UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-34776

 

Oasis Petroleum Inc.

(Exact name of registrant as specified in its charter)

Delaware		80-0554627
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 202 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 574-1770
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

Number of shares of the registrant’s common stock outstanding at August 13, 2010: 92,215,295 shares.

 

 

OASIS PETROLEUM INC.
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2010

TABLE OF CONTENTS

		Page
PART I — FINANCIAL INFORMATION			1
Item 1. — Financial Statements (Unaudited)			1
Consolidated Balance Sheet at June 30, 2010 and December 31, 2009			2
Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2010 and 2009			3
Consolidated Statement of Changes in Stockholders’/Members’ Equity for the Six Months Ended June 30, 2010 and the Year Ended December 31, 2009			4
Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2010 and 2009			5
Notes to the Consolidated Financial Statements			6
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations			17
Item 3. — Quantitative and Qualitative Disclosures About Market Risk			26
Item 4. — Controls and Procedures			27
PART II — OTHER INFORMATION			28
Item 1. — Legal Proceedings			28
Item 1A. — Risk Factors			28
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds			28
Item 5. — Other Information			29
Item 6. — Exhibits			29
SIGNATURES			31
EXHIBIT INDEX			32
Exhibit 10.18
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)
Consolidated Balance Sheet at June 30, 2010 and December 31, 2009
Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2010 and 2009
Consolidated Statement of Changes in Stockholders’/Members’ Equity for the Six Months Ended June 30, 2010 and the Year Ended December 31, 2009
Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2010 and 2009
Notes to the Consolidated Financial Statements

OASIS PETROLEUM INC.

CONSOLIDATED BALANCE SHEET
(Unaudited)

		June 30,				December 31,
		2010				2009
		(In thousands, except share amounts)
ASSETS
Current assets
Cash and cash equivalents		$	326,231			$	40,562
Accounts receivable — oil and gas revenues			15,577				9,142
Accounts receivable — joint interest partners			10,193				1,250
Inventory			3,140				1,258
Prepaid expenses			1,199				134
Advances to joint interest partners			2,369				4,605
Derivative instruments			717				219
Deferred tax asset			254				—
Total current assets			359,680				57,170
Property, plant and equipment
Oil and gas properties (successful efforts method)			340,811				243,350
Other property and equipment			1,044				866
Less: accumulated depreciation, depletion, amortization and impairment			(77,118	)			(62,643	)
Total property, plant and equipment, net			264,737				181,573
Derivative instruments			409				—
Deferred costs and other assets			2,041				810
Total assets		$	626,867			$	239,553
LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY
Current liabilities
Accounts payable		$	11,165			$	1,577
Advances from joint interest partners			1,763				589
Production taxes and royalties payable			4,154				2,563
Accrued liabilities			25,368				18,038
Accrued interest payable			2				144
Derivative instruments			387				1,087
Total current liabilities			42,839				23,998
Long-term debt			—				35,000
Asset retirement obligations			5,949				6,511
Derivative instruments			684				2,085
Deferred income taxes			30,121				—
Other liabilities			87				109
Total liabilities			79,680				67,703
Commitments and contingencies (see Note 12)
Stockholders’/members’ equity
Capital contributions			—				235,000
Common stock, $0.01 par value; 300,000,000 shares authorized; 92,215,295 shares issued and outstanding			920				—
Additional paid-in-capital			638,998				—
Retained deficit/accumulated loss			(92,731	)			(63,150	)
Total stockholders’/members’ equity			547,187				171,850
Total liabilities and stockholders’/members’ equity		$	626,867			$	239,553

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

OASIS PETROLEUM INC.

CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)

		Three months ended								Six months ended
		June 30,								June 30,
		2010				2009				2010				2009
		(In thousands, except per share amounts)
Oil and gas revenues		$	26,734			$	6,037			$	46,802			$	9,253
Expenses
Lease operating expenses			2,927				2,106				5,904				3,913
Production taxes			2,702				463				4,612				731
Depreciation, depletion and amortization			8,783				2,683				14,632				5,211
Exploration expenses			24				214				42				59
Rig termination			—				—				—				3,000
Impairment of oil and gas properties			7,907				809				10,984				1,250
Stock-based compensation expenses			—				—				5,200				—
General and administrative expenses			3,743				1,298				7,259				2,716
Total expenses			26,086				7,573				48,633				16,880
Operating income (loss)			648				(1,536	)			(1,831	)			(7,627	)
Other income (expense)
Change in unrealized gain (loss) on derivative instruments			3,399				(4,942	)			3,008				(5,601	)
Realized gain (loss) on derivative instruments			(33	)			791				(59	)			2,233
Interest expense			(509	)			(198	)			(847	)			(392	)
Other income (expense)			12				2				15				(8	)
Total other income (expense)			2,869				(4,347	)			2,117				(3,768	)
Income (loss) before income taxes			3,517				(5,883	)			286				(11,395	)
Income tax expense			29,867				—				29,867				—
Net loss		$	(26,350	)		$	(5,883	)		$	(29,581	)		$	(11,395	)
Loss per share:
Basic and diluted (Note 11)		$	(3.26	)		$	—			$	(7.28	)		$	—
Pro forma loss per share:
Basic and diluted (Note 11)		$	(0.29	)		$	(0.06	)		$	(0.32	)		$	(0.12	)
Weighted averages shares outstanding:
Basic and diluted (Note 11)			8,088				—				4,066				—
Pro forma weighted averages shares outstanding:
Basic and diluted (Note 11)			92,000				92,000				92,000				92,000

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

OASIS PETROLEUM INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’/MEMBERS’ EQUITY
(Unaudited)
(In thousands)

		Common Stock																Retained				Total
		Number																Deficit/				Stockholders’/
		of								Capital				Additional Paid-in-				Accumulated				Members’
		Shares				Amount				Contributions				Capital				Loss				Equity
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			215				—				—				5,249				—				5,249
Net loss			—				—				—				—				(29,581	)			(29,581	)
Balance as of June 30, 2010			92,215			$	920			$	—			$	638,998			$	(92,731	)		$	547,187

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

OASIS PETROLEUM INC.

CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)

		Six months ended
		June 30,
		2010				2009
		(In thousands)
Cash Flows from Operating Activities:
Net loss		$	(29,581	)		$	(11,395	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			14,632				5,211
Impairment of oil and gas properties			10,984				1,250
Deferred income taxes			29,867				—
Derivative instruments			(2,949	)			3,368
Stock-based compensation expense			5,249				—
Debt discount amortization and other			332				47
Working capital and other changes:
Change in accounts receivable			(15,601	)			(508	)
Change in inventory			(1,789	)			(20	)
Change in prepaid expenses			(1,065	)			81
Change in other assets			(84	)			—
Change in accounts payable and accrued liabilities			10,657				(1,447	)
Change in other liabilities			(22	)			(20	)
Net cash provided by (used in) operating activities			20,630				(3,433	)
Cash flows from investing activities:
Capital expenditures			(101,568	)			(21,875	)
Acquisition of oil and gas properties			—				(26,803	)
Derivative settlements			(59	)			2,233
Advances to joint interest partners			2,236				(957	)
Advances from joint interest partners			1,174				(163	)
Net cash used in investing activities			(98,217	)			(47,565	)
Cash flows from financing activities:
Proceeds from members’ contributions			—				59,600
Proceeds from sale of common stock			399,669				—
Proceeds from issuance of debt			72,000				6,000
Reduction in debt			(107,000	)			(13,000	)
Debt issuance costs			(1,413	)			—
Net cash provided by financing activities			363,256				52,600
Increase in cash and cash equivalents			285,669				1,602
Cash and cash equivalents:
Beginning of period			40,562				1,570
End of period		$	326,231			$	3,172
Supplemental non-cash transactions:
Change in accrued capital expenditures		$	7,726			$	(5,346	)
Asset retirement obligations			(183	)			849

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

OASIS PETROLEUM INC.

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. 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 private equity funds managed by EnCap Investments LLC (“EnCap”). 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. The sale of the shares in the Company’s IPO closed on June 22, 2010.

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 have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2009 is derived from audited financial statements. All significant intercompany transactions have been eliminated in consolidation. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair presentation have been included. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read with the audited consolidated financial statements and notes thereto included in the Company’s Registration Statement on Form S-1, as amended (Registration No 333-165212).

Recent Accounting Pronouncements

Financial Receivables - On July 21, 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 Company does not expect the adoption of this new guidance to have an impact on its financial position, cash flows or results of operations.

3. 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:

		June 30,				December 31,
		2010				2009
		(In thousands)
Equipment and materials		$	138			$	588
Crude oil inventory			3,002				670
Total inventory		$	3,140			$	1,258

4. Property, Plant and Equipment

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

		June 30,				December 31,
		2010				2009
		(In thousands)
Proved oil and gas properties		$	292,743			$	195,546
Less: Accumulated depreciation, depletion, amortization and impairment			(76,705	)			(62,330	)
Proved oil and gas properties, net			216,038				133,216
Unproved oil and gas properties			48,068				47,804
Other property and equipment			1,044				866
Less: Accumulated depreciation			(413	)			(313	)
Other property and equipment, net			631				553
Total property, plant and equipment, net		$	264,737			$	181,573

As a result of expiring unproved leases, the Company recorded non-cash impairment charges of $7.9 million and $11.0 million for the three and six months ended June 30, 2010, respectively, and $0.8 million and $1.3 million for the three and six months ended June 30, 2009, respectively.

5. 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 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

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. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards and options.

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 June 30, 2010
		Level 1				Level 2				Level 3				Total
		(In thousands)
Assets (Liabilities):
Commodity Derivative Instruments (see Note 6)		$	—			$	—			$	55			$	55
Total Derivative Instruments		$	—			$	—			$	55			$	55

		At fair value as of December 31, 2009
		Level 1				Level 2				Level 3				Total
		(In thousands)
Assets (Liabilities):
Commodity Derivative Instruments (see Note 6)		$	—			$	—			$	(2,953	)		$	(2,953	)
Total Derivative Instruments		$	—			$	—			$	(2,953	)		$	(2,953	)

The Level 3 instruments presented in the tables above consist of crude oil swaps and collars. The Company utilizes the mark-to-market valuation reports provided by its counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. 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). 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 periods presented.

		2010				2009
		(In thousands)
Balance as of January 1		$	(2,953	)		$	4,090
Total gains or (losses) (realized or unrealized):
Included in earnings			2,949				(3,368	)
Included in other comprehensive income			—				—
Purchases, issuances and settlements			59				(2,233	)
Transfers in and out of level 3			—				—
Balance as of June 30		$	55			$	(1,511	)
Change in unrealized gains (losses) included in earnings relating to derivatives still held at June 30		$	3,008			$	(5,601	)

At June 30, 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.

Nonfinancial Assets and Liabilities

Asset Retirement Obligations — The carrying amount of the Company’s asset retirement obligations (“ARO”) in the Consolidated Balance Sheet at June 30, 2010 is $6.2 million (see Note 8 — Asset Retirement Obligations).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. Estimating the future ARO requires management to make estimates and judgments regarding timing and the 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.

Impairment — 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. 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 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 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. No impairment on proved oil and natural gas properties was recorded for the three and six months ended June 30, 2010 and 2009.

6. Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of June 30, 2010, the Company utilized zero-cost collar options to reduce the volatility of oil prices on a portion of the Company’s future expected oil production. As of December 31, 2009, the Company utilized both fixed-price swap agreements and zero-cost collar options.

All derivative instruments are recorded on the Consolidated Balance Sheet as either assets or liabilities measured at their fair value (see Note 5 — Fair Value Measurements). Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. 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 June 30, 2010, the Company had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges:

				Total Notional
		Derivative		Amount of Oil				Average Floor				Average Ceiling				Fair Value Asset
Settlement Period		Instrument		(Barrels)				Price				Price				(Liability)
																(In thousands)
2010		NYMEX Collar			289,284			$	69.30			$	90.39			$	283
2011		NYMEX Collar			465,744			$	68.15			$	90.48				(178	)
2012		NYMEX Collar			38,418			$	68.07			$	90.56				(50	)
																$	55

As of December 31, 2009, the Company had the following outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges:

				Total
				Notional
Settlement		Derivative		Amount of				Average				Average								Fair Value Asset
Period		Instrument		Oil (Barrels)				Floor Price				Ceiling Price				Fixed Price				(Liability)
																				(In thousands)
2010		NYMEX Swap			11,163											$	72.25			$	(26	)
2010		NYMEX Collar			401,814			$	67.48			$	90.19								(841	)
2011		NYMEX Collar			186,764			$	61.49			$	82.23								(1,912	)
2012		NYMEX Collar			13,618			$	60.00			$	80.25								(174	)
																				$	(2,953	)

The following table summarizes the location and fair value of all outstanding commodity derivative contracts recorded in the balance sheet that do not qualify for hedge accounting for the periods presented:

Fair Value of Derivative Instrument Assets (Liabilities)
				June 30,				December 31,
Investment Type		Balance Sheet Location		2010				2009
				(In thousands)
Crude oil collar		Derivative Instruments — current assets		$	717			$	219
Crude oil collar		Derivative Instruments — non-current asset			409				—
Crude oil swap		Derivative Instruments — current liabilities			—				(26	)
Crude oil collar		Derivative Instruments — current liabilities			(387	)			(1,061	)
Crude oil collar		Derivative Instruments — non-current liabilities			(684	)			(2,085	)
		Total Derivative Instruments		$	55			$	(2,953	)

The following table summarizes the location and amounts of realized and unrealized gains and losses from the Company’s commodity derivative contracts that do not qualify for hedge accounting for the periods presented:

				Three Months Ended								Six Months Ended
				June 30,								June 30,
		Income Statement Location		2010				2009				2010				2009
				(In thousands)
Derivative Contracts		Change in Unrealized Gain (Loss) on Derivative Instruments		$	3,399			$	(4,942	)		$	3,008			$	(5,601	)
Derivative Contracts		Realized Gain (Loss) on Derivative Instruments			(33	)			791				(59	)			2,233
		Total Derivative Instruments Gain (Loss)		$	3,366			$	(4,151	)		$	2,949			$	(3,368	)

7. Long-Term Debt

Oasis Petroleum LLC, as parent, and OPNA, as borrower, entered into a credit agreement dated June 22, 2007, which was subsequently amended as of June 10, 2008, May 13, 2009, June 23, 2009 and June 3, 2010 (as amended, the “Credit Facility”). On February 26, 2010, the Company entered into an agreement that amended and restated the existing Credit Facility (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 (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. The Amended Credit Facility provides for semi-annual redeterminations on April 1 and October 1 of each year, commencing October 2, 2010. In connection with the IPO, the Company entered into an amendment to the Amended Credit Facility to add it as a guarantor.

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			2.25	%			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 for 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.

The Amended Credit Facility contains covenants that include, 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 hedging transactions to a volume not exceeding 100 percent of anticipated production from proved developed producing reserves;
	•		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 June 30, 2010, the Company had no borrowings under the Amended Credit Facility and $65,000 of outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $69.9 million. The weighted average interest rate incurred on the outstanding Amended Credit Facility borrowings for the six months ended June 30, 2010 was 3.11%. The Company was in compliance with the financial covenants of the Credit Facility and Amended Credit Facility as of June 30, 2010.

Upon execution of the Amended Credit Facility, the Company recorded $1.4 million of deferred financing costs, 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 Consolidated Balance Sheet at June 30, 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 Consolidated Statement of Operations, for the six months ended June 30, 2010. See Note 13 — Subsequent Events.

8. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO for the six months ended June 30, 2010:

		(In thousands)
Asset retirement obligation — January 1		$	6,511
Liabilities incurred			(319	)
Liabilities settled			(162	)
Accretion expense			201
Revisions to estimates			—
Asset retirement obligation — June 30		$	6,231

At June 30, 2010, the current portion of the total ARO balance is approximately $0.3 million and is included in accrued liabilities on the Consolidated Balance Sheet.

9. Stock-Based Compensation

Restricted Stock Awards — In conjunction with its IPO that closed on June 22, 2010, the Company granted restricted stock awards under its 2010 Long-Term Incentive Plan. The awards granted to employees vest in three substantially equal installments on January 1 in each of the next three years, such that 100% of the shares will be vested on January 1, 2013. The restricted stock awards granted to directors will be 100% vested on June 22, 2011.

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 June 30, 2010, the Company assumed no annual forfeiture rate because of the Company’s lack of turnover and history for this type of award.

						Weighted Average
						Grant Date
		Shares				Fair Value
Non-vested shares outstanding at December 31, 2009			—				—
Granted			215,295			$	15.72
Vested			—				—
Forfeited			—				—
Non-vested shares outstanding at June 30, 2010			215,295			$	15.72

Stock-based compensation expense recorded for restricted stock awards for the three and six months ended June 30, 2010 was approximately $49,000 and is included in general and administrative expenses on the Consolidated Statement of Operations. Unrecognized expense as of June 30, 2010 for all outstanding restricted stock awards was $3.3 million and will be recognized over a weighted average period of 2.4 years. No stock-based compensation expense was recorded for the three and six months ended June 30, 2009 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 expense associated with OPM granting 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, are non-voting and provide an opportunity for employees to participate in appreciation realized through the IPO and/or future sales or distributions of the Company’s shares indirectly held by OPM.

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 shareholders are entitled to receive a portion of the distributions made to OPM, but only after those future distributions have satisfied a complete return of the capital investment previously made by the Oasis Petroleum Management LLC Capital Members, plus a specified return on their capital investment.

The C Units are membership interests in OPM and not a direct interest 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.

Under the FASB’s authoritative guidance for share-based payments, stock-based compensation expense is measured based on the calculated fair value of the award on the grant date. The expense is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. 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 and no future requisite service period required of the employees.

The Company used a probability weighted expected return method to evaluate the potential return to 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 allocable to the C Unit shareholders comes 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, which represent Level 3 inputs (see Note 5 — Fair Value Measurements).

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 estimated 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 does require a complete distribution of all remaining shares held by OAS Holdco in 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.

Stock-based compensation expense recorded for the C Units for the six months ended June 30, 2010 was $5.2 million. As the awards vested immediately, there was no unrecognized stock-based compensation expense as of June 30, 2010. No stock-based compensation expense was recorded for the six months ended June 30, 2009 as the Company had not historically issued stock-based compensation awards to its employees.

10. Income Taxes

Prior to its corporate reorganization (Note 1), the Company was a limited liability company and not subject to federal income tax 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. The Company recorded a net deferred tax expense of $29.9 million to recognize a deferred tax liability related to the Company’s initial book and tax basis differences.

Significant components of the Company’s deferred tax assets and liabilities as of June 30, 2010 were as follows:

		(In thousands)
Derivatives instruments		$	123
Oil and natural gas properties			(29,990	)
Total net deferred tax asset (liability)		$	(29,867	)

The deferred tax liability is preliminary and includes significant estimates. The preliminary calculation is based on information that was available to management at the time these consolidated financial statements were prepared. Management has not yet analyzed the book and tax differences for its period-end accruals for capital expenditures related to its non-operated properties. This analysis is needed to determine the split between intangible drilling costs and equipment, which have differing characteristics for tax purposes. Accordingly, the deferred tax liability will change as additional information becomes available and is assessed by management, and the impact of such changes may be material.

Subsequent to the corporate reorganization, the Company recorded federal and state income tax expense at an effective tax rate of 37.8% on pre-tax income of $1.9 million earned in the post-reorganization period from June 17, 2010 (the effective date of the reorganization) to June 30, 2010. The Company’s effective tax rate for the post-reorganization period differs from the federal statutory rate of 35% due to state income taxes. The Company is projected to generate a tax loss in the current year and thus no current income taxes are anticipated to be paid.

As of June 30, 2010, the Company was not aware of any uncertain tax positions requiring adjustments to its tax liability.

11. 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 three and six months ended June 30, 2010:

		June 30, 2010
		Three Months				Six Months
		Ended				Ended
		(In thousands)
Weighted average basic common shares outstanding(1)			8,088				4,066
Effect of dilutive securities(2)			—				—
Weighted average diluted common shares outstanding			8,088				4,066

The following is a calculation of the unaudited pro forma basic and diluted weighted-average shares outstanding for the periods presented:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2010				2009				2010				2009
		(In thousands)								(In thousands)
Weighted average basic common shares outstanding			92,000				92,000				92,000				92,000
Effect of dilutive securities(1)			—				—				—				—
Weighted average diluted common shares outstanding			92,000				92,000				92,000				92,000

12. Commitments and Contingencies

Lease Obligations —On June 29, 2010, the Company executed an amendment to its office space lease agreement for relocation to a new floor within its current office building. Under the terms of the amendment, the Company’s obligation for its existing premises will terminate and rental obligations for the new premises will begin upon substantial completion of the remodeling work in the new premises, which is projected to be in September 2010, and when the Company will take possession of the new premises. The amended lease agreement will have a term of 84 months.

Drilling Contracts —On March 25, 2010, the Company entered into a new drilling rig contract. In the event of early contract termination under this new contract, the Company would be obligated to pay approximately $3.0 million as of June 30, 2010 for the days remaining through the end of the primary contract term.

Litigation — There are no material claims, title matters or other legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under oil and gas operating agreements and other contractual disputes that are pending or threatened against the Company at this time. The Company purchases and maintains general liability and other insurance to cover such potential liabilities.

13. Subsequent Events

The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than as noted below.

Drilling Contracts —On August 4, 2010, the Company entered into a new drilling rig contract. In the event of early contract termination under this new contract, the Company would be obligated to pay a maximum of approximately $1.8 million for the days remaining through the end of the primary contract term.

Senior Secured Revolving Line of Credit —At the Company’s request, the semi-annual redetermination of the borrowing base under its Amended Credit Facility was completed on August 11, 2010, prior to the normal October 1, 2010 timeframe. As a result of this redetermination, the Company’s borrowing base increased from $70 million to $120 million. Contemporaneously with this redetermination, the Company entered into an amendment to its Amended Credit Facility easing certain limitations on the ability of the Company to enter into hedging transactions. All other rates, terms and conditions of the Amended Credit Facility dated February 26, 2010 remained the same (see Note 7 — Long-Term Debt).

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with management’s discussion and analysis contained in our prospectus dated June 16, 2010 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424 (b) on June 17, 2010, as well as the unaudited consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements may include projections and estimates concerning capital expenditures, our liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of our business strategy and other statements concerning our operations, economic performance and financial condition. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed in our prospectus dated June 16, 2010 and filed with the SEC pursuant to Rule 424 (b) on June 17, 2010, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

	•		business strategy;
	•		reserves;
	•		technology;
	•		cash flows and liquidity;
	•		financial strategy, budget, projections and operating results;
	•		oil and natural gas realized prices;
	•		timing and amount of future production of oil and natural gas;
	•		availability of drilling and production equipment;
	•		availability of oil field labor;
	•		the amount, nature and timing of capital expenditures, including future development costs;
	•		availability and terms of capital;
	•		drilling of wells;
	•		competition and government regulations;
	•		marketing of oil and natural gas;
	•		exploitation or property acquisitions;
	•		costs of exploiting and developing our properties and conducting other operations;
	•		general economic conditions;
	•		competition in the oil and natural gas industry;
	•		effectiveness of our risk management activities;
	•		environmental liabilities;
	•		counterparty credit risk;
	•		governmental regulation and taxation of the oil and natural gas industry;
	•		developments in oil-producing and natural gas-producing countries;
	•		uncertainty regarding our future operating results;
	•		estimated future net reserves and present value thereof; and
	•		plans, objectives, expectations and intentions contained in this quarterly report that are not historical.

All forward-looking statements speak only as of the date of this quarterly report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this quarterly report all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Williston Basin. Since our inception, we have emphasized the acquisition of properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken formation. Substantially all of our revenues are generated through the sale of oil and natural gas production at market prices and the settlement of commodity derivative contracts.

We began active oil and natural gas operations in July 2007 upon the acquisition of properties in the Williston Basin. In May 2008, we entered into a farm-in and purchase arrangement that established our initial position in the East Nesson project area. In June 2009, we acquired additional mineral interests and production in our East Nesson project area and also acquired properties that established our Sanish project area. In September 2009, we acquired additional mineral interests and production that further consolidated our acreage position in the East Nesson project area.

Second Quarter 2010 Operational Highlights:

	•		Completed and placed on production 27 gross wells (7.9 net wells);
	•		Drilling or completing 35 gross wells (7.3 net wells) in the Bakken and Three Forks formations at June 30, 2010; and
	•		Average daily production of 4,461 Boe per day during the three months ended June 30, 2010.

Second Quarter 2010 Financial Highlights:

	•		Completed our IPO of 30,370,000 shares of our common stock at a price to the public of $14.00 per share and received net proceeds of $399.7 million;
	•		Repaid the entire $75.0 million of borrowings under our Amended Credit Facility; and
	•		Incurred capital expenditures of $72.1 million, consisting primarily of drilling ($57.3 million) and acquisition of unproved properties ($14.8 million).

Sources of revenue

Our revenues are derived from the sale of oil and natural gas production and do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

The following table summarizes our revenues and production data for the periods indicated.

		Three Months Ended June 30,												Six Months Ended June 30,
		2010				2009				% Change				2010				2009				% Change
Operating results (in thousands):
Revenues
Oil		$	25,616			$	5,897				334	%		$	44,558			$	9,023				394	%
Natural gas			1,118				140				699	%			2,244				230				876	%
Total oil and gas revenues			26,734				6,037				343	%			46,802				9,253				406	%
Production data:
Oil (MBbls)			381				112				240	%			651				214				204	%
Natural gas (MMcf)			148				41				261	%			309				69				348	%
Oil equivalents (MBoe)			406				119				241	%			702				226				211	%
Average daily production (Boe/d)			4,461				1,311				240	%			3,881				1,247				211	%
Average sales prices:
Oil, without realized derivatives (per Bbl)		$	67.19			$	52.48				28	%		$	68.44			$	42.11				63	%
Oil, with realized derivatives (1) (per Bbl)			67.10				59.52				13	%			68.35				52.53				30	%
Natural gas (per Mcf)			7.53				3.39				122	%			7.27				3.35				117	%

Three months ended June 30, 2010 as compared to three months ended June 30, 2009

Oil and Natural Gas Revenues. Our oil and natural gas sales revenues increased $20.7 million, or over 300%, to $26.7 million during the second quarter ended June 30, 2010 as compared to the second quarter ended June 30, 2009. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those increased volumes. Average daily production sold increased by 3,150 Boe per day, or 240%, to 4,461 Boe per day during the second quarter ended June 30, 2010 as compared to the second quarter ended June 30, 2009. The increase in average daily production sold was primarily in our Sanish and East Nesson project areas due to the acquisitions completed in the second and third quarters of 2009, respectively, and as a result of our well completions during 2009 and the first and second quarters of 2010. The acquisitions contributed approximately 700 Boe per day during the second quarter of 2010, and well completions in our Sanish, East Nesson and West Williston project areas contributed approximately 1,019 Boe per day, 1,131 Boe per day and 674 Boe per day, respectively, during the second quarter of 2010. The higher production amounts sold contributed $18.9 million to the revenue increase and the remaining $1.8 million increase was attributable to higher oil sales prices during the second quarter ended June 30, 2010. Average oil sales prices, without realized derivatives, increased by $14.71 per barrel, or 28%, to an average of $67.19 per barrel for the second quarter ended June 30, 2010 as compared to the second quarter ended June 30, 2009.

Six months ended June 30, 2010 as compared to six months ended June 30, 2009

Oil and Natural Gas Revenues. Our oil and natural gas sales revenues increased $37.5 million, or over 400%, to $46.8 million during the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those increased volumes. Average daily production sold increased by 2,634 Boe per day, or 211%, to 3,881 Boe per day during the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. The increase in average daily production sold was primarily in our Sanish and East Nesson project areas due to the acquisitions completed in the second and third quarters of 2009, respectively, and as a result of our well completions during 2009 and the first and second quarters of 2010. The acquisitions contributed approximately 723 Boe per day during the first six months of 2010, and well completions in our Sanish, East Nesson and West Williston project areas contributed approximately 888 Boe per day, 846 Boe per day and 447 Boe per day, respectively, during the first six months of 2010. The higher production amounts sold contributed $31.6 million to the revenue increase and the remaining $5.9 million increase was attributable to higher oil sales prices during the six months ended June 30, 2010. Average oil sales prices, without realized derivatives, increased by $26.33 per barrel, or 63%, to an average of $68.44 per barrel for the six months ended June 30, 2010 as compared to the six months ended June 30, 2009.

Expenses

The following table summarizes our operating expenses for the periods indicated.

		Three Months Ended June 30,												Six Months Ended June 30,
		2010				2009				% Change				2010				2009				% Change
		(In thousands, except cost and expense (per Boe of production))
Expenses:
Lease operating expenses		$	2,927			$	2,106				39	%		$	5,904			$	3,913				51	%
Production taxes			2,702				463				484	%			4,612				731				531	%
Depreciation, depletion and amortization			8,783				2,683				227	%			14,632				5,211				181	%
Exploration expenses			24				214				(89	%)			42				59				(29	%)
Rig termination			—				—				—				—				3,000				(100	%)
Impairment of oil and gas properties			7,907				809				877	%			10,984				1,250				779	%
Stock-based compensation expense			—				—				—				5,200				—				100	%
General and administrative expenses			3,743				1,298				188	%			7,259				2,716				167	%
Total expenses		$	26,086			$	7,573				244	%		$	48,633			$	16,880				188	%
Operating income (loss)			648				(1,536	)			(142	%)			(1,831	)			(7,627	)			(76	%)
Other income (expense):
Change in unrealized gain (loss) on derivative instruments			3,399				(4,942	)			(169	%)			3,008				(5,601	)			(154	%)
Realized gain (loss) on derivative instruments, net			(33	)			791				(104	%)			(59	)			2,233				(103	%)
Interest expense			(509	)			(198	)			157	%			(847	)			(392	)			116	%
Other income (expense)			12				2				500	%			15				(8	)			(288	%)
Total other income (expense)			2,869				(4,347	)			(166	%)			2,117				(3,768	)			(156	%)
Income (loss) before income taxes			3,517				(5,883	)			(160	%)			286				(11,395	)			(103	%)
Income tax expense			29,867				—				100	%			29,867				—				100	%
Net loss		$	(26,350	)		$	(5,883	)			348	%		$	(29,581	)		$	(11,395	)			160	%
Cost and expense (per Boe of production):
Lease operating expenses		$	7.21			$	17.66				(59	%)		$	8.40			$	17.34				(52	%)
Production taxes			6.66				3.88				72	%			6.57				3.24				103	%
Depreciation, depletion and amortization			21.63				22.50				(4	%)			20.83				23.09				(10	%)
General and administrative expenses			9.22				10.88				(15	%)			10.33				12.03				(14	%)
Stock-based compensation expense			—				—				—				7.40				—				100	%

Three months ended June 30, 2010 compared to three months ended June 30, 2009

Lease Operating Expenses. Lease operating expenses increased $0.8 million to $2.9 million for the three months ended June 30, 2010 compared to the three months ended June 30, 2009. This increase was primarily due to the higher number of productive wells from our Sanish and East Nesson acquisitions that were completed in the second and third quarters of 2009, respectively, and from our well completions during 2009 and the first two quarters of 2010. The 240% increase in oil volumes from the three months ended June 30, 2009 to the three months ended June 30, 2010 resulted in a 59% decrease in unit operating costs to $7.21 per Boe.

Production Taxes. Our production taxes for the three months ended June 30, 2010 and 2009 were 10.11% and 7.67%, respectively, as a percentage of oil and natural gas sales. The production tax rate for the three months ended June 30, 2010 was higher than the production tax rate for the three months ended June 30, 2009 due to the increased weighting of oil revenues in North Dakota, which imposes an 11.5% production tax rate. The production taxes for the three months ended June 30, 2009 were primarily for oil and natural gas sales revenue associated with properties in our West Williston project area that generate revenues subject to lower Montana production tax rates.

Depreciation, Depletion and Amortization (DD&A). Depreciation, depletion and amortization expense increased $6.1 million for the three months ended June 30, 2010 compared to the three months ended June 30, 2009. The increase in DD&A expense for the three months ended June 30, 2010 was primarily due to the production increases from the Sanish and East Nesson acquisitions completed in the second and third quarters of 2009, respectively, and as a result of our well completions during 2009 and the first two quarters of 2010. The DD&A rate for the three months ended June 30, 2010 was $21.63 per Boe compared to $22.50 per Boe for the three months ended June 30, 2009. This decrease in the DD&A rate was due to the lower cost of reserve additions associated with our 2009 acquisition and drilling activities.

Impairment of Oil and Gas Properties. During the three months ended June 30, 2010 and 2009, we recorded non-cash impairment charges of $7.9 million and $0.8 million, respectively, for unproved property leases that expired during the period.

General and Administrative. Our general and administrative expenses increased to $3.7 million for the three months ended June 30, 2010 from $1.3 million for the three months ended June 30, 2009. Of this increase, approximately $1.4 million was due to higher advisory, audit, legal, tax and filing fees related to our IPO. The remaining increase was primarily due to higher compensation costs related to additional employees (including contractors).

Derivatives. As a result of our derivative activities, we incurred cash settlement losses of $33,000 for the three months ended June 30, 2010 and cash settlement gains of $0.8 million for the three months ended June 30, 2009. In addition, as a result of forward oil price changes, we recognized a $3.4 million unrealized mark-to-market non-cash derivative gain for the three months ended June 30, 2010 and a $4.9 million unrealized mark-to-market non-cash derivative loss for the three months ended June 30, 2009.

Interest Expense. Interest expense increased by $0.3 million for the three months ended June 30, 2010 compared to the three months ended June 30, 2009. The increase was a result of our higher weighted average outstanding debt balance (offset by slightly lower weighted average borrowing rates) during the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, coupled with the increased amortization of the deferred financing costs related to the Amended Credit Facility. Our weighted average debt balance increased to $48.2 million for the three months ended June 30, 2010 compared to $18.9 million for the three months ended June 30, 2009.

Income Tax Expense. Prior to our corporate reorganization, we were a limited liability company not subject to entity level income tax. Accordingly, no provision for federal or state corporate income taxes was recorded for the three months ended June 30, 2009 as the taxable income was allocated directly to our equity holders. In connection with the closing of our IPO, we merged into a corporation and became subject to federal and state entity-level taxation. In connection with our corporate reorganization, an initial net deferred tax liability of $29.9 million was established for differences between the tax and book basis of our assets and liabilities and a corresponding tax expense was recorded in our Consolidated Statement of Operations.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

Lease Operating Expenses. Lease operating expenses increased $2.0 million to $5.9 million for the six months ended June 30, 2010 compared to the six months ended June 30, 2009. This increase was primarily due to the higher number of productive wells from our Sanish and East Nesson acquisitions that were completed in the second and third quarters of 2009, respectively, and from our well completions during 2009 and the first two quarters of 2010. The 211% increase in oil volumes from the six months ended June 30, 2009 to the six months ended June 30, 2010 resulted in a 52% decrease in unit operating costs to $8.40 per Boe.

Production Taxes. Our production taxes for the six months ended June 30, 2010 and 2009 were 9.85% and 7.90%, respectively, as a percentage of oil and natural gas sales. The production tax rate for the six months ended June 30, 2010 was higher than the production tax rate for the six months ended June 30, 2009 due to the increased weighting of oil revenues in North Dakota, which imposes an 11.5% production tax rate. The production taxes for the six months ended June 30, 2009 were primarily for oil and natural gas sales revenue associated with properties in our West Williston project area that generate revenues subject to lower Montana production tax rates.

Depreciation, Depletion and Amortization (DD&A). Depreciation, depletion and amortization expense increased $9.4 million for the six months ended June 30, 2010 compared to the six months ended June 30, 2009. The increase in DD&A expense for the six months ended June 30, 2010 was primarily due to the production increases from the Sanish and East Nesson acquisitions completed in the second and third quarters of 2009, respectively, and as a result of our well completions during 2009 and the first two quarters of 2010. The DD&A rate for the six months ended June 30, 2010 was $20.83 per Boe compared to $23.09 per Boe for the six months ended June 30, 2009. This decrease in the DD&A rate was due to the lower cost of reserve additions associated with our 2009 acquisition and drilling activities.

Rig Termination. During 2008, we entered into drilling rig contracts with two drilling contractors. In the fourth quarter of 2008, we reduced our planned 2009 capital expenditure program and entered into discussions regarding early termination of these contracts. During the first quarter of 2009, we paid a total of $3.0 million in rig termination expenses in connection with the early termination of our drilling rig contracts. We did not have any rig termination expenses during the six months ended June 30, 2010.

Impairment of Oil and Gas Properties. During the six months ended June 30, 2010 and 2009, we recorded non-cash impairment charges of $11.0 million and $1.3 million, respectively, for unproved property leases that expired during the period.

Stock-Based Compensation Expense. For the six months ended June 30, 2010, we recorded a $5.2 million non-cash charge for stock-based compensation expense associated with OPM granting Class C Common Unit interests (“C Units”) to certain employees of the Company. Based on the characteristics of the C Units awarded, we concluded that the C Units represent an equity-type award and we accounted for the value of this award as if it had been awarded by the Company. We used fair-value-based methods to determine the value of stock-based compensation awarded to our employees and recognized the entire amount as expense due to the immediate vesting of the awards and no future requisite service period required by the employees. No stock-based compensation expense was recorded for the six months ended June 30, 2009 as we had not historically issued stock-based compensation awards to our employees. See Note 9 to our unaudited consolidated financial statements.

General and Administrative. Our general and administrative expenses increased $4.5 million for the six months ended June 30, 2010 from $2.7 million for the six months ended June 30, 2009. Of this increase, approximately $2.1 million was due to higher advisory, audit, legal, tax and filing fees related to our IPO. The remaining increase was primarily due to higher costs related to employee compensation (including bonuses paid during the first quarter of 2010) and contract labor. As of June 30, 2010, we had 45 full-time employees and contractors compared to 28 full-time employees and contractors as of June 30, 2009.

Derivatives. As a result of our derivative activities, we incurred a cash settlement loss of $59,000 for the six months ended June 30, 2010 and a cash settlement gain of $2.2 million for the six months ended June 30, 2009. In addition, as a result of forward oil price changes, we recognized a $3.0 million unrealized mark-to-market non-cash derivative gain during the six months ended June 30, 2010 and a $5.6 million unrealized mark-to-market non-cash derivative loss during the six months ended June 30, 2009.

Interest Expense. Interest expense increased by $0.5 million for the six months ended June 30, 2010 compared to the six months ended June 30, 2009. The increase was the result of our higher weighted average outstanding debt balance and higher weighted average borrowing rates during the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, coupled with the increased amortization of the deferred financing costs related to the Amended Credit Facility. In addition, we wrote off $0.1 million of remaining deferred financing costs associated with our previous revolving credit facility in February 2010. Our weighted average debt balance increased to $30.8 million for the six months ended June 30, 2010 compared to $19.5 million for the six months ended June 30, 2009.

Income Tax Expense. Prior to our corporate reorganization, we were a limited liability company not subject to entity level income tax. Accordingly, no provision for federal or state corporate income taxes was recorded for the six months ended June 30, 2009 as the taxable income was allocated directly to our equity holders. In connection with the closing of our IPO, we merged into a corporation and became subject to federal and state entity-level taxation. In connection with our corporate reorganization, an initial net deferred tax liability of $29.9 million was established for differences between the tax and book basis of our assets and liabilities and a corresponding tax expense was recorded in our Consolidated Statement of Operations.

Liquidity and Capital Resources

On June 30, 2010, we had $326.2 million of cash and cash equivalents and no indebtedness. Our primary sources of liquidity and capital are existing cash on hand and our operating cash flow. We also maintain an undrawn revolving line of credit, which can be accessed as needed to supplement our primary sources of liquidity and capital. We actively review acquisition opportunities on an ongoing basis, which may require us to obtain additional equity or debt financing.

Initial Public Offering. On June 22, 2010, we completed an IPO of 48,300,000 shares of common stock at $14.00 per share. We sold 30,370,000 shares of common stock in this offering, and OAS Holding Company LLC (“OAS Holdco”), the selling stockholder, sold 17,930,000 shares of common stock, including 6,300,000 shares sold by OAS Holdco pursuant to the full exercise of the underwriters’ over-allotment option.

We received net proceeds from the offering of $399.7 million, after deducting underwriting discounts and estimated offering expenses. We used a portion of these net proceeds to repay all outstanding indebtedness of $75.0 million under our Amended Credit Facility, and we intend to fund our exploration and development program with the remainder of the proceeds. We did not receive any proceeds from the sale of shares by OAS Holdco.

Senior Secured Revolving Line of Credit. On February 26, 2010, we entered into the Amended Credit Facility which matures in February 2014. 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 (collectively, the “Lenders”). Borrowings under the Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports. The Amended Credit Facility provides for semi-annual redeterminations on April 1 and October 1 of each year, commencing October 2, 2010. At our request, our semi-annual redetermination was completed on August 11, 2010 prior to the normal October 1, 2010 timeframe, and our borrowing base increased from $70 million to $120 million.

At our election, interest is generally determined by reference to (i) the London interbank offered rate, or LIBOR, plus an applicable margin between 2.25% and 3.00% per annum; or (ii) a domestic bank prime rate plus an applicable margin between 0.75% and 1.50% per annum.

Our Amended Credit Facility contains covenants, including financial covenants that require us and our subsidiary guarantors, on a consolidated basis, to maintain specified ratios or conditions as follows:

•

a ratio of Total Debt (as defined in the Amended Credit Facility) to consolidated EBITDAX (as defined in the Amended Credit Facility) not greater than 4.0 to 1.0 for the four quarters ended on the last day of each quarter; and

•

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 June 30, 2010, we had no borrowings under the Amended Credit Facility and $65,000 of outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $69.9 million. The weighted average interest rate incurred on the outstanding Amended Credit Facility borrowings for the six months ended June 30, 2010 was 3.11%. We were in compliance with the financial covenants of the Amended Credit Facility as of June 30, 2010.

Cash Flow Activity

Our cash flows for the six months ended June 30, 2010 and 2009 are presented below (in thousands):

		Six Months Ended
		June 30,
		2010				2009
Net cash provided by (used in) operating activities		$	20,630			$	(3,433	)
Net cash used in investing activities			(98,217	)			(47,565	)
Net cash provided by financing activities			363,256				52,600
Net increase in cash and cash equivalents		$	285,669			$	1,602

Cash flows provided by operating activities

Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of a portion of our production, thereby mitigating our exposure to price declines, but these transactions may also limit our earnings potential in periods of rising oil prices.

Net cash provided by operating activities was $20.6 million for the six months ended June 30, 2010 and net cash used in operating activities was $3.4 million for the six months ended June 30, 2009. The increase in cash flows from operations was primarily the result of an increase in oil and natural gas production of 211% for the six months ended June 30, 2010 as compared to the same period in 2009. In addition, at June 30, 2010, we had a working capital surplus of $316.8 million. This surplus for the first six months of 2010 was primarily attributable to our cash balance as a result of the proceeds from the sale of common stock in our IPO.

Cash flows used in investing activities

We had cash flows used in investing activities of $98.2 million and $47.6 million during the six months ended June 30, 2010 and 2009, respectively, as a result of our capital expenditures for drilling and development costs. For the six months ended June 30, 2009, expenditures for the development of properties were only for our West Williston project area and the acquisition of the Sanish project area and did not include properties acquired in the Sanish and East Nesson project areas in September of 2009.

Capital expenditures for drilling, development, acquisition and undeveloped acreage costs for the six months ended June 30, 2010 are summarized in the following table (in thousands):

		Six Months Ended
		June 30, 2010
Project Area:
West Williston		$	51,168
East Nesson			44,099
Sanish			13,099
Other(1)			100
Total(2)		$	108,466

Our 2010 capital expenditure budget was $220 million at June 30, 2010, which was a 147% increase over the $89 million invested during 2009. This increase was a result of improved industry conditions and technology in the Bakken formation as well as increased economics in the area. On August 9, 2010, our Board of Directors increased our 2010 capital expenditure budget to $270 million. This increase is primarily due to the increase in total net wells expected to be drilled in 2010 and an increase for potential additional lease acquisitions. Total gross operated well count is planned to increase from 35 to 39 projects (26.2 net wells). The increase in well count is a result of acceleration based on availability of rigs and improved drilling efficiency in the Bakken formation. Non-operated drilling activity is currently planned for a total of 10.3 net wells, an increase of 2.6 net wells, primarily in the southern portion of the East Nesson project area and in the Whiting Sanish field. Our land activity is focused in and around our existing core consolidated land positions, primarily in West Williston.

Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Cash flows provided by financing activities

Net cash provided by financing activities was $363.3 million for the six months ended June 30, 2010 and $52.6 million for the six months ended June 30, 2009. For the six months ended June 30, 2010, cash sourced through financing activities was primarily provided by net proceeds from the sale of common stock in our IPO in June 2010. For the six months ended June 30, 2009, cash sourced through financing activities was primarily provided by capital contributions from EnCap and other private investors and borrowings under our Amended Credit Facility. Our long-term debt, including the current portion, was $0 and $35.0 million at June 30, 2010 and December 31, 2009, respectively.

Contractual obligations

On June 29, 2010, we executed an amendment to our office space lease agreement for relocation to a new floor within our current office building. Under the terms of the amendment, our obligation for our existing premises will terminate and rental obligations for the new premises will begin upon substantial completion of the remodeling work in the new premises, which is projected to be in September 2010, and when the Company will take possession of the new premises. The amended lease agreement will have a term of 84 months.

Critical accounting policies and estimates

There have been no other material changes in our critical accounting policies and estimates from those disclosed in our prospectus dated June 16, 2010 and filed with the SEC pursuant to Rule 424(b) on June 17, 2010, other than those listed below.

Stock-based compensation

Restricted Stock Awards — We recognize compensation expense for all restricted stock awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. The fair value of restricted stock grants is based on the value of our common stock on the date of grant. Assumptions regarding forfeiture rates are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized. Stock-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on the Consolidated Statement of Operations.

Income taxes

Our provision for taxes includes both state and federal taxes. We record our 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.

We apply significant judgment in evaluating our tax positions and estimating our 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.

We also account 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. We do not have uncertain tax positions outstanding and, as such, did not record a liability for the three and six months ended June 30, 2010.

Recent accounting pronouncements

See Part I, Item 1, Note 2 to our unaudited consolidated financial statements entitled “Summary of Significant Accounting Policies.”

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements.

Item 3. — Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our prospectus dated June 16, 2010 and filed with the SEC pursuant to Rule 424(b) on June 17, 2010, as well as with the unaudited consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

Commodity price risk. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production.

We utilize derivative financial instruments to manage risks related to changes in oil prices. As of June 30, 2010, we utilized zero-cost collar options to reduce the volatility of oil prices on a significant portion of our future expected oil production.

We record all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement.

The following is a summary of our derivative contracts as of June 30, 2010:

						Total Notional
		Derivative				Amount of Oil				Average Floor				Average Ceiling				Fair Value Asset
Settlement Period		Instrument				(Barrels)				Price				Price				(Liability)
																		(In thousands)
2010		NYMEX Collar					289,284			$	69.30			$	90.39			$	283
2011		NYMEX Collar					465,744			$	68.15			$	90.48				(178	)
2012		NYMEX Collar					38,418			$	68.07			$	90.56				(50	)
																		$	55

Interest rate risk. At June 30, 2010, we had no indebtedness outstanding under our Amended Credit Facility. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

The counterparties on our derivative instruments currently in place are lenders under our Amended Credit Facility with investment grade ratings and we are likely to enter into any future derivative instruments with these or other lenders under our Amended Credit Facility which also carry investment grade ratings. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions within the agreements. As a result of the netting provisions under the agreements, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. See Note 6 to our unaudited consolidated financial statements.

Item 4. — Controls and Procedures

Material Weakness in Internal Control over Financial Reporting and Status of Remediation Efforts. As previously discussed in our Registration Statement on Form S-1, we have not maintained an effective control environment in that the design and execution of our controls has not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. We concluded that these control deficiencies constituted a material weakness in our control environment as of December 31, 2009 and March 31, 2010. To address these control deficiencies, we hired additional accounting and financial reporting staff, implemented additional analysis and reconciliation procedures and increased the levels of review and approval. Additionally, we have begun taking steps to comprehensively document and analyze our system of internal controls over financial reporting in preparation for our first management report on internal controls over financial reporting. Due to the recent implementation of these changes to the control environment, management continues to evaluate the design and effectiveness of these control changes in conjunction with the ongoing evaluation, review and formalization of its internal controls during the remainder of 2010.

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. In light of the previously identified material weakness described above, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of June 30, 2010. Notwithstanding the identified material weakness, management concluded that the financial statements and other financial information included in this Quarterly Report on Form 10-Q presents fairly in all material respects the financial condition, results of operations and cash flows for all periods presented.

Changes in Internal Control over Financial Reporting. As described above, there were changes in our system of internal controls over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

See Part I, Item 1, Note 12 to our unaudited consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.

Item 1A. — Risk Factors

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information under the heading “Risk Factors” in our prospectus dated June 16, 2010, filed with the SEC in accordance with Rule 424(b) of the Securities Act on June 17, 2010, which is accessible on the SEC’s website at www.sec.gov.

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

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Company’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if commodity prices decline as a consequence of the legislation and regulations. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds

On June 22, 2010, we completed our IPO of our common stock pursuant to our registration statement on Form S-1 (File 333-165212) declared effective by the SEC on June 16, 2010. Morgan Stanley & Co. Incorporated and UBS Securities LLC acted as joint book-running managers and representatives of the underwriters in the offering. Pursuant to the registration statement, we registered the offer and sale of 42,000,000 shares of our $0.01 par value common stock, which included 11,630,000 shares sold by the selling stockholder and 6,300,000 shares subject to an option granted to the underwriters by the selling stockholder to cover over-allotments. The underwriters exercised their over-allotment option on June 18, 2010. The sale of the shares in our IPO and the shares covered by the over-allotment option closed on June 22, 2010. Our IPO terminated upon completion of the closing.

The net proceeds of our IPO, based on the public offering price of $14.00 per share, were approximately $635.7 million, which resulted in net proceeds to us of $399.7 million after deducting estimated expenses and underwriting discounts and commissions of approximately $25.5 million and the net proceeds to the selling stockholders of approximately $236.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. No fees or expenses have been paid, directly or indirectly, to any officer, director or 10% stockholder or other affiliate. The net proceeds from our IPO were used to repay all outstanding indebtedness under our Amended Credit Facility totaling $75.0 million, and we intend to fund our exploration and development program with the remainder of the proceeds.

Item 5. — Other Information

At our request, the semi-annual redetermination of the borrowing base under our Amended Credit Facility was completed on August 11, 2010, prior to the normal October 1, 2010 timeframe. As a result of this redetermination, our borrowing base increased from $70 million to $120 million. Contemporaneously with this redetermination, we entered into an amendment to the Amended Credit Facility easing certain limitations on our ability to enter into hedging transactions. All other rates, terms and conditions of the Amended Credit Facility dated February 26, 2010 remained the same (see Note 7).

Item 6. — Exhibits

Exhibit
No.				Description of Exhibit
	3.1			Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).
	3.2			Amended and Restated Bylaws of Oasis Petroleum Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).
	4.1			Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on May 19, 2010, and incorporated herein by reference).
	10.1			Contribution Agreement, dated June 15, 2010, by and among Oasis Petroleum Inc., Oasis Petroleum LLC, OAS Holding Company LLC, OAS Mergerco LLC and EnCap Energy Capital Fund VI, L.P. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 22, 2010, and incorporated herein by reference).
	10.2			Registration Rights Agreement dated as of June 22, 2010 by and between Oasis Petroleum Inc. and OAS Holding Company LLC (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).
	10.3			Business Opportunities Agreement dated as of June 22, 2010 by and among Oasis Petroleum Inc., EnCap Investments L.P., Douglas E. Swanson, Jr. and Robert L. Zorich (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).
	10.4			Services Agreement dated as of June 22, 2010 by and between Oasis Petroleum Inc. and Oasis Petroleum Management LLC (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).
	10.5			Services Agreement dated as of June 22, 2010 by and between Oasis Petroleum Inc. and OAS Holding Company LLC (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).
	10.6			First Amendment to Amended and Restated Credit Agreement and Consent dated as of June 3, 2010 by and among Oasis Petroleum North America LLC, as borrower, Oasis Petroleum LLC and Oasis Petroleum Inc., as guarantors, BNP Paribas, as Administrative Agent, and the lenders party thereto (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).