Exhibit 99.3

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

 

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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.

 

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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.

 

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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

 

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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.

 

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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.

 

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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.

 

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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

 

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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.

 

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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.

 

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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

 

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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.

 

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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.

 

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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.

 

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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:

 

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		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

 

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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.

 

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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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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.

 

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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.

 

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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.

 

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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.

 

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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	)

 

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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.

 

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•

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

 

•

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

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

 

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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.

 

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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

 

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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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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.

 

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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.

 

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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

 

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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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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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

 

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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):

 

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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.

 

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