 2012. The maturity date for amounts outstanding under the Credit Agreement is November 9, 2016.

Interest expense for 2011, 2010, and 2009 includes amortization of deferred financing costs of $981,000, $1.1 million, and $785,000 respectively. During 2010, the Company capitalized interest of $234,000. The Company did not capitalize any interest in 2011 or 2009.

In October 2007, the Company entered into an interest rate swap agreement with one of the banks participating in its credit facility, providing a fixed rate of 4.79% on a notional $50 million through October 16, 2010. During 2008, the Company broke the swap up into two pieces, a $40 million swap and a $10 million swap each with a fixed annual interest rate of 4.29%. The $40 million swap was accounted for as a cash flow hedge while the $10 million swap was accounted for as a trading security. These swaps expired in October 2010. During 2010, the Company recognized a net gain of $2,000 on the $10 million swap due to the cash settlement losses approximating the mark-to-market gain. The Company recognized a net loss of $162,000 on the $10 million swap during the year ended December 31, 2009.

For the years ended December 31, 2010 and December 31, 2009, the Company recognized realized cash settlement losses of $1.3 million and $1.6 million, respectively, related to the $40 million swap.

The weighted average interest rate on borrowings outstanding, excluding amortization of deferred financing costs and loans fees but including interest rate swaps, during 2011, 2010 and 2009 was 2.7%, 4.8%, and 5.4%.

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Subsequent Events

12 Months Ended

Dec. 31, 2011

Subsequent Events [Abstract]

Subsequent Events

NOTE O: Subsequent Events

In January, 2012, the Company awarded 167,520 in restricted stock units to directors and officers, including subsidiary officers. Each restricted stock unit represents a contingent right to receive one share of the Company's common stock upon vesting. Vesting occurs over a three year period for 149,000 of these units and over one year for the remaining 18,520 units.

On January 20, 2012, the Company closed on an acquisition of unproved leasehold interests in McKenzie County, North Dakota. The Company acquired an average net interest of 10.2% in approximately 3,700 net acres. The Company's net acquisition cost was $12.7 million and was funded with working capital and borrowings on its credit facility.

On February 29, 2012, the Company closed an acquisition of producing wells and acreage in the Austin Chalk trend of east Texas in the Brookeland field area. The Company acquired varying working interests in 96 producing and productive wells across approximately 170,000 net acres. The Company's net acquisition cost was $40.4 million, subject to closing adjustments for normal operating activity and other customary purchase price adjustments. The acquisition was funded with borrowings on its credit facility.

As a result of the two acquisitions and other capital expenditures, the outstanding balance on the Company's credit facility was $60 million as of March 9, 2012.

On January 30, 2012, the Company entered into one additional natural gas swap and two additional crude oil swaps. The natural gas swap has a term of February 2012 to December 2013. The swap has a quantity of 20,000 Mmbtus per month at a fixed price of $2.925 per Mmbtu during 2012 and $3.560 per Mmbtu during 2013. The first of the two crude oil swaps has a term of January 2012 to December 2013. The swap has a quantity of 5,000 Bbls per month at a fixed price of $99.55 per barrel during 2012 and $97.60 during 2013. The second of the two crude oil swaps has a term of January 2012 to December 2013. The swap has a quantity of 5,000 Bbls per month at a fixed price of $107.30 per barrel during 2012 and $100.70 during 2013.

On February 24, 2012, the Company entered into an additional crude oil swap. The swap has a term of March 2012 to December 2013. The swap has a quantity of 10,000 Bbls per month at a fixed price of $108.45 per Mmbtu during 2012 and $105.55 during 2013.

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Related Party Transactions

12 Months Ended

Dec. 31, 2011

Related Party Transactions [Abstract]

Related Party Transactions

NOTE K: Related Party Transactions

Accounts receivable at December 31, 2011 and 2010 include $258,000 and $753,000, respectively, due from SBE Partners LP ("SBE Partners"). Accounts receivable at December 31, 2011 and 2010, also includes $113,000 and $219,000, respectively, due from OKLA Energy Partners LP ("OKLA Energy"). 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 December 31, 2011 and 2010, includes $2.8 million and $2.3 million, respectively, due to SBE Partners for oil and gas revenues and severance tax refunds collected on its behalf. Accounts payable at December 31, 2011 and 2010, also includes $817,000 and $654,000, respectively due to OKLA Energy for oil and gas revenues collected on its behalf.

The Company earned partnership management fees during the years ended December 31, 2011, 2010, and 2009 of $507,000, $550,000 and $1.0 million, 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. These revenues are paid monthly to each partnership, which in turn reimburses the Company for the partnership's share of expenditures.

In May 2009, the Company, through its subsidiary, Catena, entered into a Purchase and Sale Agreement with an affiliated limited partnership, SBE Partners. Catena purchased the properties for $49.3 million. As the General Partner of SBE Partners, Catena received a distribution from the partnership as a result of the sale of $987,000. The net purchase price for the properties was $48.4 million. This acquisition is discussed in Note B above.

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Fair Value Disclosures

12 Months Ended

Dec. 31, 2011

Fair Value Disclosures [Abstract]

Fair Value Disclosures

NOTE G: Fair Value Disclosures

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

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

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

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

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

A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of the input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers between Level 1 and Level 2 of the fair value hierarchy during the years ended December 31, 2011 or 2010. Further, there were no transfers in and/or out of Level 3 of the fair value hierarchy during the years ended December 31, 2011 and 2010.

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

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

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

The tables below present information about the Company's assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

Derivative Assets and Liabilities—December 31, 2011

(in thousands)

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2011
Current portion of derivative financial instrument asset (1)		—	$	4,037		—	$	4,037
Long-term portion of derivative financial instrument asset (1)		—		868		—		868
Current portion of derivative financial instrument liability (1)		—		2,890		—		2,890
Long-term portion of derivative financial instrument liability (1)		—		—		—		—

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

Derivative Assets and Liabilities—December 31, 2010

(in thousands)

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2010
Current portion of derivative financial instrument asset (1)		—	$	4,282			—	$	4,282
Long-term portion of derivative financial instrument asset (1)		—		851			—		851
Current portion of derivative financial instrument liability (1)		—		(7,433	)		—		(7,433	)
Long-term portion of derivative financial instrument liability (1)		—		(1,650	)		—		(1,650	)

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

At December 31, 2011 and 2010, the Company did not have any assets or liabilities measured at fair value on a recurring basis that meet the definition of Level 1 or Level 3.

Nonrecurring Fair Value Measurements—The Company applies the provision of the fair value measurement standard to its nonrecurring, non-financial measurements. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The following non-financial assets and liabilities measured at fair value on a nonrecurring basis.

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

The Company recorded asset impairments of $6.0 million, $3.4 million and $2.8 million on proved properties during the years ended December 31, 2011, 2010 and 2009, respectively. All of the 2011, 2010 and 2009 impairments on proved properties were included in impairment expense. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of future natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

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

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

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

NOTE E: Income Taxes

The following table shows the components of the Company's income tax provision for 2011, 2010 and 2009:

	Year ended December 31,
	2011			2010		2009
	(in thousands)
Current:
Federal	$	(2,337	)	$	8,111	$	283
State		(307	)		750		129
Total current		(2,644	)		8,861		412
Deferred
Federal		21,323			2,570		4,318
State		1,312			492		337
Total deferred		22,635			3,062		4,655
Total	$	19,991		$	11,923	$	5,067

The following is a reconciliation of taxes computed at the corporate federal statutory income tax rate of 35% to the reported income tax provision for the years ended December 31, 2011, 2010 and 2009:

	2011			2010			2009
	(in thousands)
Income before income taxes	$	51,242		$	35,254		$	14,842
Tax computed at federal statutory rate		17,965		$	12,339		$	5,195
Statutory depletion in excess of tax basis		—			(1,060	)		—
Domestic production activities deduction		—			(513	)		—
State income taxes, net of federal benefit		1,752			876			521
Expense not deductible for tax purposes and other		274			281			(649	)
Total income tax expense	$	19,991		$	11,923		$	5,067
Effective tax rate		39.01	%		33.82	%		34.14	%

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

The following table shows the components of the Company's net deferred tax liability at December 31, 2011, 2010 and 2009:

	2011			2010			2009
	(in thousands)
Deferred tax asset or (liability)
Current:	$	—		$	—		$	—
Noncurrent:
Oil and gas properties		(49,598	)		(24,536	)		(20,178	)
Other property and equipment		434			482			473
Equity in limited partnerships		(704	)		(465	)		(685	)
Asset retirement obligations		3,024			2,652			1,703
Stock-based compensation		865			875			518
Commodity hedges and other		1,590			1,703			2,391
Net deferred tax liability	$	(44,389	)	$	(19,289	)	$	(15,778	)

As of December 31, 2011, the Company had statutory depletion available for carryforward of approximately $3.6 million, which may be used to offset future taxable income. The amount that may be used in any year is subject to an annual limit of $1.1 million arising from a change in control in 2007.

Uncertain Tax Positions

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

At December 31, 2011, the Company did not have any uncertain tax positions that would require recognition. The Company's uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.

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

The Company's continuing practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statement of Income. As of December 31, 2011, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statutes of limitations prior to December 31, 2012.

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2011

Derivative Financial Instruments [Abstract]

Derivative Financial Instruments

NOTE F: Derivative Financial Instruments

The Company enters into various crude oil and natural gas hedging contracts, primarily costless collars and swaps, in an effort to manage its exposure to product price volatility. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has designated its commodity derivative contracts as cash flow hedges designed to achieve more predictable cash flows, as well as to reduce its exposure to price volatility. While the use of derivative instruments limits the downside risk of adverse price movements, they also limit future revenues from favorable price movements. The Company does not enter into commodity derivative instruments for speculative or trading purposes.

At December 31, 2011, accumulated other comprehensive income (loss) included unrecognized gains of $1.1 million, net of taxes of $658,000, representing the inception to date change in mark-to-market value of the effective portion of the Company's open commodity contracts, designated as cash flow hedges, as of the balance sheet date. At December 31, 2010, accumulated other comprehensive income (loss) included unrecognized losses of $3.0 million, net of taxes of $1.8 million. For the year ended December 31, 2011, the Company recognized a realized net cash settlement loss on commodity derivatives of $2.0 million. For the years ended December 31, 2010 and 2009, the Company recognized realized net cash settlement gains on commodity derivatives of $4.1 million and $7.4 million, respectively. Based on the estimated fair market value of the Company's derivative contracts designated as hedges at December 31, 2011, the Company expects to reclassify net gains of $1.1 million into earnings from accumulated other comprehensive income (loss) during the next twelve months; however, actual cash settlement gains and losses recognized may differ materially.

On October 17, 2008, the Company paid $3.0 million to cancel its 2009 natural gas swaps that were previously accounted for as cash flow hedges. At the time of cancelation, accumulated other comprehensive (loss) contained $482,000 of acquisition to date change in mark-to-market of the effective portion of these commodity derivative contracts. These accumulated losses were amortized during 2009 and reduce net income by $482,000.

During the first quarter of 2011, the Company entered into one additional natural gas swap contract, three crude oil collars, and two crude oil swaps. The natural gas swap has a term of January 2012 to March 2013 with a volume amount of 75,000 MMBTUs per month. The swap has a fixed price of $4.85 per MMBTU. The first crude oil collar has a term of February 2011 through December 2011 with a volume amount of 5,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $106.08 per Bbl on this contract. The second crude oil collar has a term of January 2012 through December 2012 and provides for 10,000 Bbls per month. The floor price is $85.00 per Bbl and the ceiling price is $110.00 per Bbl. The third crude oil collar has a term of March 2011 through December 2011 and provides for 5,000 Bbls per month. The floor price is $100.00 per Bbl and the ceiling price is $114.00 per Bbl. The first crude oil swap has a term of January 2012 through December 2012 and provides for 10,000 Bbls per month. The swap has a fixed price of $103.95 per Bbl. The second crude oil swap has a term of January 2013 through December 2013 and provides for 10,000 Bbls per month. The swap has a fixed price of $101.85 per Bbl.

During the second quarter of 2011, the Company entered into a crude oil swap. The crude oil swap has a term of May 2011 through December 2011 and provides for 6,250 Bbls per month. The swap has a fixed price of $110.00 per Bbl.

During the fourth quarter of 2011, the Company entered into a crude oil swap. The crude oil swap has a term of January 2012 through December 2012 and provides for 5,000 Bbls per month. The swap has a fixed price of $105.00 per Bbl.

At December 31, 2011, the Company had hedged its exposure to the variability in future cash flows from forecasted oil and gas production volumes as follows:

	Total Remaining Volume		Floor Price		Ceiling / Swap Price
Crude Oil Contracts (Bbls):
Swap contracts:
2012		120,000			$	87.22
2012		120,000			$	86.85
2012		120,000			$	103.95
2012		60,000			$	105.00
2013		120,000			$	101.85
Costless collar contracts
2012		120,000	$	85.00	$	110.00
Natural Gas Contracts (Mmbtu)
Swap contracts:
2012		150,000			$	6.450
2012		450,000			$	6.415
2012		900,000			$	4.850
2013		225,000			$	4.850

The fair market value of the Company's gas hedge contracts in place at December 31, 2011 and 2010, were assets of $3.7 million and $5.1 million, respectively, of which $3.4 million and $4.3 million were classified as current assets, respectively. The fair market value of the Company's oil hedge contracts in place at December 31, 2011 and 2010 were net liabilities of $1.7 million and $9.1 million, respectively. At December 31, 2011 the net fair market value liability was made up of a current asset of $583,000 and a long-term asset of $647,000 offset by a current liability of $2.9 million. $7.4 million of the December 31, 2010 liability was classified as current liability and $1.7 million was classified as a long-term liability. For the year ended December 31, 2011, the Company recognized, in oil and gas revenues, realized cash settlement loss on commodity derivatives of $2.0 million. For the years ended December 31, 2010 and 2009, the Company recognized, in oil and gas revenues, realized cash settlement gains on commodity derivatives of $4.1 million and $7.4 million, respectively. During 2010, the Company recognized gains due to hedge ineffectiveness of $891,000. Due to hedge ineffectiveness on hedge contracts during 2011 and 2009 the Company recognized a loss of $569,000 and $137,000, respectively.

To reduce the impact of changes in interest rates on the Company's variable rate term loan, the Company entered into a two-year interest rate swap contract on $50 million of the debt, designed to protect against interest rate increases. During 2008, the Company extended the term of this interest rate swap through October, 2010, and broke the swap up into two pieces, a $40 million swap and a $10 million swap. The Company accounted for the $40 million swap as a cash flow hedge while the $10 million swap was accounted for as a trading security. The interest rate swaps are further discussed in Note C above.

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

Derivatives designated as ASC 815 hedges:	Asset Derivatives					Liability Derivatives
	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
		Dec. 31, 2011		Dec. 31, 2010			Dec. 31, 2011			Dec. 31, 2010
Commodity contracts	Current derivative financial instruments asset	$	4,037	$	4,282	Current derivative financial instruments liability	$	(2,890	)	$	(7,433	)
Commodity contracts	Long-term derivative financial instruments asset		868		851	Long-term derivative financial instruments liability		—			(1,650	)
		$	4,905	$	5,133		$	(2,890	)	$	(9,083	)

Derivative contracts – The following tables summarize the effects of commodity and interest rate derivative instruments on the consolidated statements of income for the years ended December 31, 2011, 2010 and 2009 (in thousands):

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Recognized in OCI on Derivatives  (Effective Portion)
	2011		2010		2009
Commodity contracts	$	4,538	$	3,512	$	(10,834	)
Interest rate swap contracts		—		—		(646	)
	$	4,538	$	3,512	$	(11,480	)

Derivatives designated as ASC 815 hedges:	Amount of Gain or (Loss) Reclassified from OCI into Income  (Effective Portion)									Location of Gain or (Loss) Reclassified from OCI into Income (Effective Portion)
	2011			2010			2009
Commodity contracts	$	(1,996	)	$	4,078		$	7,434		Oil and gas revenues
Interest rate swap contracts		—			(1,294	)		(1,598	)	Interest expense
	$	(1,996	)	$	2,784		$	5,836

Derivatives in ASC 815 cash flow hedging relationships:	Location of Gain or (Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain or (Loss) Recognized in Income on Derivative  (Ineffective Portion)
		2011			2010		2009
Commodity contracts	Hedge ineffectiveness	$	(569	)	$	891	$	(137	)

Derivative not designated as ASC 815 hedges:	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain or (Loss) Recognized in Income on Derivative
		2011		2010			2009
Realized cash settlements on interest rate swap	Gain (loss) on derivative contracts		—	$	(323	)	$	(399	)
Unrealized gain (loss) on interest rate swap	Gain (loss) on derivative contracts		—		325			237
			—	$	2		$	(162	)

Contingent features in derivative instruments – None of the Company's derivative instruments contain credit-risk-related contingent features. Counterparties to the Company's derivative contracts are high credit quality financial institutions that are lenders under the Company's credit facility. The Company uses credit facility participants to hedge with, since these institutions are secured equally with the holders of the Company's debt, which eliminates the potential need to post collateral when the Company is in a large derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

NOTE H: 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, and removal of equipment and facilities from leased acreage and land restoration, in accordance with applicable local, state and federal laws. The Company determines its obligation by calculating the present value of estimated cash flows related to plugging and abandonment obligations. The changes to the Asset Retirement Obligations ("ARO") for oil and gas properties and related equipment during the years ended December 31, 2011 and 2010 are as follows (in thousands):

	Year ended December 31
	2011			2010
Balance, beginning of year	$	7,052		$	6,110
Additional liabilities incurred		838			314
Settlement of liabilities		(213	)		—
Accretion Expense		444			405
Disposals of properties		(557	)		(105	)
Revisions of estimates		376			328
Balance, end of year	$	7,940		$	7,052

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Supplemental Financial Quarterly Results

12 Months Ended

Dec. 31, 2011

Supplemental Financial Quarterly Results [Abstract]

Supplemental Financial Quarterly Results

NOTE M: Supplemental Financial Quarterly Results (Unaudited):

The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree with year-to-date basic and diluted earnings (loss) per share amounts as a result of each period's computation being based on the weighted average number of common shares outstanding during that period.

	Three Months Ended
	March 31, 2011			June 30, 2011			September 30, 2011			December 31, 2011
	(in thousands, except per share data)
Year ended December 31, 2011
Oil and gas revenues	$	26,614		$	29,292		$	35,229		$	39,473
Other revenues (1)		2,025			1,588			1,873			1,654
Operating expenses (2)		(12,846	)		(14,826	)		(17,882	)		(18,556	)
Operating income		15,793			16,054			19,220			22,571
Other income (expense), net (3)		(5,388	)		(1,853	)		(3,523	)		(11,632	)
Income tax (expense) benefit		(4,092	)		(5,422	)		(6,282	)		(4,195	)
Net income	$	6,313		$	8,779		$	9,415		$	6,744
Basic net income per share	$	0.26		$	0.35		$	0.37		$	0.26
Diluted net income per share	$	0.26		$	0.34		$	0.36		$	0.26

	Three Months Ended
	March 31, 2010			June 30, 2010			September 30, 2010			December 31, 2010
	(in thousands, except per share data)
Year ended December 31, 2010
Oil and gas revenues	$	24,729		$	24,343		$	25,612		$	25,229
Other revenues (1)		1,549			1,021			1,294			1,744
Operating expenses (2)		(13,875	)		(13,089	)		(13,914	)		(14,152	)
Operating income		12,403			12,275			12,992			12,821
Other income (expense), net (4)		(2,552	)		(4,947	)		(2,735	)		(5,003	)
Income tax (expense) benefit		(3,777	)		(2,885	)		(2,621	)		(2,640	)
Net income (loss)	$	6,074		$	4,443		$	7,636		$	5,178
Basic net income per share	$	0.31		$	0.23		$	0.39		$	0.25
Diluted net income per share	$	0.30		$	0.22		$	0.38		$	0.26

(1) Partnership management fees, property operating income, gain (loss) on sale of property and partnership income.

(2) Lease operating expense, production taxes, re-engineering and workover, exploration, and depreciation depletion and amortization.

(3) Other income (expense), net for the fourth quarter of 2011 included impairment expenses of $6.0 million

(4) Other income (expense), net for the second and fourth quarters of 2010 included impairment expenses of $2.7 million and $697,000, respectively.

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Consolidated Statements Of Equity And Comprehensive Income (Loss) (USD $) In Thousands, except Share data, unless otherwise specified	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Non-Controlling Interest [Member]	Total
Balance at Dec. 31, 2008	$ 162	$ 112,523	$ 21,027	$ 7,283		$ 140,995
Balance, shares at Dec. 31, 2008	16,241,717
Issuance of common stock
For cash, net of issuance costs	35	33,019				33,054
For cash, net of issuance costs, shares	3,450,000
For services		59				59
For services, shares	13,645
Comprehensive income:
Net income			9,775			9,775
Change in fair market value of hedged positions, net of taxes				(7,123)		(7,123)
Hedging gains/ losses realized in income, net of taxes				(3,448)		(3,448)
Total comprehensive income / loss						(796)
Equity based compensation expense		1,365				1,365
Balance at Dec. 31, 2009	197	146,966	30,802	(3,288)		174,677
Balance, shares at Dec. 31, 2009	19,705,362
Exercise of employee stock options
Cash exercises		135				135
Cash exercises, shares	13,150
Cashless exercise		2				2
Cashless exercise, shares	8,054
Comprehensive income:
Net income			23,331			23,331
Change in fair market value of hedged positions, net of taxes				2,024		2,024
Hedging gains/ losses realized in income, net of taxes				(1,736)		(1,736)
Total comprehensive income / loss						23,619
Purchase of Trigon LLC					2,233	2,233
Equity based compensation expense		1,069				1,069
Balance at Dec. 31, 2010	197	148,172	54,133	(3,000)	2,233	201,735
Balance, shares at Dec. 31, 2010	19,726,566					19,726,566
Issuance of common stock
For cash, net of issuance costs	52	122,434				122,486
For cash, net of issuance costs, shares	5,175,000
Exercise of employee stock options
Cash exercises	7	6,263				6,270
Cash exercises, shares	694,364
Excess tax benefit from share-based compensation		2,531				2,531
Comprehensive income:
Net income			31,338		(87)	31,251
Change in fair market value of hedged positions, net of taxes				2,833		2,833
Hedging gains/ losses realized in income, net of taxes				1,236		1,236
Total comprehensive income / loss						35,320
Equity based compensation expense		2,115				2,115
Deconsolidation of noncontrolling interest					(2,146)	(2,146)
Balance at Dec. 31, 2011	$ 256	$ 281,515	$ 85,471	$ 1,069		$ 368,311
Balance, shares at Dec. 31, 2011	25,595,930					25,595,930

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Acquisitions And Divestitures

12 Months Ended

Dec. 31, 2011

Acquisitions And Divestitures [Abstract]

Acquisitions And Divestitures

NOTE B: Acquisitions and Divestitures

Bakken Acquisition

In May 2009, the Company closed an acquisition, through an existing joint venture partner, of producing wells and acreage in the Bakken shale trend of the Williston Basin. The Company acquired a 15% interest in approximately 60,000 net acres, and also acquired 15% of varying working interests in 59 producing and productive wells. The Company's net acquisition cost was approximately $10.4 million, subject to closing adjustments for normal operations activity and other customary purchase price adjustments. The Company funded the acquisition with borrowings under its credit facility.

Giddings Field Acquisition

On May 29, 2009, effective May 1, 2009, the Company, though its subsidiary, Catena Oil and Gas LLC ("Catena"), entered into a Purchase and Sale Agreement (the "Purchase Agreement") with an affiliated limited partnership, SBE Partners LP (the "Seller") for the acquisition (the "Acquisition") of certain oil and gas producing properties in Giddings field, Grimes and Montgomery counties, Texas (the "Interests"). Under the Purchase Agreement, the Interests were purchased for a cash purchase price of $48.7 million, net of closing adjustments for normal operations activity (the "Purchase Price"). In addition, the Company also acquired rights to certain post-closing severance tax refunds which amounted to $2.4 million. The Acquisition increased the Company's partnership sharing ratio from 2% to 30% in the Seller. Catena is the general partner of the Seller. The Seller distributed to Catena $978,000 of the gross proceeds from the sale. The Acquisition increased the Company's direct working interests in the Interests from a range of 6.5% to 7.8% to a range of 34% to 37%. The Company funded the Purchase Price with borrowings under its credit facility. The Purchase Agreement contains representations and warranties, covenants, and indemnifications that are customary for oil and gas producing property acquisitions.

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

Total revenue	$	93,536
Income before taxes		21,491
Net income		13,718
Net income per share:
Basic	$	0.83
Diluted	$	0.83
Weighted average shares:
Basic		16,532,003
Diluted		16,559,431

Other

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

On August 29, 2009, the Company, through its subsidiary, Catena, received a distribution of proved undeveloped property and unproved acreage in the Giddings field from SBE Partners LP ("SBE"), an affiliated partnership. The property was recorded at the estimated fair market value of $1.6 million, which exceeded its carrying value in the partnership. In conjunction with the distribution, SBE recorded a gain. The Company, which accounts for SBE as an equity method investment, included its share of the gain, $1.0 million, in the Company's partnership income during the third quarter 2009.

In October 2009, the Company initiated a leasing program in Williams County, North Dakota with the objective of establishing a significant operated position in the Bakken trend. In February 2010, the Company entered into agreements with two unaffiliated third parties to jointly develop the project. Cash proceeds to the Company totaled approximately $20 million and the Company retained a 47.5% working interest in the project area. The agreement also provided for up to $10 million ($4.75 million net) of additional joint leasing in a contractually specified area of mutual interest ("AMI"). As of December 31, 2011 the net acreage position of the Company in the project area totaled approximately 27,800 acres. For accounting purposes the Company uses the cost recovery method; under this method proceeds from joint owners have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties.

In July 2010, the Company closed an acquisition of producing oil and gas properties located near the Giddings field of central Texas. The purchase price was $16.6 million plus closing adjustments for normal operating activity. The acquisition included approximately 9,700 net acres and was funded through borrowings under the Company's credit facility. The amount of revenue from the acquisition included in the Company's Consolidated Statement of Income for years ended December 31, 2011 and 2010 was $6.7 million and $2.7 million, respectively. The amount of net income from the acquisition included in the Company's Consolidated Statements of Income for years ended December 31, 2011 and 2010 was $1.3 million and $700,000, respectively.

In September 2010, the Company entered into an agreement with an unaffiliated third party to jointly acquire and develop mineral leases in the Eagle Ford shale trend of Texas. As part of this agreement, the Company sold a 50% working interest in approximately 20,000 acres to a third party for $20 million. For accounting purposes, the Company uses the cost recovery method; under this method proceeds from joint owners are recorded in the balance sheet as a reduction of the carrying value of unproved properties. The purchaser also agreed to pay 100% of the drilling costs for the first six wells to be drilled in a contractually specified AMI. The agreement also provides for an additional $20 million for additional joint leasing within the AMI ($10 million net to each joint owner). Subsequent to the initial closing, the Company and the joint owner have continued to acquire leases within the AMI pursuant to the terms of the agreement.

In November 2010, the Company purchased an 86.67% membership interest in Trigon which held leases in the Eagle Ford shale trend of Texas and recorded a $2.2 million non-controlling interest in the Company's financial statements. The acquisition cost was approximately $11.8 million. In June 2011, the Company's membership interest decreased to 73.34% as a result of a $2.2 million capital contribution by the non-controlling interest holder. In September 2011, the Company deconsolidated the non-controlling interest in the financial statements due to a distribution of all of Trigon's assets to its owners.

In August 2011, the Company closed an acquisition of producing oil and gas properties located in the Austin Chalk trend of east Texas. The purchase price was $11 million plus closing adjustments for normal operating activity. The acquisition included approximately 3,700 net acres. The amount of revenue and net income from the acquisition included in the Company's Consolidated Statement of Income for year ended December 31, 2011, was $1.5 million and $400,000, respectively.

In December 2011, the Company sold approximately 1,800 net acres in Atacosa County, Texas for $4.6 million. For accounting purposes the Company used the cost recovery method; under this method proceeds have been recorded in the balance sheet as a reduction to the carrying value of the unproved properties.

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Equity Investments

12 Months Ended

Dec. 31, 2011

Equity Investments [Abstract]

Equity Investments

NOTE L: Equity Investments

The Company accounts for its investment in SBE Partners L.P. and OKLA Energy using the equity method of accounting. Under this accounting method the Company records its share of income and expenses. Contributions to the investment increase the Company's investment while distributions from the partnership decrease the Company's carrying value of the investment.

OKLA Energy, formed during 2008, holds direct working interests in producing oil and gas properties located throughout Oklahoma. The Company's 2% general partner interest reverts to 35.66% when the limited partner realizes a contractually specified rate of return. The Company recorded a loss in partnership income related to this investment for the years ended December 31, 2011, 2010 and 2009 of $22,600, $39,000 and $34,000, respectively.

SBE Partners, formed during 2007, holds direct working interests in producing oil and gas properties located in Giddings field in Texas. Previously, the Company held a 2% general partner interest which increased after reaching a cumulative payout. As result of the sale of certain properties and subsequent distribution of proceeds by the Partnership cumulative payout was achieved and the Company's general partner interest increased to 30%. For further information about the sale see Note B above. For the years ended December 31, 2011, 2010 and 2009 the Company recorded partnership income of $1.8 million, $2.3 million, and $4.4 million, respectively.

The Company's carrying value for its equity investment in OKLA Energy at December 31, 2011 and 2010 was $646,000 and $709,000, respectively. The Company's carrying value for its equity investment in SBE Partners at December 31, 2011 and 2010 was $1.6 million and $1.6 million, respectively. During 2011, the Company received cash distributions of $1.8 million and $41,000 from SBE Partners and OKLA Energy, respectively.

The following is a summary of selected financial information of SBE Partners, LP as of and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	2011		2010		2009
Summary of Partnership selected balance sheet information:
Current assets	$	7,677	$	5,831	$	11,933
Oil and gas properties, net	$	55,604	$	59,745	$	60,834
Total assets	$	66,876	$	68,993	$	73,686
Current liabilities	$	591	$	1,032	$	1,047
Total liabilities	$	1,519	$	2,161	$	1,876
Partner's capital	$	65,357	$	66,832	$	71,810
Summary of Partnership operations:
Revenues	$	17,957	$	19,181	$	52,429
Income from continuing operations	$	7,025	$	6,419	$	29,726
Net income	$	7,025	$	6,419	$	29,726
The Company's equity in partnership net income	$	1,782	$	2,279	$	4,352
The Company's capital balance in the partnership	$	1,597	$	1,565	$	2,686