UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2012

or

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

For the transition period from             to            

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 1500 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(281) 404-9500

(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  x    No  ¨

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  x    No  ¨

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

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

Number of shares of the registrant’s common stock outstanding at August 3, 2012: 93,342,852 shares.

OASIS PETROLEUM INC.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2012

TABLE OF CONTENTS

	Page
PART I — FINANCIAL INFORMATION		1
Item 1. — Financial Statements (Unaudited)		1
Condensed Consolidated Balance Sheet at June 30, 2012 and December 31, 2011		1
Condensed Consolidated Statement of Operations for the Three and Six Months Ended June  30, 2012 and 2011		2
Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2012		3
Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2012 and 2011		4
Notes to the Condensed Consolidated Financial Statements		5
Item  2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. — Quantitative and Qualitative Disclosures About Market Risk		29
Item 4. — Controls and Procedures		30
PART II — OTHER INFORMATION		31
Item 1. — Legal Proceedings		31
Item 1A. — Risk Factors		31
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 6. — Exhibits		31
SIGNATURES		33
EXHIBIT INDEX		34

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PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Oasis Petroleum Inc.

Condensed Consolidated Balance Sheet

(Unaudited)

	June 30, 2012			December 31, 2011
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	238,886		$	470,872
Short-term investments		—			19,994
Accounts receivable — oil and gas revenues		79,478			52,164
Accounts receivable — joint interest partners		66,794			67,268
Inventory		19,550			3,543
Prepaid expenses		674			2,140
Advances to joint interest partners		1,957			3,935
Derivative instruments		35,257			—
Deferred income taxes		—			3,233
Other current assets		1			491
Total current assets		442,597			623,640
Property, plant and equipment
Oil and gas properties (successful efforts method)		1,769,570			1,235,357
Other property and equipment		41,333			20,859
Less: accumulated depreciation, depletion, amortization and impairment		(261,529	)		(176,261	)
Total property, plant and equipment, net		1,549,374			1,079,955
Derivative instruments		18,167			4,362
Deferred costs and other assets		26,232			19,425
Total assets	$	2,036,370		$	1,727,382
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	1,010		$	12,207
Advances from joint interest partners		28,444			9,064
Revenues and production taxes payable		56,795			19,468
Accrued liabilities		237,694			119,692
Accrued interest payable		16,427			15,774
Derivative instruments		—			5,907
Deferred income taxes		11,780			—
Other current liabilities		2,895			472
Total current liabilities		355,045			182,584
Long-term debt		800,000			800,000
Asset retirement obligations		16,982			13,075
Derivative instruments		—			3,505
Deferred income taxes		133,178			92,983
Other liabilities		1,751			997
Total liabilities		1,306,956			1,093,144
Commitments and contingencies (Note 11)
Stockholders’ equity
Common stock, $0.01 par value; 300,000,000 shares authorized; 93,185,023 issued and 93,122,353 outstanding at June 30, 2012; 92,483,393 issued and 92,460,914 outstanding at December 31, 2011		922			921
Treasury stock, at cost; 62,670 and 22,479 shares at June 30, 2012 and December 31, 2011, respectively		(1,808	)		(602	)
Additional paid-in-capital		651,271			647,374
Retained earnings (deficit)		79,029			(13,455	)
Total stockholders’ equity		729,414			634,238
Total liabilities and stockholders’ equity	$	2,036,370		$	1,727,382

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

1

Oasis Petroleum Inc.

Condensed Consolidated Statement of Operations

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands, except per share data)
Revenues
Oil and gas revenues	$	145,203		$	67,206		$	283,109		$	125,950
Well services revenues		3,861			—			4,521			—
Total revenues		149,064			67,206			287,630			125,950
Expenses
Lease operating expenses		12,029			5,951			21,845			11,581
Well services operating expenses		1,207			—			1,684			—
Marketing, transportation and gathering expenses		1,970			247			4,539			559
Production taxes		13,720			7,085			26,986			13,168
Depreciation, depletion and amortization		44,213			13,100			83,099			26,912
Exploration expenses		—			259			2,835			291
Impairment of oil and gas properties		2,203			1,536			2,571			2,917
General and administrative expenses		13,537			6,614			25,736			12,564
Total expenses		88,879			34,792			169,295			67,992
Operating income		60,185			32,414			118,335			57,958
Other income (expense)
Net gain (loss) on derivative instruments		74,595			27,547			56,009			(4,119	)
Interest expense		(14,074	)		(6,761	)		(27,973	)		(11,959	)
Other income		776			379			1,374			691
Total other income (expense)		61,297			21,165			29,410			(15,387	)
Income before income taxes		121,482			53,579			147,745			42,571
Income tax expense		45,439			20,230			55,261			16,069
Net income	$	76,043		$	33,349		$	92,484		$	26,502
Earnings per share:
Basic and diluted (Note 10)	$	0.82		$	0.36		$	1.00		$	0.29
Weighted average shares outstanding:
Basic (Note 10)		92,176			92,048			92,153			92,047
Diluted (Note 10)		92,222			92,151			92,339			92,177

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

2

Oasis Petroleum Inc.

Condensed Consolidated Statement of Changes in Stockholders’ Equity

(Unaudited)

(In thousands)

	Common Stock					Treasury Stock					Additional Paid-in-Capital			Retained Earnings (Deficit)			Total Stockholders’ Equity
	Shares			Amount		Shares		Amount
Balance as of December 31, 2011		92,461		$	921		22	$	(602	)	$	647,374		$	(13,455	)	$	634,238
Stock-based compensation		702			—		—		—			3,898			—			3,898
Vesting of restricted shares		—			1		—		—			(1	)		—			—
Treasury stock – tax withholdings		(41	)		—		41		(1,206	)		—			—			(1,206	)
Net income		—			—		—		—			—			92,484			92,484
Balance as of June 30, 2012		93,122		$	922		63	$	(1,808	)	$	651,271		$	79,029		$	729,414

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

3

Oasis Petroleum Inc.

Condensed Consolidated Statement of Cash Flows

(Unaudited)

	Six Months Ended June 30,
	2012			2011
	(In thousands)
Cash flows from operating activities:
Net income	$	92,484		$	26,502
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		83,099			26,912
Impairment of oil and gas properties		2,571			2,917
Deferred income taxes		55,161			16,069
Derivative instruments		(56,009	)		4,119
Stock-based compensation expenses		3,898			1,571
Debt discount amortization and other		1,265			648
Working capital and other changes:
Change in accounts receivable		(26,840	)		(19,945	)
Change in inventory		(21,636	)		(65	)
Change in prepaid expenses		1,500			(254	)
Change in other current assets		490			(211	)
Change in other assets		(7,365	)		(103	)
Change in accounts payable and accrued liabilities		40,022			43,612
Change in other current liabilities		2,470			—
Change in other liabilities		750			323
Net cash provided by operating activities		171,860			102,095
Cash flows from investing activities:
Capital expenditures		(440,781	)		(212,267	)
Derivative settlements		(2,465	)		(4,652	)
Purchases of short-term investments		—			(164,913	)
Redemptions of short-term investments		19,994			39,974
Advances to joint interest partners		1,978			983
Advances from joint interest partners		19,380			5,851
Net cash used in investing activities		(401,894	)		(335,024	)
Cash flows from financing activities:
Proceeds from issuance of senior notes		—			400,000
Purchases of treasury stock		(1,206	)		(559	)
Debt issuance costs		(746	)		(10,027	)
Net cash (used in) provided by financing activities		(1,952	)		389,414
(Decrease) increase in cash and cash equivalents		(231,986	)		156,485
Cash and cash equivalents:
Beginning of period		470,872			143,520
End of period	$	238,886		$	300,005
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	104,486		$	(6,676	)
Change in asset retirement obligations		4,185			2,357

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

4

OASIS PETROLEUM INC.

Notes to Condensed Consolidated Financial Statements (Unaudited)

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 holding company for Oasis Petroleum LLC (“OP LLC”), the Company’s predecessor, which was formed as a Delaware limited liability company on February 26, 2007. In connection with its initial public offering in June 2010 and related corporate reorganization, the Company acquired all of the outstanding membership interests in OP LLC in exchange for shares of the Company’s common stock. In May 2007, the Company formed Oasis Petroleum North America LLC (“OPNA”), a Delaware limited liability company, to conduct its domestic oil and natural gas exploration and production activities. 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. As of June 30, 2012, OPI had no business activities or material assets. In June 2011, the Company formed Oasis Well Services LLC (“OWS”), a Delaware limited liability company, to provide well services to OPNA. In July 2011, the Company formed Oasis Petroleum Marketing LLC (“OPM”), a Delaware limited liability company, to provide marketing services to OPNA.

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 in the Williston Basin. The Company’s proved and unproved oil and natural gas properties are located in the Montana and North Dakota areas of the Williston Basin and are owned by OPNA. The Company also operates businesses that are complementary to its primary development and production activities, including a marketing business (OPM) and a well services business (OWS).

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis and its wholly owned subsidiaries: OP LLC, OPNA, OPI, OWS and OPM. The accompanying condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the condensed consolidated balance sheet at December 31, 2011 is derived from audited financial statements. All significant intercompany transactions have been eliminated in consolidation. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair presentation have been included. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed 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 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 in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”).

Significant Accounting Policies

There have been no material changes to the Company’s critical accounting policies and estimates from those disclosed in the 2011 Annual Report.

3. Inventory

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

	June 30, 2012		December 31, 2011
	(In thousands)
Equipment and materials	$	16,869	$	2,709
Crude oil inventory		2,681		834
Total inventory	$	19,550	$	3,543

5

4. Property, Plant and Equipment

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

	June 30, 2012			December 31, 2011
	(In thousands)
Proved oil and gas properties (1)	$	1,691,964		$	1,152,532
Less: Accumulated depreciation, depletion, amortization and impairment		(257,607	)		(174,948	)
Proved oil and gas properties, net		1,434,357			977,584
Unproved oil and gas properties		77,606			82,825
Oil and gas properties, net		1,511,963			1,060,409
Other property and equipment		41,333			20,859
Less: Accumulated depreciation		(3,922	)		(1,313	)
Other property and equipment, net		37,411			19,546
Total property, plant and equipment, net	$	1,549,374		$	1,079,955

(1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $15.2 million and $11.4 million at June 30, 2012 and December 31, 2011, respectively. In addition, the Company’s proved oil and gas properties include capitalized interest of $4.7 million and $3.1 million at June 30, 2012 and December 31, 2011, respectively.

As a result of expiring leases and periodic assessments of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $2.2 million and $2.6 million for the three and six months ended June 30, 2012, respectively, and $1.5 million and $2.9 million for the three and six months ended June 30, 2011, respectively. No impairment charges on proved oil and natural gas properties were recorded for the three and six months ended June 30, 2012 or 2011.

5. Fair Value Measurements

In accordance with the Financial Accounting Standards Board’s (“FASB”) authoritative guidance on fair value measurements, 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 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, 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 and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

6

Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

Financial Assets and Liabilities

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, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	145,609	$	—	$	—	$	145,609
Commodity derivative instruments (see Note 6)		—		53,424		—		53,424
Total assets	$	145,609	$	53,424	$	—	$	199,033
	At fair value as of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	250,419	$	—	$	—	$	250,419
Commodity derivative instruments (see Note 6)		—		—		4,362		4,362
Total assets	$	250,419	$	—	$	4,362	$	254,781
Liabilities:
Commodity derivative instruments (see Note 6)	$	—	$	—	$	9,412	$	9,412
Total liabilities	$	—	$	—	$	9,412	$	9,412

The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheet at June 30, 2012 and December 31, 2011. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments.

The Level 2 and Level 3 instruments presented in the tables above consist of oil collars, put spreads and deferred premium puts. The fair values of the Company’s oil collars and deferred premium puts are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using an options pricing model similar to Black-Scholes. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The determination of the fair values 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 market credit spread. Based on these calculations, the Company recorded a downward adjustment to the fair value of its net derivative asset in the amount of $0.3 million at June 30, 2012 and a downward adjustment to the fair value of its net derivative liability in the amount of $0.3 million at December 31, 2011.

The Company has adopted the FASB’s authoritative guidance amending certain accounting and disclosure requirements related to fair value measurements. The guidance clarifies and modifies some fair value measurement principles under GAAP, including a change in the valuation premise and the application of premiums and discounts, and contains some new disclosure requirements under GAAP. The guidance had no impact on the Company’s financial position, cash flows or results of operations for the six months ended June 30, 2012.

7

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.

	2012			2011
	(In thousands)
Balance as of January 1	$	(5,050	)	$	(10,486	)
Total gains or (losses) (realized or unrealized):
Included in earnings		—			(4,119	)
Included in other comprehensive income		—			—
Settlements		—			4,652
Transfers in and out of Level 3 (1)		5,050			—
Balance as of June 30	$	—		$	(9,953	)
Change in unrealized losses included in earnings relating to derivatives still held at June 30	$	—		$	533

(1) During the first six months of 2012, the inputs used to value the Company’s commodity derivative instruments were directly or indirectly observable and those contracts were transferred to Level 2.

Fair Value of Other Financial Instruments

The Company’s financial instruments, including certain cash and cash equivalents, short-term investments, accounts receivable and accounts payable, are carried at amortized cost, which approximates cost and fair value due to the short-term maturity of these instruments. At June 30, 2012, the Company’s cash equivalents were all Level 1 assets. The carrying amount of the Company’s long-term debt (senior unsecured notes due 2019 and 2021 – see Note 7) reported in the Condensed Consolidated Balance Sheet at June 30, 2012 is $800.0 million, with a fair value of $806.0 million. The Company’s unsecured notes are publicly traded and therefore categorized as a Level 1 asset.

Nonfinancial Assets and Liabilities

Asset retirement obligations. The carrying amount of the Company’s asset retirement obligations (“ARO”) in the Condensed Consolidated Balance Sheet at June 30, 2012 is $17.3 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. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

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. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. No impairment charges on proved oil and natural gas properties were recorded for the three months ended June 30, 2012 or 2011.

6. Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of June 30, 2012, the Company utilized put spreads, two-way collar options and three-way collar options to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production. All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at 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 fair value, both realized and unrealized, are recognized in the Other Income (Expense) section of the Condensed Consolidated Statement of Operations as a gain or loss on derivative instruments. 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 Condensed Consolidated Statement of Cash Flows.

8

As of June 30, 2012, the Company had the following outstanding commodity derivative instruments, all of which settle monthly based on the average West Texas Intermediate crude oil index price:

Settlement Period	Derivative Instrument	Total Notional Amount of Oil (Barrels)		Average Sub-Floor Price		Average Floor Price		Average Ceiling Price		Fair Value Asset (Liability)
										(In thousands)
2012	Two-Way Collars		1,189,500			$	89.23	$	108.76	$	7,906
2012	Three-Way Collars		1,860,000	$	66.39	$	90.33	$	109.70		12,093
2013	Two-Way Collars		201,500			$	89.23	$	108.76		1,533
2013	Three-Way Collars		2,023,420	$	65.30	$	92.51	$	112.63		13,978
2013	Put Spreads		1,717,080	$	70.71	$	91.24				12,853
2014	Three-Way Collars		827,030	$	71.08	$	92.58	$	114.15		3,714
2014	Put Spreads		150,970	$	71.03	$	91.03				1,104
2015	Three-Way Collars		62,000	$	72.50	$	92.50	$	114.40		243
										$	53,424

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

Fair Value of Derivative Instrument Assets (Liabilities)
		Fair Value
Instrument Type	Balance Sheet Location	June 30, 2012		December 31, 2011
		(In thousands)
Crude oil collar	Derivative instruments — current assets	$	35,257	$	—
Crude oil collar	Derivative instruments — non-current assets		18,167		4,362
Crude oil collar	Derivative instruments — current liabilities		—		(5,907	)
Crude oil collar	Derivative instruments — non-current liabilities		—		(3,505	)
Total derivative instruments		$	53,424	$	(5,050	)

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

		Three Months Ended June 30,						Six Months Ended June 30,
	Income Statement Location	2012			2011			2012			2011
		(In thousands)						(In thousands)
Change in unrealized gain/loss on derivative instruments	Net gain (loss) on derivative instruments	$	75,769		$	31,687		$	58,474		$	533
Realized loss on derivative instruments	Net gain (loss) on derivative instruments		(1,174	)		(4,140	)		(2,465	)		(4,652	)
Total net gain (loss) on derivative instruments		$	74,595		$	27,547		$	56,009		$	(4,119	)

7. Long-Term Debt

Senior unsecured notes. During 2011, the Company issued $400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”) and $400.0 million of 6.5% senior unsecured notes due November 1, 2021 (the “2021 Notes”, and together with the 2019 Notes, the “Notes”). Interest on the Notes is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company’s material subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The issuance of these Notes resulted in aggregate net proceeds to the Company of approximately $783.4 million.

The Notes were issued under indentures containing provisions that are substantially the same, as amended and supplemented by supplemental indentures (collectively the “Indentures”), among the Company, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The Company has certain options to redeem up to 35% of the Notes at a certain redemption price based on a percentage of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to certain dates, the Company has the option to redeem some or all of the Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The Company estimates that the fair value of these options is immaterial at June 30, 2012.

9

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

The Indentures contain customary events of default, including:

• default in any payment of interest on any Note when due, continued for 30 days;

• default in the payment of principal or premium, if any, on any Note when due;

• failure by the Company to comply with its other obligations under the Indentures, in certain cases subject to notice and grace periods;

• payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the Indentures) in the aggregate principal amount of $10.0 million or more;

• certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the Indentures) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;

• failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary to pay certain final judgments aggregating in excess of $10.0 million within 60 days; and

• any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

Senior secured revolving line of credit. OP LLC, as parent, and OPNA, as borrower, entered into a credit agreement dated June 22, 2007 (as amended and restated, the “Amended Credit Facility”). The Amended Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. 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. On April 3, 2012, the Company entered into its sixth amendment to its Amended Credit Facility. This amendment added two new lenders to the bank group. All other terms and conditions of the Amended Credit Facility remained the same, including the October 6, 2016 maturity date and the $1 billion senior secured revolving line of credit. In connection with the sixth amendment, the semi-annual redetermination of the borrowing base was also completed on April 3, 2012, which resulted in the borrowing base of the Amended Credit Facility increasing from $350 million to $500 million. Effective April 20, 2012, the Company executed an agreement consenting to the resignation of BNP Paribas as the administrative agent and a lender under the Amended Credit Facility. Wells Fargo was appointed successor administrative agent and assumed the credit commitment of BNP Paribas. BNP Paribas remains as a counterparty for the Company’s commodity derivative instruments. In addition, on June 25, 2012, the Company’s lenders waived the mandatory reduction of the Company’s borrowing base that otherwise would have occurred as a result of the Company’s issuance of senior unsecured notes in July 2012 (see Note 13 – Subsequent Events).

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 domestic bank prime interest rate loan (defined in the Amended Credit Facility as an Alternate Based Rate or “ABR” loan). As of June 30, 2012, any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:

Ratio of Total Outstanding Borrowings to Borrowing Base	Applicable Margin for LIBOR Loans	Applicable Margin for ABR Loans
Less than .25 to 1	1.50%	0.00%
Greater than or equal to .25 to 1 but less than .50 to 1	1.75%	0.25%
Greater than or equal to .50 to 1 but less than .75 to 1	2.00%	0.50%
Greater than or equal to .75 to 1 but less than .90 to 1	2.25%	0.75%
Greater than .90 to 1 but less than or equal 1	2.50%	1.00%

10

An ABR loan may be repaid at any time before the scheduled maturity of the Amended Credit Facility upon the Company providing advance notification to the lenders under the Amended Credit Facility (the “Lenders”). Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum loan term is six months for LIBOR-based loans. Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms greater than three months in duration. At the end of a LIBOR loan term, the Amended Credit Facility allows the Company to elect to repay the borrowing, 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 0.375% annualized commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average 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 derivative financial instruments;

• a requirement that the Company not allow a ratio of Total Net 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 (as defined in the Amended Credit Facility) 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, 2012, the Company had no borrowings and no outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $500 million. The Company was in compliance with the financial covenants of the Amended Credit Facility as of June 30, 2012.

Deferred financing costs. As of June 30, 2012, the Company had $25.2 million of deferred financing costs related to the Amended Credit Facility and the senior unsecured notes. The deferred financing costs are included in deferred costs and other assets on the Company’s Condensed Consolidated Balance Sheet at June 30, 2012 and are being amortized over the respective terms of the Amended Credit Facility and the senior unsecured notes. The amortization of these deferred financing costs is included in interest expense on the Company’s Condensed Consolidated Statement of Operations.

8. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2012:

	(In thousands)
Balance at December 31, 2011	$	13,075
Liabilities incurred during period		2,812
Liabilities settled during period		—
Accretion expense during period (1)		389
Revisions to estimates		984
Balance at June 30, 2012	$	17,260

(1) Included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statement of Operations.

At June 30, 2012, the current portion of the total ARO balance was approximately $0.3 million and is included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

11

9. Income Taxes

The Company’s effective tax rate for the three and six months ended June 30, 2012 was 37.4%, and the Company’s effective tax rate for the three and six months ended June 30, 2011 was 37.8%, which were consistent with the statutory tax rate applicable to the U.S. and the blended state rate for the states in which the Company conducts business. As of June 30, 2012, the Company did not have any uncertain tax positions requiring adjustments to its tax liability.

The Company had deferred tax assets for its federal and state tax loss carryforwards at June 30, 2012 recorded in non-current deferred taxes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of June 30, 2012, management determined that a valuation allowance was not required for the tax loss carryforwards as they are expected to be fully utilized before expiration.

10. Earnings Per Share

Basic earnings 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 per share includes the impact of potentially dilutive non-vested restricted shares outstanding during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income available to common stockholders in the calculation of diluted earnings per share.

The following is a calculation of the basic and diluted weighted-average shares outstanding for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands)				(In thousands)
Basic weighted average common shares outstanding		92,176		92,048		92,153		92,047
Dilution effect of stock awards at end of period		46		103		186		130
Diluted weighted average common shares outstanding		92,222		92,151		92,339		92,177
Anti-dilutive stock-based compensation awards		634		272		397		173

11. Commitments and Contingencies

Lease obligations. The Company’s total rental commitments under leases for office space and other property and equipment at June 30, 2012 were $14.7 million.

Drilling contracts. As of June 30, 2012, the Company had certain drilling rig contracts with initial terms greater than one year. In the event of early contract termination under these contracts, the Company would be obligated to pay approximately $58.5 million as of June 30, 2012 for the days remaining through the end of the primary terms of the contracts.

Volume commitment agreements. As of June 30, 2012, the Company had certain agreements with an aggregate requirement to deliver a minimum quantity of approximately 21.2 MMBbl and 16.5 Bcf from its Williston Basin project areas within a specified timeframe. Future obligations under these agreements were approximately $73.4 million as of June 30, 2012.

Fracturing services. As of June 30, 2012, the Company had certain agreements with third party fracturing service companies for an initial term greater than one year. In the event of early contract termination under these agreements, the Company would be obligated to pay approximately $31.4 million as of June 30, 2012 for the months remaining through the end of the primary terms of these agreements.

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

12. Condensed Consolidating Financial Information

The 2019 Notes and the 2021 Notes (see Note 7) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s immaterial wholly owned subsidiaries do not guarantee the Notes (“Non-Guarantor Subsidiaries”).

12

The following financial information reflects consolidating financial information of the Company (“Issuer”) and its Guarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors. The consolidating statement of cash flows for the six months ended June 30, 2011 includes a revision in presentation in the Issuer column, which increased cash flows from operating activities by $34.4 million and reduced cash flows from financing activities by the same amount. These revisions are eliminated in consolidation and have no effect on the Guarantors or consolidated financial statements.

Condensed Consolidating Balance Sheet

(In thousands, except share data)

	June 30, 2012
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	195,660		$	43,226		$	—		$	238,886
Accounts receivable – oil and gas revenues		—			79,478			—			79,478
Accounts receivable – joint interest partners		—			66,794			—			66,794
Accounts receivable – from affiliates		266			3,361			(3,627	)		—
Inventory		—			19,550			—			19,550
Prepaid expenses		63			611			—			674
Advances to joint interest partners		—			1,957			—			1,957
Derivative instruments		—			35,257			—			35,257
Other current assets		1			—			—			1
Total current assets		195,990			250,234			(3,627	)		442,597
Property, plant and equipment
Oil and gas properties (successful efforts method)		—			1,769,570			—			1,769,570
Other property and equipment		—			41,333			—			41,333
Less: accumulated depreciation, depletion, amortization and impairment		—			(261,529	)		—			(261,529	)
Total property, plant and equipment, net		—			1,549,374			—			1,549,374
Investments in and advances to subsidiaries		1,313,402			—			(1,313,402	)		—
Derivative instruments		—			18,167			—			18,167
Deferred income taxes		24,980			—			(24,980	)		—
Deferred costs and other assets		22,132			4,100			—			26,232
Total assets	$	1,556,504		$	1,821,875		$	(1,342,009	)	$	2,036,370
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	—		$	1,010		$	—		$	1,010
Accounts payable – from affiliates		3,361			266			(3,627	)		—
Advances from joint interest partners		—			28,444			—			28,444
Revenues and production taxes payable		—			56,795			—			56,795
Accrued liabilities		7,312			230,382			—			237,694
Accrued interest payable		16,417			10			—			16,427
Deferred income taxes		—			11,780			—			11,780
Other current liabilities		—			2,895			—			2,895
Total current liabilities		27,090			331,582			(3,627	)		355,045
Long-term debt		800,000			—			—			800,000
Asset retirement obligations		—			16,982			—			16,982
Deferred income taxes		—			158,158			(24,980	)		133,178
Other liabilities		—			1,751			—			1,751
Total liabilities		827,090			508,473			(28,607	)		1,306,956
Stockholders’ equity
Capital contributions from affiliates		—			1,183,810			(1,183,810	)		—
Common stock, $0.01 par value; 300,000,000 shares authorized; 93,185,023 issued and 93,122,353 outstanding		922			—			—			922
Treasury stock, at cost; 62,670 shares		(1,808	)		—			—			(1,808	)
Additional paid-in-capital		651,271			8,743			(8,743	)		651,271
Retained earnings		79,029			120,849			(120,849	)		79,029
Total stockholders’ equity		729,414			1,313,402			(1,313,402	)		729,414
Total liabilities and stockholders’ equity	$	1,556,504		$	1,821,875		$	(1,342,009	)	$	2,036,370

13

Condensed Consolidating Balance Sheet

(In thousands, except share data)

	December 31, 2011
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	443,482		$	27,390		$	—		$	470,872
Short-term investments		19,994			—			—			19,994
Accounts receivable – oil and gas revenues		—			52,164			—			52,164
Accounts receivable – joint interest partners		—			67,268			—			67,268
Accounts receivable – from affiliates		88			1,540			(1,628	)		—
Inventory		—			3,543			—			3,543
Prepaid expenses		309			1,831			—			2,140
Advances to joint interest partners		—			3,935			—			3,935
Deferred income taxes		—			3,233			—			3,233
Other current assets		18			473			—			491
Total current assets		463,891			161,377			(1,628	)		623,640
Property, plant and equipment
Oil and gas properties (successful efforts method)		—			1,235,357			—			1,235,357
Other property and equipment		—			20,859			—			20,859
Less: accumulated depreciation, depletion, amortization and impairment		—			(176,261	)		—			(176,261	)
Total property, plant and equipment, net		—			1,079,955			—			1,079,955
Investments in and advances to subsidiaries		958,880			—			(958,880	)		—
Derivative instruments		—			4,362			—			4,362
Deferred income taxes		13,158			—			(13,158	)		—
Deferred costs and other assets		15,742			3,683			—			19,425
Total assets	$	1,451,671		$	1,249,377		$	(973,666	)	$	1,727,382
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	23		$	12,184		$	—		$	12,207
Accounts payable – from affiliates		1,540			88			(1,628	)		—
Advances from joint interest partners		—			9,064			—			9,064
Revenues and production taxes payable		—			19,468			—			19,468
Accrued liabilities		103			119,589			—			119,692
Accrued interest payable		15,767			7			—			15,774
Derivative instruments		—			5,907			—			5,907
Other current liabilities		—			472			—			472
Total current liabilities		17,433			166,779			(1,628	)		182,584
Long-term debt		800,000			—			—			800,000
Asset retirement obligations		—			13,075			—			13,075
Derivative instruments		—			3,505			—			3,505
Deferred income taxes		—			106,141			(13,158	)		92,983
Other liabilities		—			997			—			997
Total liabilities		817,433			290,497			(14,786	)		1,093,144
Stockholders’ equity
Capital contributions from affiliates		—			941,575			(941,575	)		—
Common stock, $0.01 par value; 300,000,000 shares authorized; 92,483,393 issued and 92,460,914 outstanding		921			—			—			921
Treasury stock, at cost; 22,479 shares		(602	)		—			—			(602	)
Additional paid-in-capital		647,374			8,743			(8,743	)		647,374
Retained earnings (deficit)		(13,455	)		8,562			(8,562	)		(13,455	)
Total stockholders’ equity		634,238			958,880			(958,880	)		634,238
Total liabilities and stockholders’ equity	$	1,451,671		$	1,249,377		$	(973,666	)	$	1,727,382

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Condensed Consolidating Statement of Operations

(In thousands)

	Three Months Ended June 30, 2012
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil and gas revenues	$	—		$	145,203		$	—		$	145,203
Well services revenues		—			3,861			—			3,861
Total revenues		—			149,064			—			149,064
Expenses
Lease operating expenses		—			12,029			—			12,029
Well services operating expenses		—			1,207			—			1,207
Marketing, transportation and gathering expenses		—			1,970			—			1,970
Production taxes		—			13,720			—			13,720
Depreciation, depletion and amortization		—			44,213			—			44,213
Impairment of oil and gas properties		—			2,203			—			2,203
General and administrative expenses		2,644			10,893			—			13,537
Total expenses		2,644			86,235			—			88,879
Operating income (loss)		(2,644	)		62,829			—			60,185
Other income (expense)
Equity in earnings in subsidiaries		86,024			—			(86,024	)		—
Net gain on derivative instruments		—			74,595			—			74,595
Interest expense		(13,414	)		(660	)		—			(14,074	)
Other income		118			658			—			776
Total other income (expense)		72,728			74,593			(86,024	)		61,297
Income before income taxes		70,084			137,422			(86,024	)		121,482
Income tax benefit (expense)		5,959			(51,398	)		—			(45,439	)
Net income	$	76,043		$	86,024		$	(86,024	)	$	76,043

Condensed Consolidating Statement of Operations

(In thousands)

	Three Months Ended June 30, 2011
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Oil and gas revenues	$	—		$	67,206		$	—		$	67,206
Expenses
Lease operating expenses		—			5,951			—			5,951
Marketing, transportation and gathering expenses		—			247			—			247
Production taxes		—			7,085			—			7,085
Depreciation, depletion and amortization		—			13,100			—			13,100
Exploration expenses		—			259			—			259
Impairment of oil and gas properties		—			1,536			—			1,536
General and administrative expenses		1,318			5,296			—			6,614
Total expenses		1,318			33,474			—			34,792
Operating income (loss)		(1,318	)		33,732			—			32,414
Other income (expense)
Equity in earnings in subsidiaries		37,557			—			(37,557	)		—
Net gain on derivative instruments		—			27,547			—			27,547
Interest expense		(6,473	)		(288	)		—			(6,761	)
Other income		371			8			—			379
Total other income (expense)		31,455			27,267			(37,557	)		21,165
Income before income taxes		30,137			60,999			(37,557	)		53,579
Income tax benefit (expense)		3,212			(23,442	)		—			(20,230	)
Net income	$	33,349		$	37,557		$	(37,557	)	$	33,349

15

Condensed Consolidating Statement of Operations

(In thousands)

	Six Months Ended June 30, 2012
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues
Oil and gas revenues	$	—		$	283,109		$	—		$	283,109
Well services revenues		—			4,521			—			4,521
Total revenues		—			287,630			—			287,630
Expenses
Lease operating expenses		—			21,845			—			21,845
Well services operating expenses		—			1,684			—			1,684
Marketing, transportation and gathering expenses		—			4,539			—			4,539
Production taxes		—			26,986			—			26,986
Depreciation, depletion and amortization		—			83,099			—			83,099
Exploration expenses		—			2,835			—			2,835
Impairment of oil and gas properties		—			2,571			—			2,571
General and administrative expenses		5,090			20,646			—			25,736
Total expenses		5,090			164,205			—			169,295
Operating income (loss)		(5,090	)		123,425			—			118,335
Other income (expense)
Equity in earnings in subsidiaries		112,286			—			(112,286	)		—
Net gain on derivative instruments		—			56,009			—			56,009
Interest expense		(26,829	)		(1,144	)		—			(27,973	)
Other income		295			1,079			—			1,374
Total other income (expense)		85,752			55,944			(112,286	)		29,410
Income before income taxes		80,662			179,369			(112,286	)		147,745
Income tax benefit (expense)		11,822			(67,083	)		—			(55,261	)
Net income	$	92,484		$	112,286		$	(112,286	)	$	92,484

Condensed Consolidating Statement of Operations

(In thousands)

	Six Months Ended June 30, 2011
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Oil and gas revenues	$	—		$	125,950		$	—		$	125,950
Expenses
Lease operating expenses		—			11,581			—			11,581
Marketing, transportation and gathering expenses		—			559			—			559
Production taxes		—			13,168			—			13,168
Depreciation, depletion and amortization		—			26,912			—			26,912
Exploration expenses		—			291			—			291
Impairment of oil and gas properties		—			2,917			—			2,917
General and administrative expenses		2,581			9,983			—			12,564
Total expenses		2,581			65,411			—			67,992
Operating income (loss)		(2,581	)		60,539			—			57,958
Other income (expense)
Equity in earnings in subsidiaries		34,387			—			(34,387	)		—
Net loss on derivative instruments		—			(4,119	)		—			(4,119	)
Interest expense		(11,414	)		(545	)		—			(11,959	)
Other income		664			27			—			691
Total other income (expense)		23,637			(4,637	)		(34,387	)		(15,387	)
Income before income taxes		21,056			55,902			(34,387	)		42,571
Income tax benefit (expense)		5,446			(21,515	)		—			(16,069	)
Net income	$	26,502		$	34,387		$	(34,387	)	$	26,502

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Condensed Consolidating Statement of Cash Flows

(In thousands)

	Six Months Ended June 30, 2012
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	92,484		$	112,286		$	(112,286	)	$	92,484
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries		(112,286	)		—			112,286			—
Depreciation, depletion and amortization		—			83,099			—			83,099
Impairment of oil and gas properties		—			2,571			—			2,571
Deferred income taxes		(11,822	)		66,983			—			55,161
Derivative instruments		—			(56,009	)		—			(56,009	)
Stock-based compensation expenses		3,793			105			—			3,898
Debt discount amortization and other		960			305			—			1,265
Working capital and other changes:
Change in accounts receivable		(178	)		(28,661	)		1,999			(26,840	)
Change in inventory		—			(21,636	)		—			(21,636	)
Change in prepaid expenses		246			1,254			—			1,500
Change in other current assets		17			473			—			490
Change in other assets		(7,305	)		(60	)		—			(7,365	)
Change in accounts payable and accrued liabilities		9,657			32,364			(1,999	)		40,022
Change in other current liabilities		—			2,470			—			2,470
Change in other liabilities		—			750			—			750
Net cash provided by (used in) operating activities		(24,434	)		196,294			—			171,860
Cash flows from investing activities:
Capital expenditures		—			(440,781	)		—			(440,781	)
Derivative settlements		—			(2,465	)		—			(2,465	)
Redemptions of short-term investments		19,994			—			—			19,994
Advances to joint interest partners		—			1,978			—			1,978
Advances from joint interest partners		—			19,380			—			19,380
Net cash provided by (used in) investing activities		19,994			(421,888	)		—			(401,894	)
Cash flows from financing activities:
Purchases of treasury stock		(1,206	)		—			—			(1,206	)
Debt issuance costs		(46	)		(700	)		—			(746	)
Investment in / capital contributions from affiliates		(242,130	)		242,130			—			—
Net cash provided by (used in) financing activities		(243,382	)		241,430			—			(1,952	)
Increase (decrease) in cash and cash equivalents		(247,822	)		15,836			—			(231,986	)
Cash and cash equivalents at beginning of period		443,482			27,390			—			470,872
Cash and cash equivalents at end of period	$	195,660		$	43,226		$	—		$	238,886

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Condensed Consolidating Statement of Cash Flows

(In thousands)

	Six Months Ended June 30, 2011
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	26,502		$	34,387		$	(34,387	)	$	26,502
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries		(34,387	)		—			34,387			—
Depreciation, depletion and amortization		—			26,912			—			26,912
Impairment of oil and gas properties		—			2,917			—			2,917
Deferred income taxes		(5,446	)		21,515			—			16,069
Derivative instruments		—			4,119			—			4,119
Stock-based compensation expenses		1,571			—			—			1,571
Debt discount amortization and other		489			159			—			648
Working capital and other changes:
Change in accounts receivable		—			(20,940	)		995			(19,945	)
Change in inventory		—			(65	)		—			(65	)
Change in prepaid expenses		(382	)		128			—			(254	)
Change in other current assets		(211	)		—			—			(211	)
Change in other assets		(100	)		(3	)		—			(103	)
Change in accounts payable and accrued liabilities		13,013			31,594			(995	)		43,612
Change in other liabilities		—			323			—			323
Net cash provided by operating activities		1,049			101,046			—			102,095
Cash flows from investing activities:
Capital expenditures		—			(212,267	)		—			(212,267	)
Derivative settlements		—			(4,652	)		—			(4,652	)
Purchases of short-term investments		(164,913	)		—			—			(164,913	)
Redemptions of short-term investments		39,974			—			—			39,974
Advances to joint interest partners		—			983			—			983
Advances from joint interest partners		—			5,851			—			5,851
Net cash used in investing activities		(124,939	)		(210,085	)		—			(335,024	)
Cash flows from financing activities:
Proceeds from issuance of senior notes		400,000			—			—			400,000
Purchases of treasury stock		(559	)		—			—			(559	)
Debt issuance costs		(9,650	)		(377	)		—			(10,027	)
Investment in / capital contributions from affiliates		(111,078	)		111,078			—			—
Net cash provided by financing activities		278,713			110,701			—			389,414
Increase in cash and cash equivalents		154,823			1,662			—			156,485
Cash and cash equivalents at beginning of period		119,940			23,580			—			143,520
Cash and cash equivalents at end of period	$	274,763		$	25,242		$	—		$	300,005

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.

Senior unsecured notes. On July 2, 2012, the Company issued $400 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes”). Interest is payable on the 2023 Notes semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2013. The 2023 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s existing material subsidiaries. The issuance of the 2023 Notes resulted in net proceeds to the Company of approximately $392 million, which the Company will use to fund its exploration, development and acquisition program and for general corporate purposes. The issuance and sale of the 2023 Notes has been registered under the Securities Act of 1933 pursuant to an automatic shelf Registration Statement on Form S-3 (Registration No. 333-175603), as amended, of the Company, filed with the SEC on July 15, 2011.

Derivative instruments. In July 2012, the Company entered into new two-way costless collar options, all of which settle monthly based on the West Texas Intermediate crude oil index price, for a total notional amount of 183,000 barrels in 2012, 1,215,500 barrels in 2013 and 108,500 barrels in 2014. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.

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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 of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, 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 under Item 1A. “Risk Factors” in our 2011 Annual Report and in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012, 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;

• estimated future net reserves and present value thereof;

• technology;

• cash flows and liquidity;

• our financial strategy, budget, projections, execution of business plan and operating results;

• oil and natural gas realized prices;

• timing and amount of future production of oil and natural gas;

• availability of drilling, completion and production equipment and materials;

• availability of qualified personnel;

• owning and operating a services company;

• the amount, nature and timing of capital expenditures;

• availability and terms of capital;

• property acquisitions;

• costs of exploiting and developing our properties and conducting other operations;

• drilling and completion of wells;

• infrastructure for salt water disposal;

• gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and domestically;

• general economic conditions;

• operating environment, including inclement weather conditions;

• competition in the oil and natural gas industry;

• effectiveness of risk management activities;

• environmental liabilities;

• counterparty credit risk;

• governmental regulation and the taxation of the oil and natural gas industry;

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• developments in oil-producing and natural gas-producing countries;

• uncertainty regarding future operating results; and

• plans, objectives, expectations and intentions contained in this report that are not historical.

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law, and 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 on Form 10-Q 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 on Form 10-Q, 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 Montana and North Dakota regions of the Williston Basin. Since our inception, we have acquired 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 and Three Forks formations. We also operate businesses that are complementary to our primary development and production activities, including a marketing business, Oasis Petroleum Marketing LLC (“OPM”), and a well services business, Oasis Well Services LLC (“OWS”). The revenues and expenses related to work performed by OPM and OWS for Oasis Petroleum North America LLC’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.

Due to the geographic concentration of our oil and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:

• Commodity prices for oil and natural gas;

• Transportation capacity;

• Availability and cost of services; and

• Availability of qualified personnel.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations. We enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity, utilize derivative financial instruments to manage our commodity price risk, and enter into physical delivery contracts to manage our price differentials. In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, during the first and second quarters of 2012, we began to actively increase the number of operated wells that we have connected to a third-party oil gathering system in our West Williston project area. At the end of June 2012, the Company had 94 operated wells connected, up from only three operated wells that were connected at the beginning of 2012. We currently flow approximately 60% of our gross operated oil production on the third-party oil gathering system.

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Changes in commodity prices may also significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. Oil prices have increased significantly since 2009. As a result of higher commodity prices and continued successes in the application of completion technologies in the Bakken formation, there were more than 225 active drilling rigs in the Williston Basin at June 30, 2012. Although additional Williston Basin transportation takeaway capacity was added in recent months, production also increased due to the elevated drilling activity. The increased production coupled with the refinery and transportation constraints caused price differentials in the first and second quarters of 2012 to be at and above the high end of the historical average range of approximately 10% to 15% of the price quoted for NYMEX West Texas Intermediate (“WTI”) crude oil.

Our large concentrated acreage position potentially provides us with a multi-year inventory of drilling projects and requires some forward planning visibility for obtaining services. Our ability to develop and hold our existing undeveloped leasehold acreage is primarily dependent upon having access to drilling rigs and completion services. The utilization of existing drilling rigs and of existing completion service equipment in the Williston Basin is at an all-time high. This has resulted in drilling rigs, completion equipment and crews being imported from Canada and other parts of the United States. To ensure access to drilling rigs, we have entered into fixed-term drilling rig contracts for periods of up to three years and currently have ten drilling rigs under contract. In order to ensure the availability of completion services and the timely fracture stimulation of newly drilled wells, we formed OWS in June 2011 to provide well services on our operated wells, in addition to entering into fracturing service contracts with third party companies.

Second Quarter 2012 Highlights:

• We completed and placed on production 26 gross (20.3 net) operated wells in the Williston Basin during the three months ended June 30, 2012;

• We had 30 gross (24.1 net) operated wells awaiting completion and 9 gross (7.4 net) operated wells in the process of being drilled in the Bakken and Three Forks formations at June 30, 2012;

• Average daily production was 20,353 Boe per day during the three months ended June 30, 2012;

• Net gas production increased to 11.2 MMcfpd during the three months ended June 30, 2012 due to connecting additional wells in the Williston Basin to third-party infrastructure;

• Exploration and production (“E&P”) capital expenditures were $263.2 million, consisting primarily of $243.4 million in drilling expenditures during the three months ended June 30, 2012;

• At June 30, 2012, we had $238.9 million of cash and cash equivalents and had no outstanding debt or outstanding letters of credit under our revolving credit facility; and

• On June 27, 2012, we priced an offering of $400 million of 6.875% senior unsecured notes due January 15, 2023. The issuance closed on July 2, 2012, resulting in net proceeds to us of approximately $392 million.

Results of Operations

Revenues

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

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

	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
Operating results (in thousands):
Revenues
Oil	$	138,559	$	65,400	$	73,159		$	269,935	$	122,572	$	147,363
Natural gas		6,644		1,806		4,838			13,174		3,378		9,796
Well services		3,861		—		3,861			4,521		—		4,521
Total oil and gas revenues		149,064		67,206		81,858			287,630		125,950		161,680
Production data:
Oil (MBbls)		1,682		685		997			3,156		1,379		1,777
Natural gas (MMcf)		1,019		200		819			1,803		402		1,401
Oil equivalents (MBoe)		1,852		718		1,134			3,457		1,446		2,011
Average daily production (Boe/d)		20,353		7,893		12,460			18,993		7,991		11,002
Average sales prices:
Oil, without realized derivatives (per Bbl) (1)	$	82.36	$	95.48	$	(13.12	)	$	85.04	$	88.86	$	(3.82	)
Oil, with realized derivatives (per Bbl) (1) (2)		81.67		89.43		(7.76	)		84.26		85.49		(1.23	)
Natural gas (per Mcf) (3)		6.52		9.05		(2.53	)		7.30		8.41		(1.11	)

(1) For the six months ended June 30, 2012, average sales prices for oil are calculated using total oil revenues, excluding bulk purchase sales of $1.5 million, divided by oil production.

(2) Realized prices include realized gains or losses on cash settlements for commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes.

(3) Natural gas prices include the value for natural gas and natural gas liquids.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

Total revenues. Our total revenues increased $81.9 million, or 122%, to $149.1 million during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 12,460 Boe per day, or 158%, to 20,353 Boe per day during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. The increase in average daily production sold was primarily a result of our well completions during the last two quarters of 2011 and the first two quarters of 2012. Well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 9,266 Boe per day, 2,584 Boe per day and 712 Boe per day, respectively, during the second quarter of 2012 as compared to the second quarter of 2011. Average oil sales prices, without realized derivatives, decreased by $13.12/Bbl, or 14%, to an average of $82.36/Bbl for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. The higher production amounts sold increased revenues by $87.5 million, while lower oil and natural gas sales prices decreased revenues by $9.5 million during the three months ended June 30, 2012. The remaining $3.9 million increase in total revenues was attributable to well services revenues during the three months ended June 30, 2012. There were no well services revenues during the second quarter of 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Six months ended June 30, 2012 as compared to six months ended June 30, 2011

Total revenues. Our total revenues increased $161.7 million, or 128%, to $287.6 million during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 11,002 Boe per day, or 138%, to 18,993 Boe per day during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. The increase in average daily production sold was primarily a result of our well completions during the last two quarters of 2011 and the first two quarters of 2012. Well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 8,542 Boe per day, 2,043 Boe per day and 451 Boe per day, respectively, during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. Average oil sales prices, without realized derivatives, decreased by $3.82/Bbl, or 4%, to an average of $85.04/Bbl for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. The higher production amounts sold increased revenues by $161.3 million, while lower oil and natural gas sales prices decreased revenues by $5.7 million during the six months ended June 30, 2012. Well services revenues were $4.5 million for the six months ended June 30, 2012 compared to no well services revenues during the six months ended June 30, 2011 because OWS did not commence fracturing activity until the first quarter of 2012. The remaining $1.5 million increase in total revenues was attributable to oil bulk purchase revenues related to marketing activities included in oil and gas revenues during the six months ended June 30, 2012.

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Expenses

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

	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			$ Change			2012			2011			$ Change
	(In thousands, except per Boe of production)
Expenses:
Lease operating expenses	$	12,029		$	5,951		$	6,078		$	21,845		$	11,581		$	10,264
Well services operating expenses		1,207			—			1,207			1,684			—			1,684
Marketing, transportation and gathering expenses		1,970			247			1,723			4,539			559			3,980
Production taxes		13,720			7,085			6,635			26,986			13,168			13,818
Depreciation, depletion and amortization		44,213			13,100			31,113			83,099			26,912			56,187
Exploration expenses		—			259			(259	)		2,835			291			2,544
Impairment of oil and gas properties		2,203			1,536			667			2,571			2,917			(346	)
General and administrative expenses		13,537			6,614			6,923			25,736			12,564			13,172
Total expenses	$	88,879		$	34,792		$	54,087		$	169,295		$	67,992		$	101,303
Operating income (loss)		60,185			32,414			27,771			118,335			57,958			60,377
Other income (expense):
Net gain (loss) on derivative instruments		74,595			27,547			47,048			56,009			(4,119	)		60,128
Interest expense		(14,074	)		(6,761	)		(7,313	)		(27,973	)		(11,959	)		(16,014	)
Other income		776			379			397			1,374			691			683
Total other income (expense)		61,297			21,165			40,132			29,410			(15,387	)		44,797
Income before income taxes		121,482			53,579			67,903			147,745			42,571			105,174
Income tax expense		45,439			20,230			25,209			55,261			16,069			39,192
Net income (loss)	$	76,043		$	33,349		$	42,694		$	92,484		$	26,502		$	65,982
Cost and expense (per Boe of production):
Lease operating expenses (1)	$	6.49		$	8.29		$	(1.80	)	$	6.32		$	8.00		$	(1.68	)
Marketing, transportation and gathering expenses		1.06			0.34			0.72			1.31			0.39			0.92
Production taxes		7.41			9.86			(2.45	)		7.81			9.10			(1.29	)
Depreciation, depletion and amortization		23.87			18.24			5.63			24.04			18.61			5.43
General and administrative expenses (2)		7.31			9.21			(1.90	)		7.45			8.69			(1.24	)

(1) For the three and six months ended June 30, 2011, lease operating expenses excludes marketing, transportation and gathering expenses to conform such amount to current year classifications.

(2) Includes $1.1 million and $2.7 million of expenses related to OWS for the three and six months ended June 30, 2012, respectively. Excluding OWS, E&P only G&A would be $6.71 and $6.66 per Boe for the three and six months ended June 30, 2012, respectively.

Three months ended June 30, 2012 compared to three months ended June 30, 2011

Lease operating expenses. Lease operating expenses increased $6.1 million to $12.0 million for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. This increase was due to an increased number of producing wells and increased workover expenses period over period. The unit operating costs decreased from $8.29 per Boe for the three months ended June 30, 2011 to $6.49 per Boe for the three months ended June 30, 2012, as a result of operational efficiency and lower salt water disposal (“SWD”) costs.

We have $74 million in our 2012 capital budget primarily allocated to building SWD infrastructure, which is currently being deployed in our key operating areas. This infrastructure is expected to reduce our dependence on trucks for water hauling and simplify operational logistics. As of June 30, 2012, we had approximately 30% of operated water production flowing through our operated pipeline system. We expect to have approximately 80% of operated water production flowing through the pipeline system by year-end 2012. Additionally, we currently dispose of approximately 60% of our operated water production at our operated disposal wells. This continued expansion of our SWD systems is expected to reduce lease operating expenses throughout the remainder of 2012.

Well services operating expenses. The $1.2 million in well services operating expenses represents non-affiliated fracturing service costs incurred by OWS for fracturing jobs completed in the second quarter of 2012. There were no well services operating expenses during the second quarter of 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Marketing, transportation and gathering expenses. This line item includes all of our marketing, transportation and gathering for our oil production as well as bulk oil purchase costs. The $1.7 million increase quarter over quarter, or $0.72 increase per Boe, is mainly attributable to increased oil transportation costs related to OPM, which did not commence operations until the third quarter of 2011.

Production taxes. Our production taxes for the three months ended June 30, 2012 and 2011 were 9.5% and 10.5%, respectively, as a percentage of oil and natural gas sales. The second quarter 2012 production tax rate was lower than the second quarter 2011 production tax rate primarily due to certain new wells in Montana that are subject to lower incentivized production tax rates.

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Depreciation, depletion and amortization (DD&A). DD&A expense increased $31.1 million to $44.2 million for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. This increase in DD&A expense for the three months ended June 30, 2012 was primarily a result of our production increases from our well completions during the last two quarters of 2011 and the first two quarters of 2012. The DD&A rate for the three months ended June 30, 2012 was $23.87 per Boe compared to $18.24 per Boe for the three months ended June 30, 2011. The higher DD&A rate was due to a greater increase in well costs over an increase in reserves.

Impairment of oil and gas properties. During the three months ended June 30, 2012 and 2011, we recorded non-cash impairment charges of $2.2 million and $1.5 million, respectively, for unproved property leases that expired during the period or have been forecasted to expire under our current drilling plans. No impairment charges of proved oil and gas properties were recorded for the three months ended June 30, 2012 or 2011.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $6.9 million for the three months ended June 30, 2012 from $6.6 million for the three months ended June 30, 2011. Of this increase, approximately $6.0 million related to employee compensation expenses due to our organizational growth, including the addition of OWS, and $1.3 million was due to additional amortization of our restricted stock awards during the three months ended June 30, 2012. As of June 30, 2012, we had 223 full-time employees compared to 88 full-time employees as of June 30, 2011. Excluding G&A expenses related to OWS of $1.1 million, G&A related to E&P on a per Boe basis would have been $6.71 in the second quarter of 2012.

Derivative instruments. As a result of our derivative activities, we incurred cash settlement net losses of $1.2 million and $4.1 million for the three months ended June 30, 2012 and 2011, respectively. In addition, as a result of forward oil price changes, we recognized a $75.8 million and a $31.7 million non-cash unrealized mark-to-market net derivative gain during the three months ended June 30, 2012 and 2011, respectively.

Interest expense. Interest expense increased $7.3 million to $14.1 million for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. The increase was primarily the result of interest expense incurred on our senior unsecured notes issued in November 2011 at an interest rate of 6.5%. There were no borrowings under our revolving credit facility during the three months ended June 30, 2012 and 2011, respectively.

Income taxes. Income tax expense for the three months ended June 30, 2012 and 2011 was recorded at 37.4% and 37.8% of pre-tax net income, respectively. Our effective tax rate is expected to continue to closely approximate the statutory rate applicable to the U.S. and the blended state rate of the states in which we conduct business.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Lease operating expenses. Lease operating expenses increased $10.3 million to $21.8 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. This increase was due to an increased number of producing wells and increased workover expenses period over period. The unit operating costs decreased from $8.00 per Boe for the six months ended June 30, 2011 to $6.32 per Boe for the six months ended June 30, 2012, as a result of operational efficiency and lower SWD costs.

Well services operating expenses. The $1.7 million in well services operating expenses represents non-affiliated fracturing service costs incurred by OWS for fracturing jobs completed in 2012. There were no well services operating expenses in 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Marketing, transportation and gathering expenses. This line item includes all of our marketing, transportation and gathering for our oil production as well as bulk oil purchase costs. The $4.0 million increase period over period, or $0.92 increase per Boe, is mainly attributable to increased oil transportation costs related to OPM, which did not commence operations until the third quarter of 2011.

Production taxes. Our production taxes for the six months ended June 30, 2012 and 2011 were 9.6% and 10.5%, respectively, as a percentage of oil and natural gas sales. The production tax rate for the six months ended June 30, 2012 was lower than the production tax rate for the six months ended June 30, 2011 primarily due to certain new wells in Montana that are subject to lower incentivized production tax rates.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $56.2 million to $83.1 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. This increase in DD&A expense for the six months ended June 30, 2012 was primarily a result of our production increases from our well completions during the last two quarters of 2011 and the first two quarters of 2012. The DD&A rate for the six months ended June 30, 2012 was $24.04 per Boe compared to $18.61 per Boe for the six months ended June 30, 2011. The higher DD&A rate was due to a greater increase in well costs over an increase in reserves.

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Exploration expenses. The $2.5 million increase in exploration expenses to $2.8 million for the six months ended June 30, 2012 is primarily due to geological and geophysical costs for the purchase of 3D seismic data.

Impairment of oil and gas properties. During the six months ended June 30, 2012 and 2011, we recorded non-cash impairment charges of $2.6 million and $2.9 million, respectively, for unproved property leases that expired during the period or have been forecasted to expire under our current drilling plans. No impairment charges of proved oil and gas properties were recorded for the three months ended June 30, 2012 or 2011.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $13.2 million for the six months ended June 30, 2012 from $12.6 million for the six months ended June 30, 2011. Of this increase, approximately $9.9 million related to employee compensation expenses due to our organizational growth, including the addition of OWS, and $2.3 million was due to additional amortization of our restricted stock awards during the six months ended June 30, 2012. As of June 30, 2012, we had 223 full-time employees compared to 88 full-time employees as of June 30, 2011. Excluding G&A expenses related to OWS of $2.7 million, G&A related to E&P on a per Boe basis would have been $6.66 for the six months ended June 30, 2012.

Derivative instruments. As a result of our derivative activities, we incurred cash settlement net losses of $2.5 million and $4.7 million for the six months ended June 30, 2012 and 2011, respectively. In addition, as a result of forward oil price changes, we recognized a $58.5 million and a $0.5 million non-cash unrealized mark-to-market net derivative gain during the six months ended June 30, 2012 and 2011, respectively.

Interest expense. Interest expense increased $16.0 million to $28.0 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. The increase was primarily the result of interest expense incurred on our senior unsecured notes issued in February and November 2011 at interest rates of 7.25% and 6.5%, respectively. There were no borrowings under our revolving credit facility during the six months ended June 30, 2012 and 2011, respectively.

Income taxes. Income tax expense for the six months ended June 30, 2012 and 2011 was recorded at 37.4% and 37.8% of pre-tax net income, respectively. Our effective tax rate is expected to continue to closely approximate the statutory rate applicable to the U.S. and the blended state rate of the states in which we conduct business.

Liquidity and Capital Resources

Our primary sources of liquidity as of the date of this report have been proceeds from our issuances of senior unsecured notes, proceeds from our IPO in June 2010, cash flows from operations and historically, borrowings under our revolving credit facility and capital contributions from private investors. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Our cash flows for the six months ended June 30, 2012 and 2011 are presented below:

	Six Months Ended June 30,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	171,860		$	102,095
Net cash used in investing activities		(401,894	)		(335,024	)
Net cash (used in) provided by financing activities		(1,952	)		389,414
(Decrease) increase in cash and cash equivalents	$	(231,986	)	$	156,485

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 mitigate the change in oil prices on a portion of our production, thereby mitigating our exposure to oil price declines, but these transactions may also limit our cash flow in periods of rising oil prices.

Net cash provided by operating activities was $171.9 million and $102.1 million for the six months ended June 30, 2012 and 2011, respectively. The increase in cash flows provided by operating activities for the period ended June 30, 2012 as compared to 2011 was primarily the result of an increase in oil and natural gas production of 138%. In addition, at June 30, 2012, we had a working capital surplus of $87.6 million. This surplus was primarily attributable to our cash and cash equivalents balance as a result of the net proceeds from the issuance of our senior unsecured notes in 2011.

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Cash flows used in investing activities

Net cash used in investing activities was $401.9 million and $335.0 million during the six months ended June 30, 2012 and 2011, respectively. The increase in cash used in investing activities for the six months ended June 30, 2012 compared to 2011 of $66.9 million was mainly attributable to increased levels of capital expenditures for drilling and development costs.

Our capital expenditures for drilling, development and acquisition costs are summarized in the following table:

	Six Months Ended June 30, 2012
	(In thousands)
Project Area:
West Williston	$	391,975
East Nesson		106,617
Sanish		31,575
Total E&P capital expenditures		530,167
Non-E&P capital expenditures (1)		25,368
Total capital expenditures (2)	$	555,535

(1) Non-E&P capital expenditures include such items as equipment for OWS, district tools, administrative capital and capitalized interest.

(2) Capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include accrued liabilities for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.

On July 26, 2012, our Board of Directors increased our total 2012 capital expenditure budget from $884 million to $1,062 million, which now consists of:

• $912 million of development capital for operated and non-operated wells (including expected savings from services provided by OWS);

• $74 million for constructing infrastructure to support production in our core project areas, primarily related to SWD systems that will lower lease operating expenses;

• $30 million for maintaining and expanding our leasehold position;

• $6 million for micro-seismic work, purchase of seismic data and other test work;

• $17 million for OWS, including $12 million for equipment budgeted and ordered in 2011 that arrived in the first quarter of 2012; and

• $23 million for other non-E&P capital, including items such as district tools, administrative capital and capitalized interest.

The 2012 capital expenditure budget does not include approximately $30 million of capital that was related to 2011 activity that was included in the first quarter of 2012 actual capital expenditures. While we have budgeted $1,062 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. We believe that cash on hand, cash flows from operating activities and availability under our revolving credit facility should be more than sufficient to fund our 2012 capital expenditure budget. However, because the operated wells funded by our 2012 drilling plan represent only a small percentage of our gross identified drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of identified drilling locations should we elect to do so.

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.

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Cash flows used in or provided by financing activities

Net cash used in financing activities was $2.0 million for the six months ended June 30, 2012 compared to $389.4 million net cash provided by financing activities for the six months ended June 30, 2011. For the six months ended June 30, 2012, cash used in financing activities was primarily due to the purchases of treasury stock for shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards combined with deferred financing costs related to the semi-annual redetermination of our borrowing base under our senior secured revolving line of credit. For the six months ended June 30, 2011, cash sourced through financing activities was primarily provided by the net proceeds from the issuance of our senior unsecured notes in February 2011.

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

At any time prior to February 1, 2014, we may redeem up to 35% of the 2019 Notes at a redemption price of 107.25% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings as long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2019 Notes remains outstanding after such redemption. Prior to February 1, 2015, we may redeem some or all of the 2019 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after February 1, 2015, we may redeem some or all of the 2019 Notes at redemption prices (expressed as percentages of the principal amount) equal to 103.625% for the twelve-month period beginning on February 1, 2015, 101.813% for the twelve-month period beginning February 1, 2016 and 100.00% beginning on February 1, 2017, plus accrued and unpaid interest to the redemption date.

On November 10, 2011, we issued $400 million of 6.5% senior unsecured notes due November 1, 2021 (the “2021 Notes”). Interest is payable on the 2021 Notes semi-annually in arrears on each May 1 and November 1, commencing May 1, 2012. The 2021 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 2021 Notes resulted in net proceeds to us of approximately $393 million, which we are using to fund our exploration, development and acquisition program and for general corporate purposes.

At any time prior to November 1, 2014, we may redeem up to 35% of the 2021 Notes at a redemption price of 106.5% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings as long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2021 Notes remains outstanding after such redemption. Prior to November 1, 2016, we may redeem some or all of the 2021 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after November 1, 2016, we may redeem some or all of the 2021 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.25% for the twelve-month period beginning on November 1, 2016, 102.167% for the twelve-month period beginning on November 1, 2017, 101.083% for the twelve-month period beginning on November 1, 2018 and 100.00% beginning on November 1, 2019, plus accrued and unpaid interest to the redemption date. If a change in control occurs at any time on or prior to January 1, 2013, we may redeem all, but not less than all, of the 2021 Notes, at a redemption price equal to 110% of the principal amount plus accrued and unpaid interest to the redemption date.

On July 2, 2012, we issued $400 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes”). Interest is payable on the 2023 Notes semi-annually in arrears on each January 15 and July 15, commencing January 15, 2013. The 2021 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 2023 Notes resulted in net proceeds to us of approximately $392.4 million, which we are using to fund our exploration, development and acquisition program and for general corporate purposes.

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At any time prior to July 15, 2015, we may redeem up to 35% of the 2023 Notes at a redemption price of 106.875% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings as long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2023 Notes remains outstanding after such redemption. Prior to July 15, 2017, we may redeem some or all of the 2023 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after July 15, 2017, we may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on July 15, 2017, 102.292% for the twelve-month period beginning on July 15, 2018, 101.146% for the twelve-month period beginning on July 15, 2019 and 100.00% beginning on July 15, 2020, plus accrued and unpaid interest to the redemption date. If a change in control occurs at any time on or prior to July 15, 2013, we may redeem all, but not less than all, of the 2023 Notes, at a redemption price equal to 110% of the principal amount plus accrued and unpaid interest to the redemption date.

The indentures governing our 2019 Notes, 2021 Notes and 2023 Notes restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when our 2019 Notes, 2021 Notes or 2023 Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants.

Senior secured revolving line of credit. On April 3, 2012, we entered into a sixth amendment to our revolving credit facility. In connection with this amendment, the semi-annual redetermination of our borrowing base was completed on April 3, 2012, which resulted in an increase to the borrowing base of our revolving credit facility from $350 million to $500 million. Additionally, two new lenders were added to the bank group. Borrowings under our revolving 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. At our election, interest is generally determined by reference to (i) the London interbank offered rate, or LIBOR, plus an applicable margin between 1.50% and 2.50% per annum; or (ii) a domestic bank prime rate plus an applicable margin between 0.00% and 1.00% per annum.

As of June 30, 2012, we had no borrowings and no outstanding letters of credit under our revolving credit facility. The revolving credit facility also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders under our revolving credit facility may declare all amounts outstanding under our revolving credit facility to be immediately due and payable. As of June 30, 2012, we were in compliance with the financial covenants of our revolving credit facility.

Fair Value of Financial Instruments

See Note 5 to our unaudited condensed consolidated financial statements for a discussion of our money market funds and derivative instruments and their related fair value measurements. See also Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2011 Annual Report.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See Note 11 to our unaudited condensed consolidated financial statements for a description of our commitments and contingencies.

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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 2011 Annual Report, as well as with the unaudited condensed 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 exposure 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, 2012, we utilized put spreads, two-way collar options and three-way collar options to reduce the volatility of oil prices on a significant portion of our future expected oil production. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be WTI plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A put spread is a combination of a purchased put and a sold put, and in this case does not include a sold call, allowing the volumes under this contract to have no established maximum price (ceiling).

We recognize 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, 2012:

Settlement Period	Derivative Instrument	Total Notional Amount of Oil (Barrels)		Average Sub-Floor  Price		Average Floor Price		Average Ceiling Price		Fair Value Asset (Liability)
										(In thousands)
2012	Two-Way Collars		1,189,500			$	89.23	$	108.76	$	7,906
2012	Three-Way Collars		1,860,000	$	66.39	$	90.33	$	109.70		12,093
2013	Two-Way Collars		201,500			$	89.23	$	108.76		1,533
2013	Three-Way Collars		2,023,420	$	65.30	$	92.51	$	112.63		13,978
2013	Put Spreads		1,717,080	$	70.71	$	91.24				12,853
2014	Three-Way Collars		827,030	$	71.08	$	92.58	$	114.15		3,714
2014	Put Spreads		150,970	$	71.03	$	91.03				1,104
2015	Three-Way Collars		62,000	$	72.50	$	92.50	$	114.40		243
										$	53,424

Interest rate risk. We had (i) $400.0 million of senior unsecured notes at a fixed cash interest rate of 7.25% per annum and (ii) $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.5% per annum outstanding at June 30, 2012. During the first six months of 2012, we had no indebtedness outstanding under our revolving 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 issued under our revolving credit facility. Interest rate derivatives would be 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 choose 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. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions, most of which are lenders under our revolving credit facility. This risk is also managed by spreading our derivative exposure across several institutions and limiting the hedged volumes placed under individual contracts.

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While we do not require all of 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.

We may, from time to time, purchase commercial paper instruments from high credit quality counterparties. These counterparties may include issuers in a variety of industries including the domestic and foreign financial sector. Our investment policy requires that our counterparties have minimum credit ratings thresholds and provides maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers being unable to pay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If a commercial paper issuer is unable to return investment proceeds to us at the maturity date, it could take a significant amount of time to recover all or a portion of the assets originally invested. Our commercial paper balance was $15.0 million at June 30, 2012.

Most of the counterparties on our derivative instruments currently in place are lenders under our revolving credit facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under our revolving credit facility, which also carry investment grade ratings. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, 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. We had a net derivative asset position of $53.4 million at June 30, 2012.

Item 4. — Controls and Procedures

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 Chief Executive Officer (“CEO”), our principal executive officer; Chief Financial Officer (“CFO”), our principal financial officer; and Chief Accounting Officer (“CAO”), 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 June 30, 2012. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO, CFO and CAO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO, CFO and CAO have concluded that our disclosure controls and procedures were effective at June 30, 2012.

Changes in internal control over financial reporting. During the quarter ended June 30, 2012, we converted to a new accounting and land software system, which replaced our existing system. We have taken the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps included procedures to preserve the integrity of the data converted and a review by management to validate the data converted. Additionally, we provided training related to this system to individuals using the system to carry out their job responsibilities. We anticipate that the implementation of this software will strengthen the overall system of internal controls due to enhanced automation and integration of related processes. In conjunction with this system conversion, we also brought all of our outsourced accounting functions in-house. We have continued to hire additional accounting staff to support these functions. We are modifying the design and documentation of internal control processes and procedures relating to the new system and modules to supplement and complement existing internal control over certain respective job areas. The system change was undertaken to integrate systems and consolidate information and was not undertaken in response to any actual or perceived deficiencies in our internal control over financial reporting. Testing of the controls related to the new system and accounting functions is ongoing and is included in the scope of our assessment of our internal control over financial reporting for 2012.

We continue to evaluate the ongoing effectiveness and sustainability of the changes we have made in internal control, and, as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

See Part I, Item 1, Note 11 to our unaudited condensed 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.

There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2011 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012. For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2011 Annual Report and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012.

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

Unregistered sales of securities. There were no sales of unregistered equity securities during the period covered by this report.

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended June 30, 2012:

Period	Total Number of Shares Exchanged (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
April 1 – April 30, 2012		306	$	30.83		—		—
May 1 – May 31, 2012		306		33.30		—		—
June 1 – June 30, 2012		234		23.79		—		—
Total		846	$	29.78		—		—

(1) Represent shares that employees surrendered back to the Company that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of common stock.

Item 6. — Exhibits

Exhibit No.	Description of Exhibit
4.1	Second Supplemental Indenture dated as of July 2, 2012 among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on July 2, 2012, and incorporated herein by reference).
10.1	Sixth Amendment to Amended and Restated Credit Agreement, dated as of April 3, 2012, among Oasis Petroleum North America, as borrower, Oasis Petroleum LLC, Oasis Petroleum Marketing LLC, Oasis Well Services LLC and Oasis Petroleum Inc., as guarantors, BNP Paribas, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 5, 2012, and incorporated herein by reference).
10.2	April 20, 2012 Resignation, Consent and Appointment Agreement and Amendment Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 23, 2012, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.

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Exhibit No.	Description of Exhibit
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

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SIGNATURES

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

		OASIS PETROLEUM INC.
Date: August 7, 2012	By:	/s/ Thomas B. Nusz
		Thomas B. Nusz
		Chairman, President and Chief Executive Officer (Principal Executive Officer)
	By:	/s/ Michael H. Lou
		Michael H. Lou
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)
	By:	/s/ Roy W. Mace
		Roy W. Mace
		Senior Vice President, Chief Accounting Officer (Principal Accounting Officer)

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EXHIBIT INDEX

Exhibit No.	Description of Exhibit
4.1	Second Supplemental Indenture dated as of July 2, 2012 among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on July 2, 2012, and incorporated herein by reference).
10.1	Sixth Amendment to Amended and Restated Credit Agreement, dated as of April 3, 2012, among Oasis Petroleum North America, as borrower, Oasis Petroleum LLC, Oasis Petroleum Marketing LLC, Oasis Well Services LLC and Oasis Petroleum Inc., as guarantors, BNP Paribas, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 5, 2012, and incorporated herein by reference).
10.2	April 20, 2012 Resignation, Consent and Appointment Agreement and Amendment Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 23, 2012, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

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