Exhibit 99.1

Item 8, Annual Report on Form 10-K for the year ended December 31, 2010 — Financial Statements and Supplementary Data

Index to Financial Statements

Report of Independent Registered Public Accounting Firm			2
Consolidated Balance Sheet at December 31, 2010 and December 31, 2009			3
Consolidated Statement of Operations for the Years Ended December 31, 2010, 2009 and 2008			4
Consolidated Statement of Changes in Stockholders’/Members’ Equity for the Years Ended December 31, 2010, 2009 and 2008			5
Consolidated Statement of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008			6
Notes to the Consolidated Financial Statements			7

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Oasis Petroleum Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in stockholders’/members’ equity, and cash flows present fairly, in all material respects, the financial position of Oasis Petroleum Inc. and its subsidiaries at December 31, 2010 and December 31, 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. 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 of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 10, 2011, except with respect to our opinion on the consolidated financial statements insofar as it relates to the guarantor financial information discussed in Note 19, as to which the date is July 15, 2011.

Oasis Petroleum Inc.
Consolidated Balance Sheet

		December 31,
		2010				2009
		(In thousands)
ASSETS
Current assets
Cash and cash equivalents		$	143,520			$	40,562
Accounts receivable — oil and gas revenues			25,909				9,142
Accounts receivable — joint interest partners			28,596				1,250
Inventory			1,323				1,258
Prepaid expenses			490				134
Advances to joint interest partners			3,595				4,605
Derivative instruments			—				219
Deferred income taxes			2,470				—
Total current assets			205,903				57,170
Property, plant and equipment
Oil and gas properties (successful efforts method)			580,968				243,350
Other property and equipment			1,970				866
Less: accumulated depreciation, depletion, amortization and impairment			(99,255	)			(62,643	)
Total property, plant and equipment, net			483,683				181,573
Deferred costs and other assets			2,266				810
Total assets		$	691,852			$	239,553
LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY
Current liabilities
Accounts payable		$	8,198			$	1,577
Advances from joint interest partners			3,101				589
Revenues payable and production taxes			6,180				2,563
Accrued liabilities			58,239				18,038
Accrued interest payable			2				144
Derivative instruments			6,543				1,087
Total current liabilities			82,263				23,998
Long-term debt			—				35,000
Asset retirement obligations			7,640				6,511
Derivative instruments			3,943				2,085
Deferred income taxes			45,432				—
Other liabilities			780				109
Total liabilities			140,058				67,703
Commitments and contingencies (Note 14)
Stockholders’/members’ equity
Capital contributions			—				235,000
Common stock, $0.01 par value; 300,000,000 shares authorized; 92,240,345 shares issued and outstanding			920				—
Additional paid-in-capital			643,719				—
Retained deficit/accumulated loss			(92,845	)			(63,150	)
Total stockholders’/members’ equity			551,794				171,850
Total liabilities and stockholders’/members’ equity		$	691,852			$	239,553

The accompanying notes are an integral part of these consolidated financial statements.

Oasis Petroleum Inc.
Consolidated Statement of Operations

		Year Ended December 31,
		2010				2009				2008
						(In thousands)
Oil and gas revenues		$	128,927			$	37,755			$	34,736
Expenses
Lease operating expenses			14,582				8,691				7,073
Production taxes			13,768				3,810				3,001
Depreciation, depletion and amortization			37,832				16,670				8,686
Exploration expenses			297				1,019				3,222
Rig termination			—				3,000				—
Impairment of oil and gas properties			11,967				6,233				47,117
Gain on sale of properties			—				(1,455	)			—
Stock-based compensation expenses			8,743				—				—
General and administrative expenses			19,745				9,342				5,452
Total expenses			106,934				47,310				74,551
Operating income (loss)			21,993				(9,555	)			(39,815	)
Other income (expense)
Change in unrealized gain (loss) on derivative instruments			(7,533	)			(7,043	)			14,769
Realized gain (loss) on derivative instruments			(120	)			2,296				(6,932	)
Interest expense			(1,357	)			(912	)			(2,404	)
Other income (expense)			284				5				(9	)
Total other income (expense)			(8,726	)			(5,654	)			5,424
Income (loss) before income taxes			13,267				(15,209	)			(34,391	)
Income tax expense			42,962				—				—
Net loss		$	(29,695	)		$	(15,209	)		$	(34,391	)
Loss per share:
Basic and diluted (Note 12)		$	(0.61	)		$	—			$	—
Weighted average shares outstanding:
Basic and diluted (Note 12)			48,395				—				—

The accompanying notes are an integral part of these consolidated financial statements.

Oasis Petroleum Inc.
Consolidated Statement of Changes in Stockholders’/Members’ Equity

		Common Stock																Retained				Total
		Number												Additional				Deficit/				Stockholders’/
		of								Capital				Paid-in-				Accumulated				Members’
		Shares				Amount				Contributions				Capital				Loss				Equity
		(In thousands)
Balance as of December 31, 2007			—			$	—			$	49,900			$	—			$	(13,550	)		$	36,350
Capital Contributions			—				—				80,500				—				—				80,500
Net loss			—				—				—				—				(34,391	)			(34,391	)
Balance as of December 31, 2008			—				—				130,400				—				(47,941	)			82,459
Capital Contributions			—				—				104,600				—				—				104,600
Net loss			—				—				—				—				(15,209	)			(15,209	)
Balance as of December 31, 2009			—				—				235,000				—				(63,150	)			171,850
Issuance of common stock			92,000				920				—				—				—				920
Proceeds from the sale of common stock			—				—				—				398,749				—				398,749
Reclassification of members’ contributions			—				—				(235,000	)			235,000				—				—
Stock-based compensation			240				—				—				9,970				—				9,970
Net loss			—				—				—				—				(29,695	)			(29,695	)
Balance as of December 31, 2010			92,240			$	920			$	—			$	643,719			$	(92,845	)		$	551,794

The accompanying notes are an integral part of these consolidated financial statements.

Oasis Petroleum Inc.
Consolidated Statement of Cash Flows

		December 31,
		2010				2009				2008
						(In thousands)
Cash Flows from Operating Activities:
Net loss		$	(29,695	)		$	(15,209	)		$	(34,391	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			37,832				16,670				8,686
Exploration expenses			—				—				1,280
Impairment of oil and gas properties			11,967				6,233				47,117
Gain on sale of properties			—				(1,455	)			—
Deferred income taxes			42,962				—				—
Derivative instruments			7,653				4,747				(7,837	)
Stock-based compensation expenses			9,970				—				—
Debt discount amortization and other			470				95				107
Working capital and other changes:
Change in accounts receivable			(44,450	)			(6,409	)			(988	)
Change in inventory			(498	)			(218	)			(1,191	)
Change in prepaid expenses			(356	)			(40	)			(6	)
Change in other assets			(164	)			(667	)			—
Change in accounts payable and accrued liabilities			13,917				2,440				968
Change in other liabilities			4				(39	)			21
Net cash provided by operating activities			49,612				6,148				13,766
Cash flows from investing activities:
Capital expenditures			(226,544	)			(47,396	)			(70,427	)
Acquisition of oil and gas properties			(86,393	)			(35,215	)			—
Derivative settlements			(120	)			2,296				(6,932	)
Advances to joint interest partners			1,010				(2,331	)			(1,430	)
Advances from joint interest partners			2,512				383				206
Proceeds from equipment and property sales			—				1,507				105
Net cash used in investing activities			(309,535	)			(80,756	)			(78,478	)
Cash flows from financing activities:
Proceeds from members’ contributions			—				104,600				80,500
Proceeds from sale of common stock			399,669				—				—
Proceeds from issuance of debt			72,000				22,000				6,750
Reduction in debt			(107,000	)			(13,000	)			(27,250	)
Debt issuance costs			(1,788	)			—				—
Net cash provided by financing activities			362,881				113,600				60,000
Increase (decrease) in cash and cash equivalents			102,958				38,992				(4,712	)
Cash and cash equivalents
Beginning of period			40,562				1,570				6,282
End of period		$	143,520			$	40,562			$	1,570
Supplemental cash flow Information:
Cash interest paid		$	1,002			$	674			$	2,485
Supplemental non-cash transactions:
Change in accrued capital expenditures		$	35,181			$	4,134			$	8,173
Asset retirement obligations			1,227				2,156				410

The accompanying notes are an integral part of these consolidated financial statements.

Oasis Petroleum Inc.
Notes to Consolidated Financial Statements

1. Organization and Operations of the Company

     Organization

     Oasis Petroleum Inc. (“Oasis” or the “Company”) was formed on February 25, 2010, pursuant to the laws of the State of Delaware to become a publicly traded entity and the parent company of Oasis Petroleum LLC, the Company’s predecessor. Oasis Petroleum LLC was formed as a Delaware limited liability company on February 26, 2007 by certain members of the Company’s senior management team and through investments made by Oasis Petroleum Management LLC (“OPM”) and certain private equity funds managed by EnCap Investments L.P. (“EnCap”). OPM, a Delaware limited liability company, was formed in February 2007 to allow Company employees to become indirect investors in the company. In April 2008, the Company formed Oasis Petroleum International LLC (“OPI”), a Delaware limited liability company, to conduct business development activities outside of the United States of America. OPI currently has no assets or business activities.

     A corporate reorganization occurred concurrently with the completion of the Company’s initial public offering (“IPO”) of its common stock on June 22, 2010. The Company sold 30,370,000 shares and OAS Holding Company LLC (“OAS Holdco”), the selling stockholder, sold 17,930,000 shares of the Company’s common stock, in each case, at $14.00 per share. After deducting estimated expenses and underwriting discounts and commissions of approximately $25.5 million, the Company received net proceeds of $399.7 million. The selling stockholder received aggregate net proceeds of approximately $236.0 million. The Company did not receive any proceeds from the sale of the shares by OAS Holdco. As a part of this corporate reorganization, the Company acquired all of the outstanding membership interests in Oasis Petroleum LLC, in exchange for shares of the Company’s common stock. The Company’s business continues to be conducted through Oasis Petroleum LLC, as a wholly owned subsidiary.

     Nature of Business

     The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Williston Basin. The Company’s assets, which consist of proved and unproved oil and natural gas properties, are located primarily in the Montana and North Dakota areas of the Williston Basin, and are owned by Oasis Petroleum North America LLC (“OPNA”), a wholly owned subsidiary of the Company, which was formed on May 17, 2007 as a Delaware limited liability company.

2. Summary of Significant Accounting Policies

     Basis of Presentation

     The accompanying consolidated financial statements of the Company include the accounts of Oasis and its wholly owned subsidiaries: Oasis Petroleum LLC, OPI and OPNA. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany transactions have been eliminated in consolidation.

     Use of Estimates

     Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

     As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.

     Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploitation and development activities, prevailing commodity prices, operating cost and other factors. These revisions may be material and could materially affect future depletion, depreciation and amortization expense, dismantlement and abandonment costs, and impairment expense.

     Cash and Cash Equivalents

     All short-term investments purchased with an original maturity of three months or less are considered cash equivalents. The Company’s short-term investments are composed of overnight bank transfers of funds from bank accounts to an offshore United States Dollar denominated interest bearing account. Invested funds and earned interest amounts are returned to the Company’s accounts the next business day. Cash equivalents are stated at cost, which approximates market value.

     Accounts Receivable

     Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. No allowance for doubtful accounts was recorded for the years ended December 31, 2010 and 2009.

     Inventory

     Equipment and materials consist primarily of tubular goods and well equipment to be used in future drilling or repair operations and are stated at the lower of cost or market with cost determined on an average cost method. Crude oil inventories are valued at the lower of average cost or market value. Inventory consists of the following:

		December 31,
		2010				2009
		(In thousands)
Equipment and materials		$	640			$	588
Crude oil inventory			683				670
		$	1,323			$	1,258

     Joint Interest Partner Advances

     The Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.

     Property, Plant and Equipment

          Proved Oil and Gas Properties

     Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are

capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.

     The provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

     Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized currently. No gain or loss for the sale of oil and natural gas properties was recorded for the years ended December 31, 2010 and 2008. In December 2009, the Company sold its interests in non-core oil and natural gas producing properties located in the Barnett shale in Texas for an aggregate $1.5 million in cash. The Company recognized a gain of $1.4 million from the sale of these divested properties.

     Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

     The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed in Note 3 — Fair Value Measurements. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2010. During the years ended December 31, 2009 and 2008, the Company recorded a $0.8 million and a $45.5 million non-cash impairment charge, respectively, on its proved oil and natural gas properties.

     Unproved Oil and Gas Properties

     Unproved properties consist of costs incurred to acquire unproved leases (“lease acquisition costs”). Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as Impairment of oil and gas properties in the Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

     The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and records impairment expense for any decline in value. As a result of expiring unproved property leases, the Company recorded non-cash impairment charges of $12.0 million, $5.4 million and $1.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

     For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

     Other Property and Equipment

     Furniture, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of three to five years for these types of assets. The cost of assets disposed of and the associated accumulated depletion, depreciation and amortization are removed from the Company’s Consolidated Balance Sheet with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statement of Operations.

     Exploration Expenses

     Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.

     Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for the near future or the necessary approvals are actively being sought.

     Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented:

		December 31,
		2010				2009				2008
						(In thousands)
Beginning of period		$	427			$	324			$	—
Exploratory well cost additions (pending determination of proved reserves)			39,708				72,972				38,666
Exploratory well cost reclassifications (successful determination of proved reserves)			(34,959	)			(72,869	)			(37,633	)
Exploratory well dry hole costs (unsuccessful in adding proved reserves)			—				—				(709	)
End of period		$	5,176			$	427			$	324

     As of December 31, 2010, the Company had no exploratory well costs that were capitalized for a period greater than one year.

     Deferred Costs

     The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in Deferred costs and other assets on the Company’s Consolidated Balance Sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.

     Asset Retirement Obligations

     In accordance with the FASB’s authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are depreciated using the unit-of-production method. The accretion expense is recorded as a component of Depreciation, depletion and amortization in the Company’s Consolidated Statement of Operations.

     The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 3 — Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

     Revenue Recognition

     Revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than 12 months) contracts at market based prices. The sales prices for oil and natural gas are adjusted for transportation and quality differentials. These differentials are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue differentials are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.

     Revenues Payable and Production Taxes

     The Company calculates and pays taxes and royalties on oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.

     Concentrations of Market Risk

     The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

     The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint venture partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. Trade receivables are generally not collateralized.

     Concentrations of Credit Risk

     The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.

     Risk Management

     The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2010, the Company utilized two-way and three-way collar options to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production (see Note 4 — Derivative Instruments).

     The Company records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Realized gains and losses from the settlement of commodity derivative instruments and unrealized gains and losses from valuation changes in the remaining unsettled commodity derivative instruments are reported in the Other Income (Expense) section of the Company’s Consolidated Statement of Operations. Unrealized gains are included in current and noncurrent assets and unrealized losses are included in current and noncurrent liabilities on the Consolidated Balance Sheet, respectively.

     Derivative financial instruments that hedge the price of oil are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has derivatives in place with three counterparties, all of which are lenders under the Company’s revolving credit facility. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.

     The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Company’s revolving credit facility (see Note 8— Long-Term Debt). As of December 31, 2010, the revolving credit facility had a provision limiting the total amount of production that may be hedged by the Company. As of December 31, 2010, the Company was in compliance with these limitations as its contractual commodity derivative volumes for 2011 and 2012 represent approximately 57% and 42%, respectively, of the Company’s average daily oil production for the three months ended December 31, 2010.

     Environmental Costs

     Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

     Restricted Stock Awards

     The Company has granted restricted stock awards to employees and directors under its 2010 Long-Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. As of December 31, 2010, the Company assumed no annual forfeiture rate because of the Company’s lack of turnover and lack of history for this type of award.

     Any excess tax benefit arising from our stock-based compensation plan is recognized as a credit to additional paid-in-capital when realized and is calculated as the amount by which the tax deduction received exceeds the deferred tax asset associated with the recorded stock-based compensation expense. As of December 31, 2010, none of the Company’s restricted stock awards had vested, and therefore, there was no required measurement of tax deduction compared to the deferred tax assets associated with the recorded stock-based compensation expense as of December 31, 2010.

     Income Taxes

     The Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

     The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

     The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not-threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company does not have uncertain tax positions outstanding and, as such, did not record a liability for the year ended December 31, 2010.

     Fair Value of Financial and Non-Financial Instruments

     The carrying value of cash and cash equivalents, accounts receivable, accounts payable and other payables approximate their respective fair market values due to their short-term maturities. The Company’s derivative instruments, long-term debt and asset retirement obligations are also recorded on the balance sheet at amounts which approximate fair market value. See Note 3 — Fair Value Measurements.

     Recent Accounting Pronouncements

     Goodwill. In December 2010, the FASB issued ASU 2010-28, “Intangibles — Goodwill and Other: When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts” (“ASU 2010-28”). ASU 2010-28 requires step two of the goodwill impairment test to be performed when the carrying value of a reporting unit is zero or negative, if it is more likely than not that a goodwill impairment exists. The requirements of this update are effective for fiscal years beginning after December 15, 2010. The Company does not expect the adoption of this new guidance to have an impact on its financial position, cash flows or results of operations.

     Business combinations. In December 2010, the FASB issued ASU 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (“ASU 2010-29”). ASU 2010-29 clarifies that when presenting comparative pro forma financial statements in conjunction with business combination disclosures, revenue and earnings of the combined entity should be presented as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period. In addition, the update requires a description of the nature and amount of material, nonrecurring pro forma adjustments included in pro forma revenue and earnings that are directly attributable to the business combination. This update is effective prospectively for business combinations that occur on or after the beginning of the first annual reporting period after December 15, 2010. As ASU 2010-29 relates to disclosure requirements, there will be no impact on the Company’s financial position, cash flows or results of operations.

     Financial receivables. On July 21, 2010, the FASB issued ASU 2010-20 “Receivables (Topic 310) — Disclosures about the Credit Quality of Financial Receivables and the Allowance for Credit Losses.” This new ASU requires disclosure of additional information to assist financial statement users to understand more clearly an entity’s

credit risk exposures to finance receivables and the related allowance for credit losses. This ASU is effective for all public companies for interim and annual reporting periods ending on or after December 15, 2010 with specific items, such as the allowance rollforward and modification disclosures, effective for periods beginning after December 15, 2010. The adoption of this new guidance did not have an impact on the Company’s financial position, cash flows or results of operations.

     Fair value. In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and added two new disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and nonrecurring fair value measurements, and is effective the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. The adoption of this new guidance did not have an impact on the Company’s financial position, cash flows or results of operations.

3. Fair Value Measurements

     The Company adopted the FASB’s authoritative guidance on fair value measurements effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. Beginning January 1, 2009, the Company also applied this guidance to non-financial assets and liabilities. The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.

     As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

     The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:

     Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

     Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

     Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

     As required, financial assets and liabilities are classified in their entirety based on the lowest level of 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 requires judgment and may affect the valuation of fair value assets and liabilities and

their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:

		At Fair Value as of December 31, 2010
		Level 1				Level 2				Level 3				Total
						(In thousands)
Assets (Liabilities):
Commodity Derivative Instruments (see Note 4)		$	—			$	—			$	(10,486	)		$	(10,486	)
Total Derivative Instruments		$	—			$	—			$	(10,486	)		$	(10,486	)

		At Fair Value as of December 31, 2009
		Level 1				Level 2				Level 3				Total
						(In thousands)
Assets (Liabilities):
Commodity Derivative Instruments (see Note 4)		$	—			$	—			$	(2,953	)		$	(2,953	)
Total Derivative Instruments		$	—			$	—			$	(2,953	)		$	(2,953	)

     The Level 3 instruments presented in the tables above consist of oil collars. The fair values of the Company’s oil collars are based upon mark-to-market valuation reports provided by its counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has a third-party reviewer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or third party reviewer. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculated the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a liability position is based on the Company’s current cost of prime based borrowings (prime rate and associated margin effect). Based on these calculations, the Company recorded a downward adjustment to the fair value of its derivative instruments in the amount of $0.3 million and $0.08 million for the years ended December 31, 2010 and 2009, respectively.

     The following table presents a reconciliation of the changes in fair value of the derivative instruments classified as Level 3 in the fair value hierarchy for the years presented.

		2010				2009				2008
						(In thousands)
Balance as of January 1		$	(2,953	)		$	4,090			$	(10,679	)
Total gains or (losses) (realized or unrealized):
Included in earnings			(7,653	)			(4,747	)			7,837
Included in other comprehensive income			—				—				—
Purchases, issuances and settlements			120				(2,296	)			6,932
Transfers in and out of level 3			—				—				—
Balance as of December 31		$	(10,486	)		$	(2,953	)		$	4,090
Change in unrealized gains (losses) included in earnings relating to derivatives still held at December 31		$	(7,533	)		$	(7,043	)		$	14,769

     At December 31, 2010, the Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The carrying amount of the Company’s ARO in the Consolidated Balance Sheet at December 31, 2010 is $7.6 million, which also approximates fair value as the Company determines the ARO by calculating the present value of estimated cash flows related to the liability based on the calculation of the estimated value (see Note 2 — Summary of Significant Accounting Policies).

     The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Therefore, the Company’s proved oil and natural gas properties are measured at fair value on a non-recurring basis. No

impairment charge on proved oil and natural gas properties was recorded for the year ended December 31, 2010. During the years ended December 31, 2009 and 2008, the Company recorded a $0.8 million and a $45.5 million non-cash impairment charge, respectively, on its proved oil and natural gas properties, as further discussed in Note 2 — Summary of Significant Accounting Policies. The 2009 impairment charge related to certain dry holes, which had a fair value of zero. The oil and natural gas properties related to the 2008 impairment charge had a fair value of $22.3 million and were evaluated for impairment primarily due to lower crude oil prices at December 31, 2008.

4. Derivative Instruments

     The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of December 31, 2010, the Company utilized two-way and three-way collar options to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price, unless the market price falls below the sold put, at which point the minimum price would be NYMEX-WTI plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract.

     All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at their fair value (see Note 3 — Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value, both realized and unrealized, are recognized in the Other Income (Expense) section of the Consolidated Statement of Operations as a gain or loss on mark-to-market derivative contracts. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.

     As of December 31, 2010, the Company had the following outstanding commodity derivative contracts, all of which settle monthly based on the West Texas Intermediate crude oil index price, and none of which were designated as hedges:

						Total
						Notional				Average
						Amount of				Sub-Floor				Average				Average				Fair Value Asset
Settlement Period		Derivative Instrument				Oil (Barrels)				Price				Floor Price				Ceiling Price				(Liability)
																						(In thousands)
2011		Two-Way Collars					1,264,944							$	76.56			$	93.89				(5,877	)
2011		Three Way Collars					167,000			$	60.00			$	80.00			$	94.98				(666	)
2012		Two-Way Collars					444,718							$	79.21			$	95.86				(2,049	)
2012		Three-Way Collars					685,500			$	62.44			$	82.44			$	104.32				(1,603	)
2013		Two-Way Collars					31,000							$	80.00			$	96.38				(122	)
2013		Three Way Collars					62,000			$	62.50			$	82.50			$	104.54				(169	)
																						$	(10,486	)

     The following table summarizes the location and fair value of all outstanding commodity derivative contracts recorded in the balance sheet for the periods presented:

Fair Value of Derivative Instrument Assets (Liabilities)
				Fair Value December 31,
Instrument Type		Balance Sheet Location		2010				2009
				(In thousands)
Crude oil collar		Derivative Instruments — current assets		$	—			$	219
Crude oil swap		Derivative Instruments — current liabilities			—				(26	)
Crude oil collar		Derivative Instruments — current liabilities			(6,543	)			(1,061	)
Crude oil collar		Derivative Instruments — non-current liabilities			(3,943	)			(2,085	)
		Total Derivative Instruments		$	(10,486	)		$	(2,953	)

     The following table summarizes the location and amounts of realized and unrealized gains and losses from the Company’s commodity derivative contracts for the periods presented:

						December 31,
		Income Statement Location				2010				2009				2008
										(In thousands)
Derivative Contracts		Change in Unrealized Gain (Loss) on Derivative Instruments				$	(7,533	)		$	(7,043	)		$	14,769
Derivative Contracts		Realized Gain (Loss) on Derivative Instruments					(120	)			2,296				(6,932	)
		Total Commodity Derivative Gain (Loss)				$	(7,653	)		$	(4,747	)		$	7,837

5. Property, Plant and Equipment

     The following table sets forth the Company’s property, plant and equipment:

		December 31,
		2010				2009
		(In thousands)
Proved oil and gas properties		$	479,657			$	195,546
Less: Accumulated depreciation, depletion, amortization and impairment			(98,821	)			(62,330	)
Proved oil and gas properties, net			380,836				133,216
Unproved oil and gas properties			101,311				47,804
Other property and equipment			1,970				866
Less: Accumulated depreciation			(434	)			(313	)
Other property and equipment, net			1,536				553
Total property, plant and equipment, net		$	483,683			$	181,573

     Included in the Company’s oil and gas properties are asset retirement costs of $6.3 million and $5.4 million at December 31, 2010 and 2009, respectively.

     Asset Impairments — As discussed in Note 2, as a result of expiring unproved property leases, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $12.0 million and $5.4 million for the years ended December 31, 2010 and 2009, respectively. For the year ended December 31, 2009, the Company also recorded a non-cash impairment charge of $0.8 million on its proved oil and gas properties. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2010.

6. Acquisitions

     Asset Acquisitions — During the fourth quarter of 2010, the Company acquired approximately 16,700 net acres of land in Roosevelt County, Montana and approximately 10,000 net leasehold acres primarily located in Richland County, Montana for $52.3 million and $30.1 million, respectively. This acreage is part of our West Williston project area. Based on the FASB’s relative authoritative guidance, neither acquisition qualified as a business combination.

     Kerogen Acquisition — On June 15, 2009, the Company acquired interests in certain oil and gas properties primarily in the East Nesson area of the Williston Basin from Kerogen Resources, Inc. (the “Kerogen Acquisition Properties”) for $27.1 million. In addition to acquiring the interests in the East Nesson project area, the Company also acquired non-operated interests in the Sanish project area.

     The Kerogen acquisition qualified as a business combination, and as such, the Company estimated the fair value of these properties as of the June 15, 2009 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed in Note 3 — Fair Value Measurements.

     The Company estimated the fair value of the Kerogen Acquisition Properties to be approximately $27.1 million, which the Company considered to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The acquisition related costs were insignificant.

     The following table summarizes the consideration paid for the Kerogen Acquisition Properties and the fair value of the assets acquired and liabilities assumed as of June 15, 2009.

Consideration given to Kerogen Resources, Inc. (in thousands):
Cash		$	27,087
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties		$	25,178
Proved undeveloped properties			1,647
Unproved lease acquisition costs			360
Seismic costs			667
Asset retirement obligations			(765	)
Total identifiable net assets		$	27,087

     Summarized below are the consolidated results of operations for the years ended December 31, 2009 and 2008, on an unaudited pro forma basis, as if the acquisition had occurred on January 1 of each of the periods presented. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Kerogen Acquisition Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.

		Year Ended December 31,
		2009								2008
		Actual				Pro Forma				Actual				Pro Forma
						(In thousands)
						Unaudited
Kerogen Acquisition Properties:
Revenues		$	37,755			$	41,999			$	34,736			$	51,314
Net Loss		$	(15,209	)		$	(15,461	)		$	(34,391	)		$	(25,858	)

     Fidelity Acquisition — On September 30, 2009, the Company acquired additional interests in the East Nesson project area of the Williston Basin from Fidelity Exploration and Production Company (the “Fidelity Acquisition Properties”) for $10.7 million.

     The Fidelity acquisition qualified as a business combination, and as such, the Company estimated the fair value of these properties as of the September 30, 2009 acquisition date. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed in Note 3 — Fair Value Measurements.

     The Company estimated the fair value of the Fidelity Acquisition Properties to be approximately $10.7 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The acquisition related costs were insignificant.

     The following table summarizes the consideration paid for the Fidelity Acquisition Properties and the fair value of the assets acquired and liabilities assumed as of September 30, 2009.

Consideration given to Fidelity Exploration and Production Company (in thousands):
Cash		$	10,681
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties		$	4,668
Proved undeveloped properties			2,415
Unproved lease acquisition costs			3,450
Seismic costs			667
Asset retirement obligations			(519	)
Total identifiable net assets		$	10,681

     Summarized below are the consolidated results of operations for the years ended December 31, 2009 and 2008, on an unaudited pro forma basis as if the acquisition had occurred on January 1 of each of the periods presented. The pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Fidelity Acquisition Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.

		Year Ended December 31,
		2009								2008
		Actual				Pro Forma				Actual				Pro Forma
						(In thousands)
						Unaudited
Fidelity Acquisition Properties:
Revenues		$	37,755			$	40,934			$	34,736			$	38,438
Net Loss		$	(15,209	)		$	(15,872	)		$	(34,391	)		$	(33,065	)

7. Accrued Liabilities

     The Company’s accrued liabilities consist of the following:

		December 31,
		2010				2009
		(In thousands)
Accrued capital costs		$	49,935			$	14,754
Accrued lease operating expense			3,305				1,560
Accrued general and administrative expense			3,014				1,056
Other			1,985				668
Total		$	58,239			$	18,038

     In addition, the Company had production taxes payable of $3.2 million and $1.2 million and revenue suspense of $2.3 million and $1.1 million for the years ended December 31, 2010 and 2009, respectively, included in Production taxes and royalties payable on the Consolidated Balance Sheet.

8. Long-Term Debt

     Oasis Petroleum LLC, as parent, and OPNA, as borrower, entered into a credit agreement dated June 22, 2007 (as amended, the “Credit Facility”). On February 26, 2010, the Company entered into an agreement that amended and restated the existing Credit Facility, as amended (the “Amended Credit Facility”). The Amended Credit Facility increased the initial borrowing base to a maximum of $70 million, extended the maturity date to February 26, 2014, and included BNP Paribas, JP Morgan Chase Bank, UBS Loan Finance LLC and Wells Fargo Bank as lenders (collectively, the “Lenders”). Borrowings under the Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports. In connection with the IPO, the Company became a guarantor under the Amended Credit Facility on June 3, 2010.

     The Amended Credit Facility provides for semi-annual redeterminations on April 1 and October 1 of each year, commencing October 2, 2010. At the Company’s request, the semi-annual redetermination of the borrowing base

under its Amended Credit Facility was completed on August 11, 2010. As a result of this redetermination, the Company’s borrowing base increased from $70 million to $120 million. Contemporaneously with this redetermination, the Company amended its Amended Credit Facility to ease certain limitations on the Company’s ability to enter into derivative financial instruments. All other rates, terms and conditions of the Amended Credit Facility remained the same.

     Borrowings under the Amended Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London Interbank Offered Rate (“LIBOR”) loan or a bank prime interest rate loan (defined in the Amended Credit Facility as an Alternate Based Rate or “ABR” loan). As of December 31, 2010, the LIBOR and ABR loans beared their respective interest rates plus the applicable margin indicated in the following table:

		Applicable Margin				Applicable Margin
Ratio of Total Outstanding Borrowings to Borrowing Base		for LIBOR Loans				for ABR Loans
Less than .50 to 1			2.25	%			0.75	%
Greater than or equal to .50 to 1 but less than .75 to 1			2.50	%			1.00	%
Greater than or equal to .75 to 1 but less than .85 to 1			2.75	%			1.25	%
Greater than .85 to 1 but less than or equal 1			3.00	%			1.50	%

     An ABR loan does not have a set maturity date and may be repaid at any time upon the Company providing advance notification to the Lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum loan term is six months for LIBOR-based loans. Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms that are greater than three months in duration. At the end of a LIBOR loan term, the Amended Credit Facility allows the Company to elect to continue a LIBOR loan with the same or a differing loan term or convert the borrowing to an ABR loan.

     On a quarterly basis, the Company also pays a 0.50% commitment fee on the daily amount of borrowing base capacity not utilized during the quarter and fees calculated on the daily amount of letter of credit balances outstanding during the quarter.

     As of December 31, 2010, the Amended Credit Facility contained covenants that included, among others:

	•		a prohibition against incurring debt, subject to permitted exceptions;
	•		a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
	•		a prohibition against making investments, loans and advances, subject to permitted exceptions;
	•		restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;
	•		restrictions on merging and selling assets outside the ordinary course of business;
	•		restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
	•		a provision limiting oil and natural gas derivative financial instruments;
	•		a requirement that the Company not allow a ratio of Total Debt (as defined in the Amended Credit Facility) to consolidated EBITDAX (as defined in the Amended Credit Facility) to be greater than 4.0 to 1.0 for the four quarters ended on the last day of each quarter; and
	•		a requirement that the Company maintain a Current Ratio of consolidated current assets (with exclusions as described in the Amended Credit Facility) to consolidated current liabilities (with exclusions as described in the Amended Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

     The Amended Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Amended Credit Facility to be immediately due and payable.

     As of December 31, 2010, the Company had no borrowings under the Amended Credit Facility and $25,000 of outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $120.0 million. The weighted average interest rate incurred on the outstanding Amended Credit Facility borrowings during 2010 was 3.11%. The Company was in compliance with the financial covenants of the Amended Credit Facility as of December 31, 2010.

     During 2010, the Company recorded $1.8 million of deferred financing costs related to costs incurred in connection with amending and restating the Credit Facility and the semi-annual redeterminations, which are being amortized over the term of the Amended Credit Facility. The deferred financing costs are included in Deferred costs and other assets on the Company’s Consolidated Balance Sheet at December 31, 2010. The amortization of deferred financing costs is included in Interest expense on the Consolidated Statement of Operations. The Company also wrote off $132,000 of unamortized deferred financing costs related to the Credit Facility, included in Interest expense on the Company’s Consolidated Statement of Operations, for the year ended December 31, 2010.

9. Asset Retirement Obligations

     The following table reflects the changes in the Company’s ARO during the years ended December 31, 2010 and 2009:

		December 31,
		2010				2009
		(In thousands)
Asset retirement obligation — beginning of period		$	6,511			$	4,458
Liabilities incurred during period			1,747				2,144
Liabilities settled during period			(422	)			(395	)
Accretion expense during period			414				362
Revisions to estimates			(610	)			(58	)
Asset retirement obligation — end of period		$	7,640			$	6,511

10. Stock-Based Compensation

     Restricted Stock Awards — The Company has granted restricted stock awards to employees and directors under its 2010 Long-Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. As of December 31, 2010, the Company assumed no annual forfeiture rate because of the Company’s lack of turnover and lack of history for this type of award.

     The following table summarizes information related to restricted stock held by the Company’s employees and directors at December 31, 2010:

						Weighted Average
						Grant Date
		Shares				Fair Value
Non-vested shares outstanding at December 31, 2009			—				—
Granted			240,345			$	16.16
Vested			—				—
Forfeited			—				—
Non-vested shares outstanding at December 31, 2010			240,345			$	16.16

     Stock-based compensation expense recorded for restricted stock awards for the year ended December 31, 2010 was approximately $1.2 million and is included in General and administrative expenses on the Company’s Consolidated Statement of Operations. Unrecognized expense as of December 31, 2010 for all outstanding restricted stock awards was $2.7 million and will be recognized over a weighted average period of 2.0 years. No

stock-based compensation expense was recorded for the years ended December 31, 2009 and 2008 as the Company had not historically issued stock-based compensation awards to its employees and directors.

     Class C Common Unit Interests — In March 2010, the Company recorded a $5.2 million stock-based compensation charge associated with OPM’s grant of 1.0 million Class C Common Unit interests (“C Units”) to certain employees of the Company. The C Units were granted on March 24, 2010 to individuals who were employed by the Company as of February 1, 2010, and who were not executive officers or key employees with an existing capital investment in OPM (“Oasis Petroleum Management LLC Capital Members”). All of the C Units vested immediately on the grant date, and based on the characteristics of the C Units awarded to employees, the Company concluded that the C Units represented an equity-type award and accounted for the value of this award as if it had been awarded by the Company.

     The C Units were membership interests in OPM and not direct interests in the Company. The C Units are non-transferable and have no voting power. OPM has an interest in OAS Holdco, but neither OPM nor its members have a controlling interest or controlling voting power in OAS Holdco. OPM will distribute any cash or common stock it receives to its members based on membership interests and distribution percentages. OPM will only make distributions if it first receives cash or common stock from distributions made at the election of OAS Holdco. As of December 31, 2010, OPM had distributed substantially all cash or requisite common stock to its members based on membership interests and distribution percentages.

     In accordance with the FASB’s authoritative guidance for share-based payments, the Company used a fair-value-based method to determine the value of stock-based compensation awarded to its employees and recognized the entire grant date fair value of $5.2 million as stock-based compensation expense on the Consolidated Statement of Operations due to the immediate vesting of the awards with no future requisite service period required of the employees.

     The Company used a probability weighted expected return method to evaluate the potential return and associated fair value allocable to the C Unit shareholders using selected hypothetical future outcomes (continuing operations, private sale of the Company, and an IPO). Approximately 95% of the fair value allocated to the C Unit shareholders came from the IPO scenario. The IPO fair value of the C Units awarded to the Company’s employees was estimated on the date of the grant using the Black-Scholes option-pricing model with the assumptions described below.

     The exercise price of the option used in the option-pricing model was set equal to the maximum value of OPM’s current capital investment in the Company as that value must be returned to Oasis Petroleum Management LLC Capital Members before distributions are made to the C Unit shareholders. Since the Company was not a public entity on the grant date, it did not have historical stock trading data that could be used to compute volatilities associated with certain expected terms; therefore, the expected volatility value of 60% was estimated based on an average of volatilities of similar sized oil and gas companies with operations in the Williston Basin whose common stocks are publicly traded. The allocable fair value to the C Units occurs in an assumed timing of four years based on a future potential secondary offering or distribution of common stock of the Company. The OAS Holdco agreement between its members required a complete distribution of all remaining shares held by OAS Holdco by 2014, the fourth year following the year of the IPO. The 2.08% risk-free rate used in the pricing model is based on the U.S. Treasury yield for a government bond with a maturity equal to the time to liquidity of four years. The Company did not estimate forfeiture rates due to the immediate vesting of the award and did not estimate future dividend payments as it does not expect to declare or pay dividends in the foreseeable future.

     Discretionary Stock Awards — During the fourth quarter of 2010, the Company recorded a $3.5 million stock-based compensation charge primarily associated with OPM granting discretionary shares of the Company’s common stock to certain of the Company’s employees who were not C Unit holders and certain contractors. Based on the characteristics of these awards, the Company concluded that they represented an equity-type award and accounted for the value of these awards as if they had been awarded by the Company. The fair value of these awards was based on the value of the Company’s common stock on the date of grant. All of these awards vested immediately on the grant date with no future requisite service period required of the employees or contractors.

     Stock-based compensation expense recorded for the C Units and discretionary stock awards for the year ended December 31, 2010 was $8.7 million. As the awards vested immediately, there was no unrecognized stock-based

compensation expense as of December 31, 2010 related to these awards. No stock-based compensation expense was recorded for the years ended December 31, 2009 and 2008 as the Company had not historically issued stock-based compensation awards to its employees.

11. Income Taxes

     Prior to its corporate reorganization in connection with the IPO (see Note 1), the Company was a limited liability company and not subject to federal or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company’s equity holders were responsible for income tax on the Company’s profits. In connection with the closing of the Company’s IPO, the Company merged into a corporation and became subject to federal and state income taxes. The Company’s book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company’s oil and natural gas properties.

     At June 30, 2010, the Company recorded an estimated net deferred tax expense of $29.2 million to recognize a deferred tax liability for the initial book and tax basis differences. This deferred tax liability was preliminary and included significant estimates related to the pre-corporate reorganization period of 2010. The preliminary calculation was based on information that was available to management at the time such estimates were made as further analysis was dependent upon the receipt of actual expenditure information in subsequent months.

     At September 30, 2010, the Company increased its estimate of this deferred tax liability by $6.2 million to $35.4 million. After analyzing the book and tax basis differences for capital expenditure accruals made at June 30, 2010, management determined that an additional deferred tax liability of $5.2 million was needed as of the date of the corporate reorganization. In addition, new tax legislation was passed in September 2010, which extended bonus tax depreciation retroactive to January 1, 2010, resulting in an additional increase of the Company’s deferred tax liability of $0.8 million. These adjustments, along with $0.2 million of other changes in estimates, were recorded as a discrete deferred tax expense for the three months ended September 30, 2010. The final adjustment to the Company’s estimated deferred tax liability related to the pre-IPO period was recorded in the fourth quarter of 2010, which resulted in an additional discrete adjustment of $0.2 million.

     The Company’s effective tax rate differs from the federal statutory rate of 35% due to the initial deferred tax expense, state income taxes, certain non-deductible IPO-related costs and non-deductible stock-based compensation expense. The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the year ended December 31, 2010 is set forth below:

						(In thousands)
U.S. federal tax statutory rate			35.00	%		$	4,644
State income taxes, net of federal income tax benefit			2.75	%			364
Pass-through loss prior to IPO not subject to federal tax			3.85	%			511
Initial deferred tax expense			268.43	%			35,612
Non-deductible stock-based compensation			10.08	%			1,338
Non-deductible IPO costs and other			3.72	%			493
Annual effective tax rate			323.83	%		$	42,962

     Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2010 were as follows:

		(In thousands)
Deferred tax assets
Derivative instruments		$	3,958
Net operating loss carryforward			43,455
Total deferred tax assets			47,413
Deferred tax liabilities
Oil and natural gas properties			90,375
Total deferred tax liabilities			90,375
Net deferred tax liability		$	42,962

     The current portion of the Company’s net deferred tax liability was an asset of $2.5 million at December 31, 2010.

     The Company generated a net operating tax loss of $115.0 million for the year ended December 31, 2010, and therefore no current income taxes are anticipated to be paid. The opportunity to utilize such net operating loss in future periods will expire by 2030. As of December 31, 2010, the Company did not have any uncertain tax positions requiring adjustments to its tax liability.

     The Company files income tax returns in the U.S. federal jurisdiction and in Montana, North Dakota and Texas. The Company has not been audited by the IRS or any state jurisdiction. Its statute of limitation for the year ended December 31, 2010 will expire in 2014.

12. Earnings (Loss) Per Share

     Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, unless their effect is anti-dilutive.

     The following is a calculation of the basic and diluted weighted-average shares outstanding for the year ended December 31, 2010:

		(In thousands)
Basic weighted average common shares outstanding(1)			48,395
Dilution effect of stock awards at end of period(2)			—
Diluted weighted average common shares outstanding			48,395
Anti-dilutive stock-based compensation awards			120

13. Significant Concentrations

     Purchasers that accounted for more than 10% of the Company’s total sales for the periods presented are as follows:

		Year Ended December 31,
		2010				2009				2008
Plains All American Pipeline L.P.			28%				N/A				N/A
Texon L.P.			19%				30%				14%
Whiting Petroleum Corporation			11%				N/A				N/A
Tesoro Refining and Marketing Company			N/A				32%				57%

     No other purchasers accounted for more than 10% of the Company’s total oil and natural gas sales for the years ended December 31, 2010, 2009 and 2008. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing regions.

     Substantially all of the Company’s accounts receivable result from sales of oil and natural gas as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. Brigham Oil & Gas LP and Hess Corporation accounted for approximately 44% and 12%, respectively, of the Company’s JIB receivables balance at December 31, 2010. Zenergy Operating Company LLC, Bristol Exploration LP and Abraxas Petroleum Corporation accounted for approximately 27%, 19% and 13%,

respectively, of the Company’s JIB receivables balance at December 31, 2009. Hess Corporation and Windsor Bakken LLC accounted for approximately 41% and 13%, respectively, of the Company’s JIB receivables balance at December 31, 2008. No other individual account balances accounted for more than 10% of the Company’s total JIB receivables at December 31, 2010, 2009 and 2008.

     This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.

14. Commitments and Contingencies

     Lease Obligations — The Company has operating leases for office space and other property and equipment. The Company incurred rental expense of $0.6 million, $0.4 million and $0.3 million for the years ended December 31, 2010, 2009 and 2008, respectively.

     Future minimum annual rental commitments under non-cancelable leases at December 31, 2010 are as follows:

		(In thousands)
2011			909
2012			922
2013			912
2014			900
Thereafter			2,516
		$	6,159

     Drilling Contracts — During 2010, the Company entered into two new drilling rig contracts with initial terms greater than one year. In the event of early contract termination under these new contracts, the Company would be obligated to pay approximately $2.5 million as of December 31, 2010 for the days remaining through the end of the primary terms of the contracts.

     Volume Commitment Agreements — During 2010, the Company entered into certain agreements with an aggregate requirement to deliver a minimum quantity of approximately 3 Bcf from our West Williston project area within a specified timeframe. Future obligations under these agreements are approximately $5.3 million as of December 31, 2010. The Company also entered into an agreement with a requirement to deliver a minimum quantity of approximately 790 MBbl from our West Williston project area within a specified timeframe. Based on the terms of the agreement, the Company is unable to quantify its future obligation under this agreement as of December 31, 2010, as the margin on the replacement price is determined at the time of production shortfall, if any.

     Litigation — The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. The Company believes all such matters are without merit or involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows.

15. Subsequent Events

     Lease Obligations — On January 12, 2011, the Company executed an amendment to its office space lease agreement for an additional 11,638 square feet of space within its current office building. Under the terms of the amendment, the Company’s rental obligation for the new premises will begin upon substantial completion of the remodeling work in the new premises, which is projected to be in May 2011. The amended lease agreement terminates on September 30, 2017.

     Drilling Contracts — On January 13, 2011, the Company entered into a new drilling rig contract with an initial term greater than one year. In the event of early contract termination under this new contract, the Company would be obligated to pay a maximum of approximately $12.2 million if terminated immediately at the beginning of the contract. On February 17, 2011, the Company extended one of its existing drilling rig contracts for an additional year. In the event of early contract termination under this extended contract, the Company would be obligated to pay an additional maximum of approximately $3.7 million if terminated immediately.

     Senior Secured Revolving Line of Credit — On January 21, 2011, a redetermination of the borrowing base under the Company’s Amended Credit Facility was completed, at the request of the Company, in lieu of the April 2, 2011 redetermination. As a result of this redetermination, the Company’s borrowing base increased from $120 million to $150 million. However, in connection with the issuance of the Company’s private placement of $400 million of senior unsecured notes due 2019 on February 2, 2011, as described below, the Company’s borrowing base under its Amended Credit Facility automatically decreased $12.5 million to $137.5 million.

     Contemporaneously with this redetermination, the Company entered into a third amendment to its Amended Credit Facility in order to:

	•		eliminate the $200 million limit for unsecured notes;
	•		reduce the interest rates payable on borrowings under its Amended Credit Facility;
	•		modify the debt coverage ratio covenant to be net of cash and cash equivalents on the Company’s Consolidated Balance Sheet;
	•		extend the maturity date from February 26, 2014 to February 26, 2015;
	•		increase the size of the Amended Credit Facility from $250 million to $600 million; and
	•		add an additional lender to the bank group for the Amended Credit Facility.

     Borrowings under the Amended Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London Interbank Offered Rate (“LIBOR”) loan or a bank prime interest rate loan (defined in the Amended Credit Facility as an Alternate Based Rate or “ABR” loan). The LIBOR and ABR loans bear their respective interest rates plus the applicable margin indicated in the following table:

		Applicable Margin		Applicable Margin
Ratio of Total Outstanding Borrowings to Borrowing Base		for LIBOR Loans		for ABR Loans
Less than .50 to 1		2.00%		0.50%
Greater than or equal to .50 to 1 but less than .75 to 1		2.25%		0.75%
Greater than or equal to .75 to 1 but less than .85 to 1		2.50%		1.00%
Greater than .85 to 1 but less than or equal 1		2.75%		1.25%

     All other rates, terms and conditions of the Amended Credit Facility dated February 26, 2010 remained the same (see Note 8).

     Senior Unsecured Notes — On February 2, 2011, the Company issued $400 million of 7.25% senior unsecured notes (the “Notes”) due February 1, 2019. Interest is payable on the Notes semi-annually in arrears on each February 1 and August 1, commencing August 1, 2011. The Notes are guaranteed on a senior unsecured basis by our material subsidiaries (“Guarantors”). The issuance of these Notes resulted in net proceeds to us of approximately $390 million, which we will use to fund our exploration, development and acquisition program and for general corporate purposes.

     At any time prior to February 1, 2014, the Company may redeem up to 35% of the Notes at a redemption price of 107.25% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to February 1, 2015, the Company may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after February 1, 2015, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 103.625% for the twelve-month period beginning on February 1, 2015, 101.813% for the twelve-month period beginning February 1, 2016 and 100.00% beginning on February 1, 2017, plus accrued and unpaid interest to the redemption date.

     The securities offered have not been registered under the Securities Act of 1933, as amended, (the “Securities Act”), or any state securities laws; and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The senior unsecured notes are expected to be eligible for trading by qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S.

     On February 2, 2011, in connection with the issuance of the Notes, the Company entered into an Indenture (the “Base Indenture”), among the Company and U.S. Bank National Association, as trustee (the “Trustee”), as amended and supplemented by the first supplemental indenture among the Company, the Guarantors and the Trustee, dated as of February 2, 2011 (the “Supplemental Indenture”; the Base Indenture, as amended and supplemented by the Supplemental Indenture, the “Indenture”).

     The Indenture restricts the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants.

     The Indenture contains customary events of default, including:

	•		default in any payment of interest on any Note when due, continued for 30 days;
	•		default in the payment of principal of or premium, if any, on any Note when due;
	•		failure by the Company to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods;
	•		payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the Indenture) in the aggregate principal amount of $10.0 million or more;
	•		certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;
	•		failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary to pay certain final judgments aggregating in excess of $10.0 million within 60 days; and
	•		any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

     Derivative Instruments — In 2011, the Company entered into new two-way and three-way collar option contracts, all of which settle monthly based on the West Texas Intermediate crude oil index price, for a total notional amount of 974,000 barrels in 2011, 915,000 barrels in 2012 and 730,000 barrels in 2013. These commodity derivatives do not qualify for and were not designated as hedging instruments for accounting purposes.

     Volume Commitment Agreements — In 2011, the Company entered into a marketing agreement with a requirement to deliver a minimum quantity of approximately 1.2 MMBbl from our West Williston project area within a specified timeframe. The future obligation under this agreement is approximately $1.2 million as of February 28, 2011.

16. Supplemental Oil and Gas Disclosures

     The supplemental data presented herein reflects information for all of the Company’s oil and natural gas producing activities.

     Capitalized Costs

     The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2010 and 2009:

		December 31,
		2010				2009
		(In thousands)
Proved oil and gas properties		$	479,657			$	195,546
Less: Accumulated depreciation, depletion, amortization and impairment			(98,821	)			(62,330	)
Proved oil and gas properties, net			380,836				133,216
Unproved oil and gas properties			101,311				47,804
Total oil and gas properties, net		$	482,147			$	181,020

     Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $6.3 million and $5.4 million at December 31, 2010 and 2009, respectively.

     Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

     The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2010, 2009 and 2008:

		Year Ended December 31,
		2010				2009				2008
						(In thousands)
Acquisition costs:
Proved oil and gas properties		$	20,259			$	35,134			$	36,969
Unproved oil and gas properties			81,624				13,917				—
Exploration costs			297				1,019				3,222
Development costs			243,758				38,526				39,025
Asset retirement costs			968				1,314				—
Total costs incurred		$	346,906			$	89,910			$	79,216

     Results of Operations for Oil and Natural Gas Producing Activities

     Results of operations for oil and natural gas producing activities, which excludes straight-line depreciation, general and administrative expense and interest expense, are presented below.

		December 31,
		2010				2009				2008
						(In thousands)
Revenues		$	128,927			$	37,755			$	34,736
Production costs			28,350				12,501				10,074
Depreciation, depletion and amortization			37,583				16,592				8,581
Exploration costs			297				1,019				3,222
Rig termination			—				3,000				—
Impairment of oil and gas properties			11,967				6,233				47,117
Gain on sale of properties			—				(1,455	)			—
Income tax expenses			17,756				—				—
Results of operations for oil and gas producing activities		$	32,974			$	(135	)		$	(34,258	)

17. Supplemental Oil and Gas Reserve Information — Unaudited

     The reserve estimates at December 31, 2010 and 2009 presented in the table below are based on reports prepared by DeGolyer and MacNaughton, independent reserve engineers, in accordance with the FASB’s new authoritative guidance on oil and gas reserve estimation and disclosures. The reserve estimates at December 31, 2008 presented in the table below are based on a report prepared by W.D. Von Gonten & Co. using the FASB’s rules in effect at that time. At December 31, 2010, all of the Company’s oil and natural gas producing activities were conducted within the continental United States.

     The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

     Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

     Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited

     The following table sets forth the Company’s net proved, proved developed and proved undeveloped reserves at December 31, 2010, 2009 and 2008:

		Oil				Gas
		(MBbl)				(MMcf)				MBoe
2008
Proved reserves
Beginning balance			4,044				1,239				4,251
Revisions of previous estimates			(1,604	)			(479	)			(1,684	)
Extensions, discoveries and other additions			132				34				137
Sales of reserves in place			—				—				—
Purchases of reserves in place			—				—				—
Production			(379	)			(123	)			(400	)
Net proved reserves at December 31, 2008			2,193				671				2,304
Proved developed reserves, December 31, 2008			2,193				671				2,304
Proved undeveloped reserves, December 31, 2008			—				—				—
2009
Proved reserves
Beginning balance			2,193				671				2,304
Revisions of previous estimates			781				(84	)			767
Extensions, discoveries and other additions			8,381				3,414				8,950
Sales of reserves in place			(2	)			(16	)			(5	)
Purchases of reserves in place			1,726				1,611				1,995
Production			(658	)			(326	)			(712	)
Net proved reserves at December 31, 2009			12,421				5,270				13,299
Proved developed reserves, December 31, 2009			5,231				2,293				5,613
Proved undeveloped reserves, December 31, 2009			7,190				2,977				7,686
2010
Proved reserves
Beginning balance			12,421				5,270				13,299
Revisions of previous estimates			2,235				1,897				2,552
Extensions, discoveries and other additions			22,445				12,172				24,473
Sales of reserves in place			(122	)			(5	)			(123	)
Purchases of reserves in place			1,363				696				1,479
Production			(1,792	)			(651	)			(1,900	)
Net proved reserves at December 31, 2010			36,550				19,379				39,780
Proved developed reserves, December 31, 2010			15,650				8,208				17,018
Proved undeveloped reserves, December 31, 2010			20,900				11,171				22,762

          Purchases of Reserves in Place

     Of the total 1,479 MBoe of reserves purchased in 2010, 715 MBoe were from the properties acquired in Roosevelt County, Montana in November 2010 and 764 MBoe were from the properties acquired in Richland County, Montana in December 2010.

     Of the total 1,995 MBoe of reserves purchased in 2009, 1,511 MBoe were from the Kerogen Acquisition Properties and 484 MBoe were from the Fidelity Acquisition Properties. The Company did not purchase reserves in place in 2008.

          Extensions, Discoveries and Other Additions

     In 2010, the Company had a total of 24,473 MBoe of additions. An estimated 8,122 MBoe of extensions and discoveries were associated with new wells, which were producing at December 31, 2010, with approximately 99% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 16,351 MBoe of proved undeveloped reserves were added across all three of the Company’s Williston Basin project areas associated with the Company’s 2010 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

     In 2009, the Company had a total of 8,950 MBoe of additions. An estimated 1,508 MBoe of extensions and discoveries were associated with new wells, which were producing at December 31, 2009, with approximately 95% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 7,442 MBoe of proved undeveloped reserves were added across all three of the Company’s Williston Basin project areas associated with the Company’s 2009 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

     In 2008, the Company had a total of 137 MBoe of additions. An estimated 127 MBoe resulted from the Company’s 2008 Bakken drilling program in the East Nesson project area.

          Sales of Reserves in Place

     The Company traded interests in three non-operated properties as part of the Richland County, Montana acquisition in December 2010. These properties produce from the Red River formation and had remaining reserves of 123 MBoe.

     In 2009, the Company sold a portion its interests in non-core oil and gas producing properties located in the Barnett shale in Texas, which had minimal impact on the Company’s proved reserves. The Company had no divestitures for the year ended December 31, 2008.

          Revisions of Previous Estimates

     In 2010, the Company had net positive revisions of 2,552 MBoe. Approximately 29% of these revisions were due to the increase in oil prices from 2009 to 2010. The unweighted arithmetic average first-day-of-the-month prices for the 12 months prior were $79.40/Bbl for the year ended December 31, 2010 as compared to $61.04/Bbl for the year ended December 31, 2009. An estimated 29% of the increase was due to higher working interests in proved wells. The remaining 42% of these revisions were due to other changes, including the estimate of recoverable hydrocarbons from proved wells.

     In 2009, the Company had net positive revisions of 767 MBoe, primarily due to the increase in oil prices. The unweighted arithmetic average first-day-of-the-month prices for the 12 months prior was $61.04/Bbl for the year ended December 31, 2009 as compared to the market price for oil of $44.60/Bbl used for the December 31, 2008 reserves.

     In 2008, the Company had net negative revisions of 1,684 MBoe. An estimated 461 MBoe reduction resulted from poor drilling results in the conventional Madison formation, including proved undeveloped locations offsetting the Madison formation drilling results. The remaining net 1,223 MBoe reduction is primarily related to the decrease in oil price, including 461 MBoe of proved undeveloped reserves at December 31, 2007, which did not have a positive PV-10 at the lower oil prices and were removed from the December 31, 2008 reserves. The index price for oil at December 31, 2008 decreased to $44.60/Bbl from $96.00/Bbl at December 31, 2007.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited

     The Standardized Measure represents the present value of estimated future cash flows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

     Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the year ended December 31, 2010 and $61.04/Bbl for oil and $3.87/MMBtu for natural gas for the year ended December 31, 2009. The index prices were $44.60/Bbl for oil and $5.63/MMBtu for natural gas at December 31, 2008. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The impact of the adoption of the FASB’s authoritative guidance on the SEC oil and gas reserve estimation final rule on our consolidated financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

     The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves at December 31, 2010, 2009 and 2008.

		At Year Ended December 31,
		2010				2009				2008
						(In thousands)
Future cash inflows		$	2,620,530			$	664,480			$	85,678
Future production costs			(696,890	)			(258,137	)			(54,885	)
Future development costs			(362,328	)			(120,212	)			(3,708	)
Future income tax expense(1)			(495,788	)			—				—
Future net cash flows			1,065,524				286,131				27,085
10% annual discount for estimated timing of cash flows			(579,789	)			(152,601	)			(9,355	)
Standardized measure of discounted future net cash flows		$	485,735			$	133,530			$	17,730

     The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the periods presented.

		2010				2009				2008
						(In thousands)
January 1,		$	133,530			$	17,730			$	121,807
Net changes in prices and production costs			126,089				11,423				(48,986	)
Net changes in future development costs			(9,767	)			1,998				210
Sales of oil and natural gas, net			(100,577	)			(25,254	)			(24,662	)
Extensions			426,824				71,333				2,648
Discoveries			—				—				—
Purchases of reserves in place			26,919				36,809				—
Sales of reserves in place			(1,720	)			(108	)			—
Revisions of previous quantity estimates			55,149				7,700				(48,260	)
Previously estimated development costs incurred			32,729				—				746
Accretion of discount			13,353				3,352				12,181
Net change in income taxes			(212,085	)			—				—
Changes in timing and other			(4,709	)			8,547				2,046
December 31,		$	485,735			$	133,530			$	17,730