CHRD 10-Q Quarterly Report Sept. 30, 2011

CHORD ENERGY CORP

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10-Q 1 c24214e10vq.htm 10-Q 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2011


o		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		(I.R.S. Employer Identification No.)
incorporation or organization)

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 þ No o

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 þ No o

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


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
		(Do not check if a 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 o No þ

Number of shares of the registrant’s common stock outstanding at November 8, 2011: 92,457,664 shares.

OASIS PETROLEUM INC.
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS


	Page

PART I — FINANCIAL INFORMATION		1

Item 1. — Financial Statements (Unaudited)		1

Condensed Consolidated Balance Sheet at September 30, 2011 and December 31, 2010		1

Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2011 and 2010		2

Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2011		3

Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		4

Notes to the Condensed Consolidated Financial Statements		5

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations		23

Item 3. — Quantitative and Qualitative Disclosures About Market Risk		34

Item 4. — Controls and Procedures		36

PART II — OTHER INFORMATION		37

Item 1. — Legal Proceedings		37

Item 1A. — Risk Factors		37

Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds		38

Item 6. — Exhibits		39

SIGNATURES		40

EXHIBIT INDEX		41

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Oasis Petroleum Inc.

Condensed Consolidated Balance Sheet

(Unaudited)


	September 30,			December 31,
	2011			2010
	(In thousands, except share
	data)
ASSETS
Current assets
Cash and cash equivalents	$	163,601		$	143,520
Short-term investments		124,939			—
Accounts receivable — oil and gas revenues		40,703			25,909
Accounts receivable — joint interest partners		55,115			28,596
Inventory		2,813			1,323
Prepaid expenses		817			490
Advances to joint interest partners		3,846			3,595
Derivative instruments		33,284			—
Deferred income taxes		—			2,470
Other current assets		337			—

Total current assets		425,455			205,903

Property, plant and equipment
Oil and gas properties (successful efforts method)		983,768			580,968
Other property and equipment		13,825			1,970
Less: accumulated depreciation, depletion, amortization and impairment		(148,121	)		(99,255	)

Total property, plant and equipment, net		849,472			483,683

Derivative instruments		28,166			—
Deferred costs and other assets		11,283			2,266

Total assets	$	1,314,376		$	691,852

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	43,825		$	8,198
Advances from joint interest partners		11,194			3,101
Revenues and production taxes payable		14,953			6,180
Accrued liabilities		82,386			58,239
Accrued interest payable		4,835			2
Derivative instruments		—			6,543
Deferred income taxes		11,684			—

Total current liabilities		168,877			82,263

Long-term debt		400,000			—
Asset retirement obligations		11,566			7,640
Derivative instruments		—			3,943
Deferred income taxes		86,291			45,432
Other liabilities		1,027			780

Total liabilities		667,761			140,058

Commitments and contingencies (Note 11)
Stockholders’ equity
Common stock, $0.01 par value; 300,000,000 shares authorized; 92,474,193 issued and 92,453,471 outstanding at September 30, 2011 and 92,240,345 issued and outstanding at December 31, 2010		921			920
Treasury stock, at cost; 20,722 shares		(562	)		—
Additional paid-in-capital		646,310			643,719
Retained deficit		(54	)		(92,845	)

Total stockholders’ equity		646,615			551,794

Total liabilities and stockholders’ equity	$	1,314,376		$	691,852

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

Oasis Petroleum Inc.

Condensed Consolidated Statement of Operations

(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In thousands, except per share data)
Oil and gas revenues	$	87,596		$	32,978		$	213,546		$	79,780
Expenses
Lease operating expenses		9,835			3,208			21,975			9,112
Production taxes		8,873			3,519			22,041			8,131
Depreciation, depletion and amortization		20,859			9,753			47,771			24,385
Exploration expenses		54			(6	)		345			36
Impairment of oil and gas properties		396			825			3,313			11,809
Stock-based compensation expenses		—			—			—			5,200
General and administrative expenses		7,306			4,848			19,870			12,107

Total expenses		47,323			22,147			115,315			70,780

Operating income		40,273			10,831			98,231			9,000

Other income (expense)
Net gain (loss) on derivative instruments		71,224			(3,124	)		67,105			(175	)
Interest expense		(6,786	)		(236	)		(18,745	)		(1,083	)
Other income		524			67			1,215			82

Total other income (expense)		64,962			(3,293	)		49,575			(1,176	)

Income before income taxes		105,235			7,538			147,806			7,824
Income tax expense		38,946			9,239			55,015			39,106

Net income (loss)	$	66,289		$	(1,701	)	$	92,791		$	(31,282	)


Income (loss) per share:
Basic and diluted (Note 10)	$	0.72		$	(0.02	)	$	1.01		$	(0.93	)

Weighted average shares outstanding:
Basic (Note 10)		92,060			92,000			92,052			33,700
Diluted (Note 10)		92,164			92,000			92,208			33,700

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

Oasis Petroleum Inc.

Condensed Consolidated Statement of Changes in Stockholders’ Equity

(Unaudited)

(In thousands)


	Common Stock					Treasury Stock
	Number					Number											Total
	of					of					Additional			Retained			Stockholders’
	Shares			Amount		Shares		Amount			Paid-in-Capital			Deficit			Equity
Balance as of December 31, 2010		92,240		$	920		—	$	—		$	643,719		$	(92,845	)	$	551,794

Stock-based compensation		234			—		—		—			2,592			—			2,592

Vesting of restricted shares		—			1		—		—			(1	)		—			—

Treasury stock — tax withholdings		(21	)		—		21		(562	)		—			—			(562	)

Net income		—			—		—		—			—			92,791			92,791

Balance as of September 30, 2011		92,453		$	921		21	$	(562	)	$	646,310		$	(54	)	$	646,615

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

Oasis Petroleum Inc.

Condensed Consolidated Statement of Cash Flows

(Unaudited)


	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	92,791		$	(31,282	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		47,771			24,385
Impairment of oil and gas properties		3,313			11,809
Deferred income taxes		55,015			39,106
Derivative instruments		(67,105	)		175
Stock-based compensation expenses		2,592			5,810
Debt discount amortization and other		1,041			422
Working capital and other changes:
Change in accounts receivable		(41,286	)		(22,895	)
Change in inventory		(1,850	)		(745	)
Change in prepaid expenses		(297	)		(711	)
Change in other current assets		(337	)		—
Change in other assets		(103	)		(84	)
Change in accounts payable and accrued liabilities		47,820			4,887
Change in other liabilities		317			8

Net cash provided by operating activities		139,682			30,885

Cash flows from investing activities:
Capital expenditures		(386,927	)		(164,666	)
Derivative settlements		(4,831	)		(59	)
Purchases of short-term investments		(124,939	)		—
Advances to joint interest partners		(408	)		(1,198	)
Advances from joint interest partners		8,093			1,218

Net cash used in investing activities		(509,012	)		(164,705	)

Cash flows from financing activities:
Proceeds from sale of common stock		—			399,669
Proceeds from credit facility		—			72,000
Principal payments on credit facility		—			(107,000	)
Proceeds from issuance of senior notes		400,000			—
Purchases of treasury stock		(562	)		—
Debt issuance costs		(10,027	)		(1,788	)

Net cash provided by financing activities		389,411			362,881

Increase in cash and cash equivalents		20,081			229,061
Cash and cash equivalents
Beginning of period		143,520			40,562

End of period	$	163,601		$	269,623


Supplemental non-cash transactions:
Change in accrued capital expenditures	$	23,422		$	22,585
Asset retirement obligations		3,925			261

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

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 publicly traded entity. The Company’s predecessor, Oasis Petroleum LLC, was formed as a Delaware limited liability company on February 26, 2007 by certain members of the Company’s senior management team and through investments made by Oasis Petroleum Management LLC (“OP Management”) and certain private equity funds managed by EnCap Investments L.P. (“EnCap”). OP Management, a Delaware limited liability company, was formed in February 2007 to allow Company employees to become indirect investors in Oasis Petroleum LLC. In May 2007, the Company formed Oasis Petroleum North America LLC (“OPNA”), a Delaware limited liability company, to conduct the domestic oil and natural gas exploration and production activities of the Company. In April 2008, the Company formed Oasis Petroleum International LLC (“OPI”), a Delaware limited liability company, to conduct business development activities outside of the United States of America. 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. OWS, OPM and OPI currently have no material business activities or material assets.

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

Nature of Business

The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Williston Basin. The Company’s assets, which consist of proved and unproved oil and natural gas properties, are located primarily in the Montana and North Dakota areas of the Williston Basin and are owned by OPNA.

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: Oasis Petroleum 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, 2010 is derived from audited financial statements. All significant intercompany transactions have been eliminated in consolidation. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair presentation have been included. In preparing the accompanying 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, 2010 (“2010 Annual Report”).

Cash Equivalents and Short-Term Investments

The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents. The Company classifies all such investments with original maturity dates greater than 90 days as held-to-maturity securities based on management’s intentions to hold the investments to their maturity date.

Treasury Stock

Treasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards. The Company includes the withheld shares as Treasury Stock on its Condensed Consolidated Balance Sheet and separately pays the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not have a publicly announced program to repurchase shares of common stock.

Capitalized Interest

The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalization of interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off.

Recent Accounting Pronouncements

Fair value . In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs” (“ASU 2011-04”). ASU 2011-04 changes some fair value measurement principles under U.S. GAAP, including a change in the valuation premise and the application of premiums and discounts. It also contains some new disclosure requirements under U.S. GAAP. It is effective for interim and annual periods beginning after December 15, 2011. The Company does not expect the adoption of this new guidance to have a significant impact on its financial position, cash flows or results of operations.

Comprehensive income . In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income” (“ASU 2011-05”), which requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The new standard also requires presentation of adjustments for items that are reclassified from other comprehensive income to net income in the statement where the components of net income and the components of other comprehensive income are presented. The new standard does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. On October 21, 2011, the FASB decided to propose a deferral of the new requirement to present reclassifications of other comprehensive income on the face of the income statement. ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011 and will be applied retrospectively. The Company does not expect the adoption of this new guidance to have any impact on its financial position, cash flows or results of operations.

3. Inventory

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


	September 30,		December 31,
	2011		2010
	(In thousands)
Equipment and materials	$	1,978	$	640
Crude oil inventory		835		683

Total inventory	$	2,813	$	1,323

4. Property, Plant and Equipment

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


	September 30,			December 31,
	2011			2010
	(In thousands)
Proved oil and gas properties(1)	$	896,283		$	479,657
Less: Accumulated depreciation, depletion, amortization and impairment		(147,151	)		(98,821	)

Proved oil and gas properties, net		749,132			380,836
Unproved oil and gas properties		87,485			101,311
Other property and equipment(2)		13,825			1,970
Less: Accumulated depreciation		(970	)		(434	)

Other property and equipment, net		12,855			1,536

Total property, plant and equipment, net	$	849,472		$	483,683


(1)		Included in the Company’s proved oil and gas properties are an estimate of future asset retirement costs of $10.0 million and $6.3 million at September 30, 2011 and December 31, 2010, respectively.

(2)		Included in the Company’s other property and equipment is well service equipment of $7.4 million at September 30, 2011. There was no such equipment at December 31, 2010.

As a result of expiring unproved property leases, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $0.4 million and $3.3 million for the three and nine months ended September 30, 2011, respectively, and $0.8 million and $11.8 million for the three and nine months ended September 30, 2010, respectively. No impairment charges on proved oil and natural gas properties were recorded for the three and nine months ended September 30, 2011 or 2010.

5. Fair Value Measurements

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

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

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

Level 1 — 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.

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.

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 September 30, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets (liabilities):
Money market funds	$	105,327	$	—	$	—	$	105,327
Commodity derivative instruments (Note 6) (1)	$	—	$	—	$	61,450	$	61,450

Total assets (liabilities)	$	105,327	$	—	$	61,450	$	166,777


	At fair value as of December 31, 2010
	Level 1		Level 2		Level 3			Total
	(In thousands)
Assets (liabilities):
Commodity derivative instruments (Note 6)	$	—	$	—	$	(10,486	)	$	(10,486	)

Total assets (liabilities)	$	—	$	—	$	(10,486	)	$	(10,486	)


(1)		Included in the Company’s commodity derivative instruments is a liability for deferred premium puts of $9.7 million at September 30, 2011.

The Level 1 instruments presented in the table above consist of money market funds included in Cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheet at September 30, 2011. The Company’s money market funds represent cash equivalents backed by the assets of banks and other liquid securities each with a minimum credit rating of A1/P1. 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 3 instruments presented in the tables above consist of oil collars. The fair value of the Company’s oil collars is based upon mark-to-market valuation reports provided by its counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has a third-party reviewer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or third party reviewer. The determination of the fair value of the Company’s oil collars also incorporates a credit adjustment for non-performance risk. The Company calculates the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a liability position is based on the Company’s current cost of prime based borrowings (prime rate and associated margin effect). Based on these calculations, the Company recorded a reduction to the fair value of its derivative instruments in the amount of $0.5 million and $0.3 million at September 30, 2011 and December 31, 2010, respectively.

The following table presents a reconciliation of the changes in fair value of the financial assets and liabilities classified as Level 3 in the fair value hierarchy for the periods presented.


	2011			2010
	(In thousands)
Balance as of January 1	$	(10,486	)	$	(2,953	)
Total gains (losses) (realized or unrealized):
Included in earnings		67,105			(175	)
Included in other comprehensive income		—			—
Settlements		4,831			59
Transfers in and out of level 3		—			—

Balance as of September 30	$	61,450		$	(3,069	)

Change in unrealized gains (losses) included in earnings relating to derivatives still held at September 30	$	71,936		$	(116	)

Fair Value of Other Financial Instruments

At September 30, 2011, 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. The Company’s derivative instruments reported in the Condensed Consolidated Balance Sheet at September 30, 2011 are stated at fair value; however, certain of the derivative instruments have a deferred premium put, which reduces the asset or increases the liability depending on the fair value of the derivative instrument. The carrying amount of the Company’s long-term debt (senior unsecured notes due 2019) reported in the Condensed Consolidated Balance Sheet at September 30, 2011 is $400.0 million, which approximates fair value.

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 September 30, 2011 is $11.6 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 and nine months ended September 30, 2011 or 2010.

6. Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of September 30, 2011, the Company utilized two-way and three-way collar options and deferred premium puts 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.

As of September 30, 2011, 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:


		Total
		Notional
		Amount of		Average				Average		Average
Settlement	Derivative	Oil		Sub-Floor		Average		Ceiling		Deferred
Period	Instrument	(Barrels)		Price		Floor Price		Price		Premium		Fair Value Asset
												(In thousands)
2011	Two-Way Collars		732,454			$	85.10	$	106.06			$	5,064
2011	Three-Way Collars		45,500	$	60.00	$	80.00	$	94.98				112
2012	Two-Way Collars		1,756,718			$	85.49	$	106.44				18,391
2012	Three-Way Collars		1,020,500	$	69.03	$	89.03	$	113.47				7,356
2012	Put		1,340,000			$	90.00			$	6.65		12,829
2013	Two-Way Collars		807,500			$	89.23	$	111.69				9,982
2013	Three-Way Collars		761,000	$	72.09	$	92.09	$	124.70				5,232
2013	Put		124,000			$	90.00			$	6.65		1,321
2014	Two-Way Collars		62,000			$	90.00	$	112.78				766
2014	Three-Way Collars		62,000	$	72.50	$	92.50	$	126.23				397

												$	61,450

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)
		September 30,		December 31,
Instrument Type	Balance Sheet Location	2011		2010
		(In thousands)
Crude oil collars	Derivative instruments — current assets	$	33,284	$	—
Crude oil collars	Derivative instruments — non-current assets		28,166		—
Crude oil collars	Derivative instruments — current liabilities		—		(6,543	)
Crude oil collars	Derivative instruments — non-current liabilities		—		(3,943	)

	Total derivative instrument asset (liability)	$	61,450	$	(10,486	)

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						Nine Months
		Ended September 30,						Ended September 30,
	Income Statement Location	2011			2010			2011			2010
		(In thousands)
Change in unrealized gain (loss) on derivative instruments	Net gain (loss) on derivative instruments	$	71,403		$	(3,124	)	$	71,936		$	(116	)
Realized loss on derivative instruments	Net gain (loss) on derivative instruments		(179	)		—			(4,831	)		(59	)

	Total net gain (loss) on derivative instruments	$	71,224		$	(3,124	)	$	67,105		$	(175	)

7. Long-Term Debt

Senior secured revolving line of credit. The Company entered into its fourth amendment to its amended and restated credit agreement (the “Amended Credit Facility”) on June 16, 2011. The Amended Credit Facility provides for a senior secured revolving line of credit of up to $600.0 million and matures on February 26, 2015. 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.

Availability under the Amended Credit Facility is restricted to the borrowing base, which is subject to semi-annual redeterminations on April 1 and October 1 of each year. On January 21, 2011, a redetermination of the borrowing base under the Company’s Amended Credit Facility was completed, at the request of the Company, in lieu of the April 1, 2011 redetermination. As a result of this redetermination, the Company’s borrowing base increased from $120 million to $150 million, and was then automatically decreased to $137.5 million in connection with the issuance of the Company’s private placement of $400.0 million of senior unsecured notes due 2019 on February 2, 2011 (discussed below).

Borrowings under the Amended Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London Interbank Offered Rate (“LIBOR”) loan or a bank prime interest rate loan (defined in the Amended Credit Facility as an Alternate Based Rate or “ABR” loan). The LIBOR and ABR loans bear their respective interest rates plus the applicable margin indicated in the following table as of September 30, 2011:


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

An ABR loan does not have a set maturity date and may be repaid at any time upon the Company providing advance notification to the lenders 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 that are greater than three months in duration. At the end of a LIBOR loan term, the Amended Credit Facility allows the Company to elect to continue a LIBOR loan with the same or a differing loan term or convert the borrowing to an ABR loan.

On a quarterly basis, the Company also pays a 0.50% (as of September 30, 2011) 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 September 30, 2011, 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 $137.5 million.

Senior unsecured notes. On February 2, 2011, the Company issued $400.0 million of 7.25% senior unsecured notes (the “Notes”) due February 1, 2019. Interest is payable on the Notes semi-annually in arrears on each February 1 and August 1, commencing August 1, 2011. The Notes are guaranteed on a senior unsecured basis by the Company’s material subsidiaries (“Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The issuance of these Notes resulted in net proceeds to the Company of approximately $390.0 million.

The Notes were issued under an Indenture, dated as of February 2, 2011 (the “Base Indenture”), among the Company and U.S. Bank National Association, as trustee (the “Trustee”), as amended and supplemented by the first supplemental indenture among the Company, the Guarantors and the Trustee, also dated as of February 2, 2011 (the “First Supplemental Indenture”) and as further amended and supplemented by the second supplemental indenture among the Company, the Guarantors and the Trustee (the “Second Supplemental Indenture”; the Base Indenture, as amended and supplemented by the First Supplemental Indenture and the Second Supplemental Indenture, the “Indenture”), dated as of September 19, 2011.

At any time prior to February 1, 2014, the Company has the option to redeem up to 35% of the Notes at a redemption price of 107.25% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to February 1, 2015, the Company has the option to redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after February 1, 2015, the Company has the option to redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 103.625% for the twelve-month period beginning on February 1, 2015, 101.813% for the twelve-month period beginning February 1, 2016 and 100.00% beginning on February 1, 2017, plus accrued and unpaid interest to the redemption date. The Company estimates that the fair value of this option is immaterial at September 30, 2011.

On September 23, 2011, the Company filed a Registration Statement on Form S-4 with the SEC to allow the holders of the Notes to exchange the Notes for registered notes that have substantially identical terms as the Notes. The Company and the Guarantors will use commercially reasonable efforts to cause the exchange to be completed within 360 days after the issuance of the Notes. Under certain circumstances, in lieu of a registered exchange offer, the Company must use commercially reasonable efforts to file a shelf registration statement for the resale of the Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

The Indenture restricts the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to 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 Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants.

The Indenture contains customary events of default, including:

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

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

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

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

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

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

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

Deferred financing costs. As of September 30, 2011, the Company had $1.5 million and $8.9 million of deferred financing costs related to the Amended Credit Facility and the Notes, respectively. The deferred financing costs are included in Deferred costs and other assets on the Company’s Condensed Consolidated Balance Sheet at September 30, 2011 and are being amortized over the respective terms of the Amended Credit Facility and the Notes. The amortization of these deferred financing costs is included in Interest expense on the Condensed Consolidated Statement of Operations.

8. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the nine months ended September 30, 2011:


	ARO
	(In thousands)
Balance at December 31, 2010	$	7,640
Liabilities incurred during period		2,422
Liabilities settled during period		(20	)
Accretion expense		418
Revisions of previous estimates		1,106

Balance at September 30, 2011	$	11,566

9. Income Taxes

Prior to its corporate reorganization in connection with the IPO (see Note 1), the Company was a limited liability company and not subject to federal or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company’s equity holders were responsible for income tax on the Company’s profits. In connection with the closing of the Company’s IPO in June 2010, the Company merged into a corporation and became subject to federal and state income taxes.

The Company’s effective tax rate for the three and nine month periods ended September 30, 2011 was 37.01% and 37.22%, respectively, which was 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 September 30, 2011, 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 September 30, 2011 recorded in noncurrent 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 September 30, 2011, management determined that a valuation allowance was not required for the tax loss carryforwards as they are expected to be fully utilized before expiration.

At September 30, 2010, the Company’s effective tax rate was 39.4%. The Company’s effective tax rate for this period differed from the federal statutory rate of 35% due to state income taxes and certain non-deductible IPO-related costs recorded in the post-corporate reorganization period. At September 30, 2010, the Company also increased its estimate of its deferred tax liability from $29.2 million to $35.4 million. After analyzing the book and tax basis differences for capital expenditure accruals made at June 30, 2010, management determined that an additional deferred tax liability of $5.2 million was needed as of the date of the corporate reorganization. In addition, new tax legislation was passed in September 2010, which extended bonus tax depreciation retroactive to January 1, 2010, resulting in an additional increase of the Company’s deferred tax liability of $0.8 million. These adjustments, along with $0.2 million of other changes in estimates, were recorded as a discrete deferred tax expense of $6.2 million for the three months ended September 30, 2010.

The following table summarizes the Company’s income tax expense for the three and nine months ended September 30, 2010:


	September 30, 2010
	Three			Nine
	Months			Months
	Ended			Ended
			(In thousands)
Initial deferred tax expense	$	—		$	29,238
Discrete adjustments to deferred tax expense		6,206			6,206
Federal and state income tax		3,033			3,662

Total income tax expense	$	9,239		$	39,106

10. Income (Loss) Per Share

Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the 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 (loss) per share.

The following is a calculation of the basic and diluted weighted-average shares outstanding for the three and nine months ended September 30, 2011 and 2010:


	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2011		2010		2011		2010
	(In thousands)
Basic weighted average common shares outstanding		92,060		92,000		92,052		33,700
Dilution effect of stock awards at end of period(1)		104		—		156		—

Diluted weighted average common shares outstanding		92,164		92,000		92,208		33,700


Anti-dilutive stock-based compensation awards		281		217		174		217


(1)		Because the Company reported a net loss for the three and nine months ended September 30, 2010, no unvested stock awards were included in computing diluted loss per share because the effect would have been anti-dilutive.

11. Commitments and Contingencies

Lease obligations. On January 12, 2011, the Company executed the fourth amendment to its office space lease agreement for an additional 11,638 square feet of space within its current office building. Under the terms of the fourth amendment, the Company’s rental obligation for the new premises commenced on May 1, 2011 and terminates on September 30, 2017. On September 26, 2011, the Company executed the fifth amendment to its office space lease agreement for an additional 27,538 square feet of space within its current office building. Under the terms of this amendment, the Company’s rental obligation for the new premises will commence once construction is substantially complete, which is projected to be in January 2012. The fifth amendment to the lease agreement terminates on September 30, 2017. The Company’s total rental commitments under non-cancelable leases for office space and other property and equipment at September 30, 2011 were $13.0 million.

Drilling contracts. As of September 30, 2011, 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 $51.0 million as of September 30, 2011 for the days remaining through the end of the primary terms of the contracts.

Volume commitment agreements. As of September 30, 2011, the Company had certain agreements with an aggregate requirement to deliver a minimum quantity of approximately 10.4 MMBbl and 8.8 Bcf from its Williston Basin project areas within a specified timeframe. Future obligations under these agreements are approximately $35.5 million as of September 30, 2011.

Fracturing services . As of September 30, 2011, 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 $41.6 million as of September 30, 2011 for the months remaining through the end of the primary term of the agreement.

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

On February 2, 2011, the Company issued $400.0 million of Notes (see Note 7 — Long-Term Debt). The Notes 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”). The Notes were offered and sold to qualified institutional buyers in reliance on Rule 144A and non-U.S. persons under Regulation S. They have not been registered under the Securities Act of 1933, as amended, or any state securities laws; however, as discussed above in Note 7, on September 23, 2011, the Company filed a Registration Statement on Form S-4 with the SEC to allow the holders of the Notes to exchange the Notes for registered notes that have substantially identical terms as the Notes. This Registration Statement is pending approval by the SEC.

The following financial information reflects condensed 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 minor 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.

Condensed Consolidating Balance Sheet
(In thousands, except share data)


	September 30, 2011
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	120,330		$	43,271		$	—		$	163,601
Short-term investments		124,939			—			—			124,939
Accounts receivable — oil and gas revenues		—			40,703			—			40,703
Accounts receivable — joint interest partners		80			56,441			(1,406	)		55,115
Inventory		—			2,813			—			2,813
Prepaid expenses		463			354			—			817
Advances to joint interest partners		—			3,846			—			3,846
Derivative instruments		—			33,284			—			33,284
Other current assets		337			—			—			337

Total current assets		246,149			180,712			(1,406	)		425,455

Property, plant and equipment
Oil and gas properties (successful efforts method)		—			983,768			—			983,768
Other property and equipment		—			13,825			—			13,825
Less: accumulated depreciation, depletion, amortization and impairment		—			(148,121	)		—			(148,121	)

Total property, plant and equipment, net		—			849,472			—			849,472

Investments in and advances to affiliates		843,347			—			(843,347	)		—
Derivative instruments		—			28,166			—			28,166
Deferred costs and other assets		8,957			2,326			—			11,283

Total assets	$	1,098,453		$	1,060,676		$	(844,753	)	$	1,314,376

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	1,326		$	43,905		$	(1,406	)	$	43,825
Advances from joint interest partners		—			11,194			—			11,194
Revenues and production taxes payable		—			14,953			—			14,953
Accrued liabilities		10			82,376			—			82,386
Accrued interest payable		4,833			2			—			4,835
Deferred income taxes		—			11,684			—			11,684

Total current liabilities		6,169			164,114			(1,406	)		168,877

Long-term debt		400,000			—			—			400,000
Asset retirement obligations		—			11,566			—			11,566
Deferred income taxes		(8,739	)		95,030			—			86,291
Other liabilities		—			1,027			—			1,027

Total liabilities		397,430			271,737			(1,406	)		667,761

Stockholders’ equity
Capital contributions from affiliates		—			765,639			(765,639	)		—
Common stock, $0.01 par value; 300,000,000 shares authorized; 92,474,193 issued and 92,453,471 outstanding		921			—			—			921
Treasury stock, at cost; 20,722 shares		(562	)		—			—			(562	)
Additional paid-in-capital		637,567			8,743			—			646,310
Retained deficit		63,097			14,557			(77,708	)		(54	)

Total stockholders’ equity		701,023			788,939			(843,347	)		646,615

Total liabilities and stockholders’ equity	$	1,098,453		$	1,060,676		$	(844,753	)	$	1,314,376


	December 31, 2010
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	119,940		$	23,580		$	—		$	143,520
Accounts receivable — oil and gas revenues		—			25,909			—			25,909
Accounts receivable — joint interest partners		—			28,902			(306	)		28,596
Inventory		—			1,323			—			1,323
Prepaid expenses		236			254			—			490
Advances to joint interest partners		—			3,595			—			3,595
Deferred income taxes		—			2,470			—			2,470

Total current assets		120,176			86,033			(306	)		205,903

Property, plant and equipment
Oil and gas properties (successful efforts method)		—			580,968			—			580,968
Other property and equipment		—			1,970			—			1,970
Less: accumulated depreciation, depletion, amortization and impairment		—			(99,255	)		—			(99,255	)

Total property, plant and equipment, net		—			483,683			—			483,683

Investments in and advances to affiliates		485,377			—			(485,377	)		—
Deferred costs and other assets		—			2,266			—			2,266

Total assets	$	605,553		$	571,982		$	(485,683	)	$	691,852

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	306		$	8,198		$	(306	)	$	8,198
Advances from joint interest partners		—			3,101			—			3,101
Revenues and production taxes payable		—			6,180			—			6,180
Accrued liabilities		—			58,239			—			58,239
Accrued interest payable		—			2			—			2
Derivative instruments		—			6,543			—			6,543

Total current liabilities		306			82,263			(306	)		82,263

Asset retirement obligations		—			7,640			—			7,640
Derivative instruments		—			3,943			—			3,943
Deferred income taxes		(954	)		46,386			—			45,432
Other liabilities		—			780			—			780

Total liabilities		(648	)		141,012			(306	)		140,058

Stockholders’ equity
Capital contributions from affiliates		—			513,501			(513,501	)		—
Common stock, $0.01 par value; 300,000,000 shares authorized; 92,240,345 issued and outstanding		920			—			—			920
Additional paid-in-capital		634,976			8,743			—			643,719
Retained deficit		(29,695	)		(91,274	)		28,124			(92,845	)

Total stockholders’ equity		606,201			430,970			(485,377	)		551,794

Total liabilities and stockholders’ equity	$	605,553		$	571,982		$	(485,683	)	$	691,852

Condensed Consolidating Statement of Operations
(In thousands)


	Three Months Ended September 30, 2011
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations			Consolidated
Oil and gas revenues	$	—		$	87,596		$	—		$	87,596
Expenses
Lease operating expenses		—			9,835			—			9,835
Production taxes		—			8,873			—			8,873
Depreciation, depletion and amortization		—			20,859			—			20,859
Exploration expenses		—			54			—			54
Impairment of oil and gas properties		—			396			—			396
General and administrative expenses		1,282			6,024			—			7,306

Total expenses		1,282			46,041			—			47,323

Operating income (loss)		(1,282	)		41,555			—			40,273

Other income (expense)
Equity in earnings in subsidiaries		71,445			—			(71,445	)		—
Net gain (loss) on derivative instruments		—			71,224			—			71,224
Interest expense		(6,495	)		(291	)		—			(6,786	)
Other income		282			242			—			524

Total other income (expense)		65,232			71,175			(71,445	)		64,962

Income (loss) before income taxes		63,950			112,730			(71,445	)		105,235
Income tax benefit (expense)		2,339			(41,285	)		—			(38,946	)

Net income (loss)	$	66,289		$	71,445		$	(71,445	)	$	66,289


	Three Months Ended September 30, 2010
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations		Consolidated
Oil and gas revenues	$	—		$	32,978		$	—	$	32,978
Expenses
Lease operating expenses		—			3,208			—		3,208
Production taxes		—			3,519			—		3,519
Depreciation, depletion and amortization		—			9,753			—		9,753
Exploration expenses		—			(6	)		—		(6	)
Impairment of oil and gas properties		—			825			—		825
General and administrative expenses		1,329			3,519			—		4,848

Total expenses		1,329			20,818			—		22,147

Operating income (loss)		(1,329	)		12,160			—		10,831

Other income (expense)
Equity in earnings in subsidiaries		(1,008	)		—			1,008		—
Net gain (loss) on derivative instruments		—			(3,124	)		—		(3,124	)
Interest expense		—			(236	)		—		(236	)
Other income		62			5			—		67

Total other income (expense)		(946	)		(3,355	)		1,008		(3,293	)

Income (loss) before income taxes		(2,275	)		8,805			1,008		7,538
Income tax benefit (expense)		574			(9,813	)		—		(9,239	)

Net income (loss)	$	(1,701	)	$	(1,008	)	$	1,008	$	(1,701	)


	Nine Months Ended September 30, 2011
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations			Consolidated
Oil and gas revenues	$	—		$	213,546		$	—		$	213,546
Expenses
Lease operating expenses		—			21,975			—			21,975
Production taxes		—			22,041			—			22,041
Depreciation, depletion and amortization		—			47,771			—			47,771
Exploration expenses		—			345			—			345
Impairment of oil and gas properties		—			3,313			—			3,313
General and administrative expenses		3,863			16,007			—			19,870

Total expenses		3,863			111,452			—			115,315

Operating income (loss)		(3,863	)		102,094			—			98,231

Other income (expense)
Equity in earnings in subsidiaries		105,832			—			(105,832	)		—
Net gain (loss) on derivative instruments		—			67,105			—			67,105
Interest expense		(17,909	)		(836	)		—			(18,745	)
Other income		946			269			—			1,215

Total other income (expense)		88,869			66,538			(105,832	)		49,575

Income (loss) before income taxes		85,006			168,632			(105,832	)		147,806
Income tax benefit (expense)		7,785			(62,800	)		—			(55,015	)

Net income (loss)	$	92,791		$	105,832		$	(105,832	)	$	92,791


	Nine Months Ended September 30, 2010
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations		Consolidated
Oil and gas revenues	$	—		$	79,780		$	—	$	79,780
Expenses
Lease operating expenses		—			9,112			—		9,112
Production taxes		—			8,131			—		8,131
Depreciation, depletion and amortization		—			24,385			—		24,385
Exploration expenses		—			36			—		36
Impairment of oil and gas properties		—			11,809			—		11,809
Stock-based compensation expenses		—			5,200			—		5,200
General and administrative expenses		1,582			10,525			—		12,107

Total expenses		1,582			69,198			—		70,780

Operating income (loss)		(1,582	)		10,582			—		9,000

Other income (expense)
Equity in earnings in subsidiaries		(30,336	)		—			30,336		—
Net gain (loss) on derivative instruments		—			(175	)		—		(175	)
Interest expense		—			(1,083	)		—		(1,083	)
Other income		62			20			—		82

Total other income (expense)		(30,274	)		(1,238	)		30,336		(1,176	)

Income (loss) before income taxes		(31,856	)		9,344			30,336		7,824
Income tax benefit (expense)		574			(39,680	)		—		(39,106	)

Net income (loss)	$	(31,282	)	$	(30,336	)	$	30,336	$	(31,282	)

Condensed Consolidating Statement of Cash Flows
(In thousands)


	Nine Months Ended September 30, 2011
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	92,791		$	105,832		$	(105,832	)	$	92,791
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		—			47,771			—			47,771
Impairment of oil and gas properties		—			3,313			—			3,313
Deferred income taxes		(7,785	)		62,800			—			55,015
Derivative instruments		—			(67,105	)		—			(67,105	)
Stock-based compensation expenses		2,592			—			—			2,592
Debt discount amortization and other		793			248			—			1,041
Working capital and other changes:
Change in accounts receivable		(80	)		(42,306	)		1,100			(41,286	)
Change in inventory		—			(1,850	)		—			(1,850	)
Change in prepaid expenses		(227	)		(70	)		—			(297	)
Change in other current assets		(337	)		—			—			(337	)
Change in other assets		(100	)		(3	)		—			(103	)
Change in accounts payable and accrued liabilities		5,864			43,056			(1,100	)		47,820
Change in other liabilities		—			317			—			317

Net cash provided by (used in) operating activities		93,511			152,003			(105,832	)		139,682

Cash flows from investing activities:
Capital expenditures		—			(386,927	)		—			(386,927	)
Derivative settlements		—			(4,831	)		—			(4,831	)
Purchases of short-term investments		(124,939	)		—			—			(124,939	)
Advances to joint interest partners		—			(408	)		—			(408	)
Advances from joint interest partners		—			8,093			—			8,093

Net cash used in investing activities		(124,939	)		(384,073	)		—			(509,012	)

Cash flows from financing activities:
Proceeds from issuance of senior notes		400,000			—			—			400,000
Purchases of treasury stock		(562	)		—			—			(562	)
Debt issuance costs		(9,650	)		(377	)		—			(10,027	)
Investment in / capital contributions from affiliates		(357,970	)		252,138			105,832			—

Net cash provided by financing activities		31,818			251,761			105,832			389,411

Increase in cash and cash equivalents		390			19,691			—			20,081
Cash and cash equivalents at beginning of period		119,940			23,580			—			143,520

Cash and cash equivalents at end of period	$	120,330		$	43,271		$	—		$	163,601


	Nine Months Ended September 30, 2010
				Combined
	Parent/			Guarantor			Intercompany
	Issuer			Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(31,282	)	$	(30,336	)	$	30,336		$	(31,282	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		—			24,385			—			24,385
Impairment of oil and gas properties		—			11,809			—			11,809
Deferred income taxes		(574	)		39,680			—			39,106
Derivative instruments		—			175			—			175
Stock-based compensation expenses		610			5,200			—			5,810
Debt discount amortization and other		—			422			—			422
Working capital and other changes:
Change in accounts receivable		—			(23,108	)		213			(22,895	)
Change in inventory		—			(745	)		—			(745	)
Change in prepaid expenses		(943	)		232			—			(711	)
Change in other assets		—			(84	)		—			(84	)
Change in accounts payable and accrued liabilities		779			4,321			(213	)		4,887
Change in other liabilities		—			8			—			8

Net cash provided by (used in) operating activities		(31,410	)		31,959			30,336			30,885

Cash flows from investing activities:
Capital expenditures		—			(164,666	)		—			(164,666	)
Derivative settlements		—			(59	)		—			(59	)
Advances to joint interest partners		—			(1,198	)		—			(1,198	)
Advances from joint interest partners		—			1,218			—			1,218

Net cash used in investing activities		—			(164,705	)		—			(164,705	)

Cash flows from financing activities:
Proceeds from members’ contributions		235,000			(235,000	)		—			—
Proceeds from sale of common stock		399,669			—			—			399,669
Proceeds from credit facility		—			72,000			—			72,000
Principal payments on credit facility		—			(107,000	)		—			(107,000	)
Debt issuance costs		—			(1,788	)		—			(1,788	)
Investment in / capital contributions from affiliates		(374,664	)		405,000			(30,336	)		—

Net cash provided by financing activities		260,005			133,212			(30,336	)		362,881

Increase in cash and cash equivalents		228,595			466			—			229,061
Cash and cash equivalents at beginning of period		—			40,562			—			40,562

Cash and cash equivalents at end of period	$	228,595		$	41,028		$	—		$	269,623

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.

Derivative instruments . In October 2011, the Company converted its deferred premium put contracts for 4,000 barrels of oil per day in calendar year 2012 to three-way costless collar options. Additionally, the Company added deferred premium put spread contracts for 2,000 barrels of oil per day in calendar year 2012 and three-way costless collar options for 1,000 barrels of oil per day in calendar year 2013. The deferred premium put contracts had a total liability of $4.9 million on the date of execution. As of November 7, 2011, the Company had 8,548 barrels of oil per day hedged for the remainder of 2011, 13,500 barrels of oil per day hedged in 2012, and 7,000 barrels of oil per day hedged in 2013. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.

Senior secured revolving line of credit. On October 6, 2011, the Company entered into a fifth amendment to its amended and restated credit agreement (the “Fifth Amendment”), among Oasis Petroleum North America LLC, as borrower, Oasis Petroleum LLC, Oasis Petroleum Marketing LLC and Oasis Well Services LLC, as wholly owned subsidiaries of the Company, and the Company, as guarantors, the lenders party thereto and BNP Paribas, as administrative agent (the “Amended Credit Facility”). The Fifth Amendment reduced the interest rates payable on borrowings under the Amended Credit Facility, extended the maturity date of the Amended Credit Facility from February 26, 2015 to October 6, 2016, and increased the Company’s senior secured revolving line of credit from $600 million to $1 billion. In connection with the Fifth Amendment, the semi-annual redetermination of the Company’s borrowing base was completed on October 6, 2011, which resulted in the borrowing base of the Amended Credit Facility increasing from $137.5 million to $350 million.


	Applicable Margin			Applicable Margin
Ratio of Total Outstanding Borrowings to Borrowing Base	for LIBOR Loans			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 or equal to .90 to 1 but less than or equal to 1		2.50	%		1.00	%

All other rates, terms and conditions of the Amended Credit Facility dated February 26, 2010 remained the same (see Note 7 — Long-Term Debt).

In addition, on October 25, 2011, the Company’s lenders in the Amended Credit Facility waived the mandatory reduction of the Company’s borrowing base that otherwise would have occurred as a result of the issuance of the senior unsecured notes subsequently offered (see “Senior unsecured notes” below).

Volume commitment agreements. On October 25, 2011, the Company amended one of its existing volume commitment agreements for an aggregate requirement to deliver a minimum quantity of approximately 7.5 Bcf from its Williston Basin project areas within a specified timeframe. The future obligation under this amended agreement is approximately $18.9 million.

Senior unsecured notes. On October 27, 2011, the Company 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 of each year, beginning on May 1, 2012. The 2021 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s existing material subsidiaries (the “Guarantors”). The issuance of the 2021 Notes will result in net proceeds to the Company of approximately $393 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 2021 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. Closing of the issuance and sale of the 2021 Notes is scheduled for November 10, 2011.

On October 27, 2011, in connection with the issuance of these 2021 Notes, the Company entered into an underwriting agreement (the “Underwriting Agreement”) with J.P. Morgan Securities LLC. The Underwriting Agreement contains customary representations, warranties and agreements by the Company and customary conditions to closing, obligations of the parties and termination provisions. Additionally, the Company has agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities. Furthermore, the Company has agreed with the underwriters not to offer or sell any debt securities issued or guaranteed by the Company having a term of more than one year (other than the 2021 Notes) for a period of 60 days after the date of the Underwriting Agreement without the prior written consent of J.P. Morgan Securities LLC.

Drilling contracts. On November 1, 2011, the Company entered into a new drilling rig contract with an initial term greater than one year. In the event of early contract termination under this new contract, the Company would be obligated to pay a maximum of approximately $15.1 million if terminated immediately at the beginning of the contract.


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, 2010 (“2010 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 2010 Annual Report, 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:

•

business strategy;

•

reserves;

•

technology;

•

cash flows and liquidity;

•

financial strategy, budget, projections and operating results;

•

oil and natural gas realized prices;

•

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

•

availability of drilling, completion and production equipment and materials;

•

availability of qualified personnel;

•

owning and operating a services company;

•

the amount, nature and timing of capital expenditures, including future development costs;

•

availability and terms of capital;

•

drilling and completion of wells;

•

infrastructure for salt water disposal;

•

gathering, transportation and marketing of oil and natural gas;

•

property acquisitions;

•

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

•

general economic conditions;

•

inclement weather conditions;

•

competition in the oil and natural gas industry;

•

effectiveness of our risk management activities;

•

environmental liabilities;

•

counterparty credit risk;

•

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

•

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

•

uncertainty regarding our future operating results;

•

estimated future net reserves and present value thereof; and

•

plans, objectives, expectations and intentions contained in this 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 development and acquisition of unconventional oil and natural gas resources primarily in the Williston Basin. Since our inception, we have emphasized the acquisition of properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken formation.

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, our willingness to acquire 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 significantly in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas. 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.

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 nine drilling rigs under contract. We also enter into service contracts to ensure the availability of completion services and the timely fracture stimulation of newly drilled wells. 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.

Third Quarter 2011 Highlights:

•

Completed and placed on production 22 gross operated wells (17.4 net) in the Bakken and Three Forks formations during the three months ended September 30, 2011;

•

Drilling 7 gross operated wells (5.4 net) in the Bakken and Three Forks formations at September 30, 2011;

•

21 gross operated wells (15.6 net) waiting on completion in the Bakken and Three Forks formations as of September 30, 2011;

•

Average daily production of 11,583 Boe per day during the three months ended September 30, 2011;

•

Exploration and production capital expenditures of $198.9 million, consisting primarily of $189.4 million in drilling expenditures during the three months ended September 30, 2011.

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.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011		2010		Change		2011		2010		Change
Operating results (in thousands):
Revenues
Oil	$	85,870	$	32,082	$	53,788	$	208,442	$	76,641	$	131,801
Natural gas		1,726		896		830		5,104		3,139		1,965

Total oil and gas revenues		87,596		32,978		54,618		213,546		79,780		133,766

Production data:
Oil (MBbls)		1,028		483		545		2,407		1,134		1,273
Natural gas (MMcf)		225		142		83		627		451		176
Oil equivalents (MBoe)		1,066		507		559		2,512		1,209		1,303
Average daily production (Boe/d)		11,583		5,507		6,076		9,201		4,429		4,772
Average sales prices:
Oil, without realized derivatives (per Bbl)	$	83.52	$	66.42	$	17.10	$	86.58	$	67.58	$	19.00
Oil, with realized derivatives (per Bbl) (1)		83.35		66.42		16.93		84.58		67.53		17.05
Natural gas (per Mcf)		7.66		6.31		1.35		8.14		6.96		1.18


(1)		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.

Three months ended September 30, 2011 as compared to three months ended September 30, 2010

Oil and natural gas revenues . Our oil and natural gas sales revenues increased $54.6 million, or 166%, to $87.6 million during the three months ended September 30, 2011 as compared to the three months ended September 30, 2010. Our 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 6,076 Boe per day, or 110%, to 11,583 Boe per day during the three months ended September 30, 2011 as compared to the three months ended September 30, 2010. The increase in average daily production sold was primarily a result of our well completions during the last quarter of 2010 and the first three quarters of 2011. Well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 6,063 Boe per day, 1,317 Boe per day and 784 Boe per day, respectively, during the third quarter of 2011 as compared to the third quarter of 2010. The higher production amounts sold increased revenues by $46.2 million, and the remaining $8.4 million increase in revenues was attributable to higher oil and gas sales prices during the three months ended September 30, 2011. Average oil sales prices, without realized derivatives, increased by $17.10/Bbl, or 26%, to an average of $83.52/Bbl for the three months ended September 30, 2011 as compared to the three months ended September 30, 2010.

Nine months ended September 30, 2011 as compared to nine months ended September 30, 2010

Oil and natural gas revenues . Our oil and natural gas sales revenues increased $133.8 million, or 168%, to $213.5 million during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. Our 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 4,772 Boe per day, or 108%, to 9,201 Boe per day during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The increase in average daily production sold was primarily a result of our well completions during the last quarter of 2010 and the first three quarters of 2011. These well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 3,599 Boe per day, 974 Boe per day and 545 Boe per day, respectively, during the first nine months of 2011. The higher production amounts sold increased revenues by $111.7 million, and the remaining $22.1 million increase in revenues was attributable to higher oil and gas sales prices during the nine months ended September 30, 2011. Average oil sales prices, without realized derivatives, increased by $19.00/Bbl, or 28%, to an average of $86.58/Bbl for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010.

Expenses

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


	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			$Change			2011			2010			$Change
	(In thousands, except per Boe of production)
Expenses:
Lease operating expenses	$	9,835		$	3,208		$	6,627		$	21,975		$	9,112		$	12,863
Production taxes		8,873			3,519			5,354			22,041			8,131			13,910
Depreciation, depletion and amortization		20,859			9,753			11,106			47,771			24,385			23,386
Exploration expenses		54			(6	)		60			345			36			309
Impairment of oil and gas properties		396			825			(429	)		3,313			11,809			(8,496	)
Stock-based compensation expenses		—			—			—			—			5,200			(5,200	)
General and administrative expenses		7,306			4,848			2,458			19,870			12,107			7,763

Total expenses	$	47,323		$	22,147		$	25,176		$	115,315		$	70,780		$	44,535

Operating income (loss)		40,273			10,831			29,442			98,231			9,000			89,231

Other income (expense):
Net gain (loss) on derivative instruments		71,224			(3,124	)		74,348			67,105			(175	)		67,280
Interest expense		(6,786	)		(236	)		(6,550	)		(18,745	)		(1,083	)		(17,662	)
Other income		524			67			457			1,215			82			1,133

Total other income (expense)		64,962			(3,293	)		68,255			49,575			(1,176	)		50,751

Income before income taxes		105,235			7,538			97,697			147,806			7,824			139,982
Income tax expense		38,946			9,239			29,707			55,015			39,106			15,909

Net income (loss)	$	66,289		$	(1,701	)	$	67,990		$	92,791		$	(31,282	)	$	124,073


Cost and expense (per Boe of production):
Lease operating expenses	$	9.23		$	6.33		$	2.90		$	8.75		$	7.54		$	1.21
Production taxes		8.33			6.95			1.38			8.77			6.72			2.05
Depreciation, depletion and amortization		19.57			19.25			0.32			19.02			20.17			(1.15	)
Stock-based compensation expenses		—			—			—			—			4.30			(4.30	)
General and administrative expenses		6.86			9.57			(2.71	)		7.91			10.01			(2.10	)

Three months ended September 30, 2011 compared to three months ended September 30, 2010

Lease operating expenses . Lease operating expenses increased $6.6 million to $9.8 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010. This increase was due to an increased number of producing wells and increased water production period over period. The unit operating costs increased from $6.33 per Boe for the three months ended September 30, 2010 to $9.23 per Boe for the three months ended September 30, 2011, primarily as a result of increased costs associated with salt water trucking and disposal and the continuing effects of the inclement weather during the second quarter of 2011. We have $35 million of capital in our 2011 budget allocated to building salt water disposal infrastructure, which is currently being deployed in our key operating areas. This infrastructure is expected to eliminate the need for trucks, simplify operational logistics and reduce costs in 2012 by $2.00 to $3.00 per Boe from current levels.

Production taxes . Our production taxes for the three months ended September 30, 2011 and 2010 were 10.1% and 10.7%, respectively, as a percentage of oil and natural gas sales. The 2011 production tax rate was lower than the 2010 production tax rate 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 $11.1 million to $20.9 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010. The increase in DD&A expense for the three months ended September 30, 2011 was primarily due to the 110% increase in production for the three months ended September 30, 2011 as compared to the same quarter in 2010.

Impairment of oil and gas properties . During the three months ended September 30, 2011 and 2010, we recorded non-cash impairment charges of $0.4 million and $0.8 million, respectively, for unproved property leases that expired during the period. No impairment charges of proved oil and gas properties were recorded for the three months ended September 30, 2011 or 2010.

General and administrative expenses . Our general and administrative expenses increased $2.5 million for the three months ended September 30, 2011 from $4.8 million for the three months ended September 30, 2010. Of this increase, approximately $2.4 million was due to the impact of our organizational growth on employee compensation and $0.5 million was due to the amortization of our restricted stock awards, offset by a decrease of $1.1 million in legal and printing costs related to our IPO incurred during the three months ended September 30, 2010. As of September 30, 2011, we had 106 full-time employees compared to 55 full-time employees as of September 30, 2010.

Derivative instruments . As a result of our derivative activities, we incurred cash settlement net losses of $179 thousand for the three months ended September 30, 2011 and no cash settlements for the three months ended September 30, 2010. In addition, as a result of forward oil price changes, we recognized a $71.4 million non-cash unrealized mark-to-market derivative gain and a $3.1 million non-cash unrealized mark-to-market derivative loss during the three months ended September 30, 2011 and 2010, respectively.

Interest expense . Interest expense increased $6.6 million to $6.8 million for the three months ended September 30, 2011 compared to the three months ended September 30, 2010. The increase was the result of interest related to our senior unsecured notes issued in February 2011 at an interest rate of 7.25%. There were no borrowings under our revolving credit facility during the three months ended September 30, 2011 and 2010, respectively.

Income taxes. Income tax expense for the three months ended September 30, 2010 was recorded at 39.4% of pre-tax net income. In addition, we recorded a $6.2 million discrete deferred tax expense in September 2010 for changes in estimates to our deferred tax liability for the initial book and tax basis differences recorded at the time of our corporate reorganization in June 2010 (see Note 9 — Income Taxes). Our income tax expense was $38.9 million for the three months ended September 30, 2011, resulting in an effective tax rate of 37.01%. 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.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Lease operating expenses . Lease operating expenses increased $12.9 million to $22.0 million for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. This increase was primarily due to an increased number of producing wells from our West Williston acquisitions that were completed in the fourth quarter of 2010 and to our well completions during the last quarter of 2010 and the first three quarters of 2011. The unit operating costs increased from $7.54 for the nine months ended September 30, 2010 to $8.75 for the nine months ended September 30, 2011, primarily due to increased costs associated with water production, salt water disposal and the continuing effects of the inclement weather during the first half of 2011. We have $35 million of capital in our 2011 budget allocated to building salt water disposal infrastructure, which is currently being deployed in our key operating areas. This infrastructure is expected to eliminate the need for trucks, simplify operational logistics and reduce costs in 2012 by $2.00 to $3.00 per Boe from current levels.

Production taxes . Our production taxes for the nine months ended September 30, 2011 and 2010 were relatively consistent at 10.3% and 10.2%, respectively, as a percentage of oil and natural gas sales.

DD&A . DD&A expense increased $23.4 million to $47.8 million for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. The increase in DD&A expense for the nine months ended September 30, 2011 was primarily due to the production increases from the West Williston acquisitions completed in the fourth quarter of 2010 and to our well completions during 2010 and the first three quarters of 2011. The DD&A rate for the nine months ended September 30, 2011 was $19.02 per Boe compared to $20.17 per Boe for the nine months ended September 30, 2010. This decrease in the DD&A rate was due to the lower cost of reserve additions associated with our 2010 acquisition and drilling activities over the last quarter of 2010 and the first three quarters of 2011.

Impairment of oil and gas properties . During the nine months ended September 30, 2011 and 2010, we recorded non-cash impairment charges of $3.3 million and $11.8 million, respectively, for unproved property leases that expired during these periods. No impairment charges of proved oil and gas properties were recorded for the nine months ended September 30, 2011 or 2010.

Stock-based compensation expense . For the nine months ended September 30, 2010, we recorded a $5.2 million non-cash charge for stock-based compensation expense associated with OP Management’s grant of 1.0 million Class C Unit Interests (“C Units”). The C Units were granted on March 24, 2010 to individuals who were employed by us as of February 1, 2010 and who were not executive officers or key employees with an existing capital investment in OP Management. The C Units were membership interests in OP Management and not direct interests in us. The C Units were non-transferable, had no voting power and vested immediately on the grant date. Based on the characteristics of these awards, we concluded that they represented equity-type awards and we accounted for the value of these awards as if they had been awarded by us. We used fair-value-based methods to determine the value of stock-based compensation awarded to our employees and recognized the entire amount as expense due to the immediate vesting of the awards, with no future requisite service period required by the employees. As of December 31, 2010, OP Management had distributed substantially all cash or requisite common stock to its members based on membership interests and distribution percentages. No stock-based compensation expense was recorded for the nine months ended September 30, 2011 related to the C Units.

General and administrative . Our general and administrative expenses increased $7.8 million for the nine months ended September 30, 2011 from $12.1 million for the nine months ended September 30, 2010. Of this increase, approximately $5.9 million was due to the impact of our organizational growth on employee compensation and $2.0 million was due to the amortization of our restricted stock awards, offset by a decrease of $1.1 million in legal costs related to our IPO incurred during the nine months ended September 30, 2010. As of September 30, 2011, we had 106 full-time employees compared to 55 full-time employees as of September 30, 2010.

Derivative instruments . As a result of our derivative activities, we incurred cash settlement net losses of $4.8 million and $59 thousand for the nine months ended September 30, 2011 and 2010, respectively. In addition, as a result of forward oil price changes, we recognized a $71.9 million non-cash unrealized mark-to-market derivative gain and a $0.1 million non-cash unrealized mark-to-market derivative loss during the nine months ended September 30, 2011 and 2010, respectively.

Interest expense . Interest expense increased by $17.7 million to $18.7 million for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. The increase was the result of interest related to our senior unsecured notes issued in February 2011 at an interest rate of 7.25%. There were no borrowings under our revolving credit facility during the nine months ended September 30, 2011 compared to a weighted average outstanding debt balance of $20.5 million at a weighted average interest rate of 3.11% for the nine months ended September 30, 2010.

Income taxes . Prior to our corporate reorganization, we were a limited liability company not subject to entity level income tax. In connection with the closing of our IPO in June 2010, we merged into a corporation and became subject to federal and state entity-level taxation. In connection with our corporate reorganization, an initial net deferred tax liability of $29.2 million was established for differences between the tax and book basis of our assets and liabilities and a corresponding deferred tax expense was recorded in our Consolidated Statement of Operations. Subsequent to our corporate reorganization, we recorded federal and state income tax expense of $3.7 million at an effective tax rate of 39.4% on pre-tax income and a $6.2 million discrete deferred tax expense in September 2010 for changes in estimates on our deferred tax liability for the initial book and tax basis differences recorded in June 2010 (see Note 9 — Income Taxes). Our income tax expense was $55.0 million for the nine months ended September 30, 2011, resulting in an effective tax rate of 37.22%. 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 IPO in June 2010, proceeds from our private placement of senior unsecured notes in February 2011, borrowings under our revolving credit facility, cash flows from operations and capital contributions from private investors prior to our IPO. 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 nine months ended September 30, 2011 and 2010 are presented below:


	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Net cash provided by operating activities	$	139,682		$	30,885
Net cash used in investing activities		(509,012	)		(164,705	)
Net cash provided by financing activities		389,411			362,881

Net increase in cash and cash equivalents	$	20,081		$	229,061

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 $139.7 million and $30.9 million for the nine months ended September 30, 2011 and 2010, respectively. The increase in cash flows provided by operating activities for the nine-month period ended September 30, 2011 as compared to 2010 was primarily the result of an increase in oil and natural gas production of 108% and an increase in average oil sales prices, without realized derivatives, of 28%. In addition, at September 30, 2011, we had a working capital surplus of $256.6 million. This surplus was primarily attributable to our cash and short-term investment balances as a result of the net proceeds from the issuance of our senior unsecured notes in February 2011.

Cash flows used in investing activities

Net cash used in investing activities was $509.0 million and $164.7 million during the nine months ended September 30, 2011 and 2010, respectively. The increase in cash used in investing activities for the nine months ended September 30, 2011 compared to 2010 of $344.3 million was attributable to increased levels of capital expenditures for drilling, development and acquisition costs and purchases of short-term investments.

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


	Nine Months Ended
	September 30, 2011
	(In thousands)
Project Area:
West Williston	$	316,106
East Nesson		64,947
Sanish		18,147
Other(1)		201

Total(2)	$	399,401


(1)		Represents data relating to our properties in the Barnett shale.

(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 changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis. The capital expenditures amount presented in the statement of cash flows also includes cash paid for other property and equipment as well as cash paid for asset retirement obligations.

On August 1, 2011, our Board of Directors increased our total 2011 capital expenditure budget from $490 million to $627 million. Our exploration and production budget increased by $97 million to $587 million, and consists of:

•

$527 million for drilling and completing operated and non-operated wells; and

•

$60 million for maintaining and expanding our leasehold position, constructing infrastructure to support production in our core project areas, micro-seismic work, purchasing seismic data and other test work.

Additionally, the revised 2011 budget includes expenditures related to our newly formed subsidiary, OWS, totaling $24 million for equipment and materials related to start-up costs necessary to provide select well services to OPNA. The 2011 budget also includes $16 million of other non-exploration and production capital expenditures for an operations building in Williston, North Dakota, and other equipment.

While we have budgeted $627 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 the net proceeds from our offering of senior unsecured notes of approximately $393 million, which will close on November 10, 2011, together with our cash on hand, short-term investments and cash flows from operating activities should be sufficient to fund our 2011 capital expenditure budget. However, because the operated wells funded by our 2011 drilling plan represent only a small percentage of our gross identified drilling locations, we may 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.

Cash flows provided by financing activities

Net cash provided by financing activities was $389.4 million and $362.9 million for the nine months ended September 30, 2011 and 2010, respectively. For the nine months ended September 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. For the nine months ended September 30, 2010, cash sourced through financing activities was primarily provided by net proceeds from the sale of common stock in our IPO.

Senior secured revolving line of credit . On October 6, 2011, we entered into our fifth amendment to our Amended Credit Facility. This amendment reduced the interest rates payable on our borrowings under the Amended Credit Facility, extended the maturity date of the Amended Credit Facility from February 26, 2015 to October 6, 2016, and increased our senior secured revolving line of credit from $600 million to $1 billion. In connection with this amendment, the semi-annual redetermination of our borrowing base was completed on October 6, 2011, which resulted in the borrowing base of our Amended Credit Facility increasing from $137.5 million to $350 million. Borrowings under our Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports. 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 September 30, 2011, we had no borrowings and no outstanding letters of credit under the Amended Credit Facility. The Amended 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 Amended Credit Facility may declare all amounts outstanding under the Amended Credit Facility to be immediately due and payable. As of September 30, 2011, we were in compliance with the financial covenants of the Amended Credit Facility.

Senior unsecured notes. On February 2, 2011, we issued $400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the “Notes”). Interest is payable on the notes semi-annually in arrears on each February 1 and August 1, commencing August 1, 2011. These notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 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.

On September 23, 2011, we filed a Registration Statement on Form S-4 with the SEC to allow the holders of the Notes to exchange the Notes for registered notes that have substantially identical terms as the Notes. We and the Guarantors will use commercially reasonable efforts to cause the exchange to be completed within 360 days after the issuance of the Notes. Under certain circumstances, in lieu of a registered exchange offer, we must use commercially reasonable efforts to file a shelf registration statement for the resale of the Notes. If we fail to satisfy these obligations on a timely basis, the annual interest borne by the Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

In order to continue funding the needs of our future capital expenditure program, on October 27, 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 of each year, beginning on May 1, 2012. The 2021 Notes are jointly and severally guaranteed on a senior unsecured basis by all of our existing material subsidiaries (the “Guarantors”). The issuance of the 2021 Notes will result in net proceeds to us of approximately $393 million, which we will use to fund our exploration, development and acquisition program and for general corporate purposes. The issuance and sale of the 2021 Notes has been registered under the Securities Act of 1933 pursuant to our automatic shelf Registration Statement on Form S-3 (Registration No. 333-175603), as amended, filed with the SEC on July 15, 2011. Closing of the issuance and sale of the 2021 Notes is scheduled for November 10, 2011.

On October 27, 2011, in connection with the issuance of these 2021 Notes, we entered into an underwriting agreement (the “Underwriting Agreement”) with J.P. Morgan Securities LLC. The Underwriting Agreement contains customary representations, warranties and agreements by us and customary conditions to closing, obligations of the parties and termination provisions. Additionally, we agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities. Furthermore, we agreed with the underwriters not to offer or sell any debt securities issued or guaranteed by us having a term of more than one year (other than the 2021 Notes) for a period of 60 days after the date of the Underwriting Agreement without the prior written consent of J.P. Morgan Securities LLC.

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.

Contractual Obligations

We have the following contractual obligations and commitments as of September 30, 2011 (in thousands):


			Within						More Than
Contractual Obligations	Total		1 Year		2-3 Years		4-5 Years		5 Years
Operating leases (1)	$	13,002	$	1,823	$	4,404	$	4,503	$	2,272
Drilling rig commitments (1)		51,000		13,805		34,795		2,400		—
Volume commitment agreements (1)		35,483		659		272		11,242		23,310
Fracturing service agreements (1)		41,625		36,375		5,250		—		—
Senior unsecured notes (2)		400,000		—		—		—		400,000
Asset retirement obligations (3)		11,566		—		1,598		689		9,279

Total	$	552,676	$	52,662	$	46,319	$	18,834	$	434,861


(1)		See Note 11 to our unaudited condensed consolidated financial statements for a description of our operating leases, drilling rig commitments, volume commitment agreements and fracturing service agreements.

(2)		See Note 7 to our unaudited condensed consolidated financial statements for a description of our senior unsecured notes. As of September 30, 2011, we had no balance outstanding under our Amended Credit Facility.

(3)		Amounts represent our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 8 to our unaudited condensed consolidated financial statements.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2010 Annual Report other than those noted below.

Cash Equivalents and Short-Term Investments

Treasury Stock

Capitalized Interest

Recent Accounting Pronouncements

Fair value . In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs” (“ASU 2011-04”). ASU 2011-04 changes some fair value measurement principles under U.S. GAAP, including a change in the valuation premise and the application of premiums and discounts. It also contains some new disclosure requirements under U.S. GAAP. It is effective for interim and annual periods beginning after December 15, 2011. We do not expect the adoption of this new guidance to have a significant impact on our financial position, cash flows or results of operations.

Comprehensive income . In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income” (“ASU 2011-05”), which requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The new standard also requires presentation of adjustments for items that are reclassified from other comprehensive income to net income in the statement where the components of net income and the components of other comprehensive income are presented. The new standard does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. On October 21, 2011, the FASB decided to propose a deferral of the new requirement to present reclassifications of other comprehensive income on the face of the income statement. ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011 and will be applied retrospectively. We do not expect the adoption of this new guidance to have any impact on our financial position, cash flows or results of operations.

Off-Balance Sheet Arrangements

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


Item 3.		— Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2010 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 September 30, 2011, we utilized two-way and three-way collar options and deferred premium puts 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 NYMEX-WTI plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. For the deferred premium puts, we pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put, we receive the difference between the floor price and the index price multiplied by the contract volumes less the premium. If the index price settles at or above the floor price of the put, we pay only the premium.

We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium put option, which reduces the asset or increases the liability, depending on the fair value of the derivative instrument. 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 September 30, 2011:


		Total
		Notional		Average
		Amount of		Sub-						Average
Settlement	Derivative	Oil		Floor		Average		Average		Deferred
Period	Instrument	(Barrels)		Price		Floor Price		Ceiling Price		Premium		Fair Value Asset
												(In thousands)
2011	Two-Way Collars		732,454			$	85.10	$	106.06			$	5,064
2011	Three-Way Collars		45,500	$	60.00	$	80.00	$	94.98				112
2012	Two-Way Collars		1,756,718			$	85.49	$	106.44				18,391
2012	Three-Way Collars		1,020,500	$	69.03	$	89.03	$	113.47				7,356
2012	Put		1,340,000			$	90.00			$	6.65		12,829
2013	Two-Way Collars		807,500			$	89.23	$	111.69				9,982
2013	Three-Way Collars		761,000	$	72.09	$	92.09	$	124.70				5,232
2013	Put		124,000			$	90.00			$	6.65		1,321
2014	Two-Way Collars		62,000			$	90.00	$	112.78				766
2014	Three-Way Collars		62,000	$	72.50	$	92.50	$	126.23				397

												$	61,450

Interest rate risk. We had $400.0 million of senior unsecured notes outstanding at September 30, 2011, which have a fixed cash interest rate of 7.25% per annum. During the first nine months of 2011, 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, all 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.

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.

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. The Company had a net derivative asset position of approximately $61.5 million at September 30, 2011.


Item 4.		— Controls and Procedures

Material weakness in internal control over financial reporting. Prior to the completion of our IPO, we were a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. As previously discussed in Item 9A. “Controls and Procedures” of our 2010 Annual Report, we did not maintain an effective control environment in that the design and execution of our controls did not consistently result in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements, which resulted in certain control deficiencies. We concluded that these control deficiencies constituted a material weakness in our control environment.

Remediation activities. Although remediation efforts are still in progress, management has taken steps to address the cause of the material weakness by putting into place new accounting processes and control procedures. In addition, we have hired additional accounting and financial reporting staff since our IPO, implemented additional analysis and reconciliation procedures and increased the levels of review and approval. Additionally, we have begun taking steps to comprehensively document and analyze our system of internal control over financial reporting in preparation for our first management report on internal control over financial reporting required in connection with our Annual Report on Form 10-K for the year ended December 31, 2011.

Management will continue to evaluate the design and effectiveness of these control changes in conjunction with its ongoing evaluation, review, formalization and testing of our internal control environment over the remainder of 2011. We will not complete our review until after this Quarterly Report on Form 10-Q is filed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to additional significant deficiencies and other material weaknesses.

Evaluation of disclosure controls and procedures . As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2011. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. In light of the previously identified material weakness described above, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of September 30, 2011. Notwithstanding the existence of the material weakness, management concluded that the financial statements and other financial information included in this Quarterly Report on Form 10-Q present fairly, in all material respects, the financial condition, results of operations and cash flows for all periods presented.

Changes in internal control over financial reporting . As our remediation efforts are still in progress, as described above, there were changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2010 Annual Report. Except for the risk factors set forth below, there have been no material changes in our risk factors from those described in our 2010 Annual Report.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs to producers and additional operating restrictions or delays, which could adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act (the “SDWA”) and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. For instance, effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations pursuant to which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Number, subject to certain trade secret protections. In September 2011, the North Dakota Industrial Commission proposed new regulations for hydraulic fracturing activities that could require well operators, under certain circumstances, to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, Chemical Abstracts Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. In the event that new or more stringent federal, state or local legal restrictions are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S. Department of Energy is conducting an investigation of practices the EPA could

recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that EPA’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanism.

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

On September 12, 2011, President Obama sent to Congress a legislative package that includes proposed legislation that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities, and (iv) the extension of the amortization period for certain geological and geophysical expenditures.

These proposals also were included in President Obama’s Proposed Fiscal Year 2012 Budget. It is unclear whether any such changes or similar changes will be enacted or, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and gas exploration and production. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.


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 September 30, 2011:


	Total				Total Number of Shares		Maximum Number (or
	Number of		Average Price		Purchased as Part of		Approximate Dollar Value) of
	Shares		Paid		Publicly Announced		Shares that May Be Purchased
Period	Exchanged (1)		per Share		Plans or Programs		Under the Plans or Programs
Jul 1 – Jul 31, 2011		—	$	—		—		—
Aug 1 – Aug 31, 2011		—		—		—		—
Sept 1 – Sept 30, 2011		127		26.34		—		—

Total		127	$	26.34		—		—


(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.


Item 6.		— Exhibits


Exhibit
No.			Description of Exhibit
	4.1		Supplemental Indenture dated as of September 19, 2011 among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.4 to the Company’s Registration Statement on Form S-4 on September 23, 2011, and incorporated herein by reference).

	4.2		Fifth Amendment to Amended and Restated Credit Agreement, dated as of October 6, 2011, among Oasis Petroleum North America LLC, 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 (file no. 001-34776) filed on October 7, 2011, and incorporated herein by reference).

	4.3		Underwriting Agreement dated October 27, 2011, by and among Oasis Petroleum Inc., the subsidiary guarantors named therein and J.P. Morgan Securities LLC, as representative of the underwriters named therein (filed as Exhibit 1.1 to the Company’s Current Report on Form 8-K (file no. 001-34776) filed on October 28, 2011, 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.

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: November 9, 2011	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)

EXHIBIT INDEX


Exhibit
No.			Description of Exhibit
	4.1		Supplemental Indenture dated as of September 19, 2011 among the Company, the Guarantors and U.S. Bank National Association, as trustee (filed as Exhibit 4.4 to the Company’s Registration Statement on Form S-4 on September 23, 2011, and incorporated herein by reference).

	4.2		Fifth Amendment to Amended and Restated Credit Agreement, dated as of October 6, 2011, among Oasis Petroleum North America LLC, 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 (file no. 001-34776) filed on October 7, 2011, and incorporated herein by reference).

	4.3		Underwriting Agreement dated October 27, 2011, by and among Oasis Petroleum Inc., the subsidiary guarantors named therein and J.P. Morgan Securities LLC, as representative of the underwriters named therein (filed as Exhibit 1.1 to the Company’s Current Report on Form 8-K (file no. 001-34776) filed on October 28, 2011, 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.

TABLE OF CONTENTS

Part I Financial Information Item 1. Financial Statements (unaudited)Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 6. Exhibits

Exhibits

Exhibit 31.1 Exhibit 31.2 Exhibit 32.1 Exhibit 32.2

CHRD 10-Q Quarter ended Sept. 30, 2011

Exhibits