CHRD 10-Q Quarterly Report Sept. 30, 2010

CHORD ENERGY CORP

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10-Q 1 c08137e10vq.htm FORM 10-Q Form 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, 2010


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

1001 Fannin Street, Suite 1500
Houston, Texas		77002

(Address of principal executive offices)		(Zip Code)

(281) 404-9500
(Registrant’s telephone number, including area code)

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

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


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	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 10, 2010: 92,240,345 shares.

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

TABLE OF CONTENTS


	Page
PART I — FINANCIAL INFORMATION		1

Item 1. — Financial Statements (Unaudited)		1

Consolidated Balance Sheet at September 30, 2010 and December 31, 2009		2

Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2010 and 2009		3

Consolidated Statement of Changes in Stockholders’/Members’ Equity for the Nine Months Ended September 30, 2010		4

Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		5

Notes to the Consolidated Financial Statements		6

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. — Quantitative and Qualitative Disclosures About Market Risk		28

Item 4. — Controls and Procedures		29

PART II — OTHER INFORMATION		31

Item 1. — Legal Proceedings		31

Item 1A. — Risk Factors		31

Item 5. — Other Information		31

Item 6. — Exhibits		31

SIGNATURES		33

EXHIBIT INDEX		34

Exhibit 10.3
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I — FINANCIAL INFORMATION


	Page
Item 1. — Financial Statements (Unaudited)

Consolidated Balance Sheet at September 30, 2010 and December 31, 2009		2

Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2010 and 2009		3

Consolidated Statement of Changes in Stockholders’/Members’ Equity for the Nine Months Ended September 30, 2010		4

Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		5

Notes to the Consolidated Financial Statements		6

OASIS PETROLEUM INC.

CONSOLIDATED BALANCE SHEET
(Unaudited)


	September 30,			December 31,
	2010			2009
	(In thousands, except share amounts)
ASSETS
Current assets
Cash and cash equivalents	$	269,623		$	40,562
Accounts receivable — oil and gas revenues		17,097			9,142
Accounts receivable — joint interest partners		15,967			1,250
Inventory		1,350			1,258
Prepaid expenses		845			134
Advances to joint interest partners		5,803			4,605
Derivative instruments		54			219
Deferred tax asset		462			—

Total current assets		311,201			57,170

Property, plant and equipment
Oil and gas properties (successful efforts method)		419,094			243,350
Other property and equipment		1,734			866
Less: accumulated depreciation, depletion, amortization and impairment		(86,816	)		(62,643	)

Total property, plant and equipment, net		334,012			181,573

Deferred costs and other assets		2,305			810

Total assets	$	647,518		$	239,553


LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY
Current liabilities
Accounts payable	$	3,302		$	1,577
Advances from joint interest partners		1,807			589
Revenues payable and production taxes		5,165			2,563
Accrued liabilities		41,310			18,038
Accrued interest payable		2			144
Derivative instruments		1,277			1,087

Total current liabilities		52,863			23,998

Long-term debt		—			35,000
Asset retirement obligations		6,488			6,511
Derivative instruments		1,846			2,085
Deferred income taxes		39,568			—
Other liabilities		706			109

Total liabilities		101,471			67,703

Commitments and contingencies (see Note 12)
Stockholders’/members’ equity
Capital contributions		—			235,000
Common stock, $0.01 par value; 300,000,000 shares authorized; 92,216,545 shares issued and outstanding		920			—
Additional paid-in-capital		639,559			—
Retained deficit/accumulated loss		(94,432	)		(63,150	)

Total stockholders’/members’ equity		546,047			171,850

Total liabilities and stockholders’/members’ equity	$	647,518		$	239,553

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

OASIS PETROLEUM INC.

CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands, except per share amounts)
Oil and gas revenues	$	32,978		$	11,046		$	79,780		$	20,298
Expenses
Lease operating expenses		3,208			2,063			9,112			5,976
Production taxes		3,519			1,023			8,131			1,754
Depreciation, depletion and amortization		9,753			4,928			24,385			10,138
Exploration expenses		(6	)		181			36			240
Rig termination		—			—			—			3,000
Impairment of oil and gas properties		825			1,613			11,809			2,863
Stock-based compensation expenses		—			—			5,200			—
General and administrative expenses		4,848			1,567			12,107			4,283

Total expenses		22,147			11,375			70,780			28,254

Operating income (loss)		10,831			(329	)		9,000			(7,956	)

Other income (expense)
Change in unrealized gain (loss) on derivative instruments		(3,124	)		234			(116	)		(5,367	)
Realized gain (loss) on derivative instruments		—			130			(59	)		2,363
Interest expense		(236	)		(209	)		(1,083	)		(601	)
Other income (expense)		67			3			82			(5	)

Total other income (expense)		(3,293	)		158			(1,176	)		(3,610	)

Income (loss) before income taxes		7,538			(171	)		7,824			(11,566	)
Income tax expense		9,239			—			39,106			—


Net loss	$	(1,701	)	$	(171	)	$	(31,282	)	$	(11,566	)


Loss per share:
Basic and diluted (Note 11)	$	(0.02	)	$	—		$	(0.93	)	$	—

Pro forma loss per share:
Basic and diluted (Note 11)	$	(0.02	)	$	(0.00	)	$	(0.34	)	$	(0.13	)

Weighted average shares outstanding:
Basic and diluted (Note 11)		92,000			—			33,700			—

Pro forma weighted average shares outstanding:
Basic and diluted (Note 11)		92,000			92,000			92,000			92,000

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

OASIS PETROLEUM INC.

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


	Common Stock									Retained			Total
	Number									Deficit/			Stockholders’/
	of				Capital			Additional Paid-in-		Accumulated			Members’
	Shares		Amount		Contributions			Capital		Loss			Equity
Balance as of December 31, 2009		—	$	—	$	235,000		$	—	$	(63,150	)	$	171,850
Issuance of common stock		92,000		920		—			—		—			920
Proceeds from the sale of common stock		—		—		—			398,749		—			398,749
Reclassification of members’ contributions		—		—		(235,000	)		235,000		—			—
Stock-based compensation		217		—		—			5,810		—			5,810
Net loss		—		—		—			—		(31,282	)		(31,282	)

Balance as of September 30, 2010		92,217	$	920	$	—		$	639,559	$	(94,432	)	$	546,047

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

OASIS PETROLEUM INC.

CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)


	Nine Months Ended
	September 30,
	2010			2009
	(In thousands)
Cash flows from operating activities:
Net loss	$	(31,282	)	$	(11,566	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		24,385			10,138
Impairment of oil and gas properties		11,809			2,863
Deferred income taxes		39,106			—
Derivative instruments		175			3,004
Stock-based compensation expense		5,810			—
Debt discount amortization and other		422			71
Working capital and other changes:
Change in accounts receivable		(22,895	)		(3,990	)
Change in inventory		(745	)		(209	)
Change in prepaid expenses		(711	)		(126	)
Change in other assets		(84	)		—
Change in accounts payable and accrued liabilities		4,887			(637	)
Change in other liabilities		8			(29	)

Net cash provided by (used in) operating activities		30,885			(481	)

Cash flows from investing activities:
Capital expenditures		(164,666	)		(30,807	)
Acquisition of oil and gas properties		—			(36,549	)
Derivative settlements		(59	)		2,363
Advances to joint interest partners		(1,198	)		(3,226	)
Advances from joint interest partners		1,218			(156	)

Net cash used in investing activities		(164,705	)		(68,375	)

Cash flows from financing activities:
Proceeds from members’ contributions		—			69,584
Proceeds from sale of common stock		399,669			—
Proceeds from issuance of debt		72,000			13,000
Reduction in debt		(107,000	)		(13,000	)
Debt issuance costs		(1,788	)		—

Net cash provided by financing activities		362,881			69,584

Increase in cash and cash equivalents		229,061			728
Cash and cash equivalents:
Beginning of period		40,562			1,570

End of period	$	269,623		$	2,298


Supplemental non-cash transactions:
Change in accrued capital expenditures	$	22,585		$	(2,983	)
Asset retirement obligations		261			1,669

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

OASIS PETROLEUM INC.

Notes to 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 and the parent company of Oasis Petroleum LLC. Oasis Petroleum LLC was formed as a Delaware limited liability company on February 26, 2007 by certain members of the Company’s senior management team and through investments made by Oasis Petroleum Management LLC (“OPM”) and private equity funds managed by EnCap Investments LLC (“EnCap”). In April 2008, the Company formed Oasis Petroleum International LLC (“OPI”), a Delaware limited liability company, to conduct business development activities outside of the United States of America. OPI currently has no assets or business activities.

A corporate reorganization occurred concurrently with the completion of the Company’s initial public offering (“IPO”) of its common stock on June 22, 2010. The Company sold 30,370,000 shares and OAS Holding Company LLC (“OAS Holdco”), the selling stockholder, sold 17,930,000 shares of the Company’s common stock, in each case, at $14.00 per share. After deducting estimated expenses and underwriting discounts and commissions of approximately $25.5 million, the Company received net proceeds of $399.7 million. The selling stockholder received aggregate net proceeds of approximately $236.0 million. The Company did not receive any proceeds from the sale of the shares by OAS Holdco.

Nature of Business

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

2. Summary of Significant Accounting Policies

Basis of Presentation

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

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

Recent Accounting Pronouncements

Financial Receivables - On July 21, 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-20 “Receivables (Topic 310) — Disclosures about the Credit Quality of Financial Receivables and the Allowance for Credit Losses.” This new ASU requires disclosure of additional information to assist financial statement users to understand more clearly an entity’s credit risk exposures to finance receivables and the related allowance for credit losses. This ASU is effective for all public companies for interim and annual reporting periods ending on or after December 15, 2010 with specific items, such as the allowance rollforward and modification disclosures, effective for periods beginning after December 15, 2010. The Company does not expect the adoption of this new guidance to have an impact on its financial position, cash flows or results of operations.

3. Inventory

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


	September 30,		December 31,
	2010		2009
	(In thousands)
Equipment and materials	$	819	$	588
Crude oil inventory		531		670

Total inventory	$	1,350	$	1,258

4. Property, Plant and Equipment

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


	September 30,			December 31,
	2010			2009
	(In thousands)
Proved oil and gas properties	$	370,147		$	195,546
Less: Accumulated depreciation, depletion, amortization and impairment		(86,461	)		(62,330	)

Proved oil and gas properties, net		283,686			133,216
Unproved oil and gas properties		48,947			47,804
Other property and equipment		1,734			866
Less: Accumulated depreciation		(355	)		(313	)

Other property and equipment, net		1,379			553

Total property, plant and equipment, net	$	334,012		$	181,573

As a result of expiring unproved leases, the Company recorded non-cash impairment charges of $0.8 million and $11.8 million for the three and nine months ended September 30, 2010, respectively, and $1.2 million and $2.5 million for the three and nine months ended September 30, 2009, respectively. No impairment on proved oil and natural gas properties was recorded for the three and nine months ended September 30, 2010. For both the three and nine months ended September 30, 2009, the Company recorded a $0.4 million non-cash impairment charge on its proved oil and natural gas properties related to certain dry holes.

5. Fair Value Measurements

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

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

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

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

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

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:


	At fair value as of September 30, 2010
	Level 1		Level 2		Level 3			Total
	(In thousands)
Assets (Liabilities):
Commodity Derivative Instruments (see Note 6)	$	—	$	—	$	(3,069	)	$	(3,069	)

Total Derivative Instruments	$	—	$	—	$	(3,069	)	$	(3,069	)


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

Total Derivative Instruments	$	—	$	—	$	(2,953	)	$	(2,953	)

The Level 3 instruments presented in the tables above consist of crude oil swaps and collars. The Company utilizes the mark-to-market valuation reports provided by its counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company calculated the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a liability position is based on the Company’s current cost of prime based borrowings (prime rate and associated margin effect). The following table presents a reconciliation of the changes in fair value of the derivative instruments classified as Level 3 in the fair value hierarchy for the periods presented.


	2010			2009
	(In thousands)
Balance as of January 1	$	(2,953	)	$	4,090
Total gains or (losses) (realized or unrealized):
Included in earnings		(175	)		(3,004	)
Included in other comprehensive income		—			—
Purchases, issuances and settlements		59			(2,363	)
Transfers in and out of level 3		—			—

Balance as of September 30	$	(3,069	)	$	(1,277	)

Change in unrealized gains (losses) included in earnings relating to derivatives still held at September 30	$	(116	)	$	(5,367	)

At September 30, 2010, the Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments.

Nonfinancial Assets and Liabilities

Asset Retirement Obligations — The carrying amount of the Company’s asset retirement obligations (“ARO”) in the Consolidated Balance Sheet at September 30, 2010 is $6.8 million (see Note 8 — Asset Retirement Obligations).The Company determines the ARO by calculating the present value of estimated cash flows related to the liability based on the calculation of the estimated value. Estimating the future ARO requires management to make estimates and judgments regarding timing and the existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs.

Impairment — The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. No impairment on proved oil and natural gas properties was recorded for the three and nine months ended September 30, 2010. For both the three and nine months ended September 30, 2009, the Company recorded a $0.4 million non-cash impairment charge on its proved oil and natural gas properties related to certain dry holes, which had a fair value of zero.

6. Derivative Instruments

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

All derivative instruments are recorded on the Consolidated Balance Sheet as either assets or liabilities measured at their fair value (see Note 5 — Fair Value Measurements). Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value, both realized and unrealized, are recognized in the Other income (expense) section of the Company’s Consolidated Statement of Operations as a gain or loss on mark-to-market derivative contracts. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements are reflected as investing activities in the Company’s Consolidated Statement of Cash Flows.

As of September 30, 2010, the Company had the following outstanding commodity derivative contracts, all of which settle monthly and do not qualify for and were not designated as hedging instruments for accounting purposes:


		Total
		Notional
Settlement	Derivative	Amount of		Average		Average		Average		Fair Value Asset
Period	Instrument	Oil (Barrels)		Sub-Floor Price		Floor Price		Ceiling Price		(Liability)
										(In thousands)
2010	NYMEX Collar		144,102			$	69.28	$	90.38	$	(39	)
2011	NYMEX Collar		465,744			$	68.15	$	90.48		(1,518	)
2011	NYMEX Collar		267,200	$	55.00	$	75.00	$	91.87		(458	)
2012	NYMEX Collar		205,918			$	73.71	$	92.55		(622	)
2012	NYMEX Collar		192,300	$	59.36	$	79.36	$	99.39		(343	)
2013	NYMEX Collar		15,500			$	75.00	$	93.00		(49	)
2013	NYMEX Collar		15,500	$	60.00	$	80.00	$	100.50		(40	)

										$	(3,069	)

As of December 31, 2009, the Company had the following outstanding commodity derivative contracts, all of which settle monthly and do not qualify for and were not designated as hedging instruments for accounting purposes:


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

										$	(2,953	)

The following table summarizes the location and fair value of all outstanding commodity derivative contracts recorded in the Company’s Consolidated Balance Sheet for the periods presented:


Fair Value of Derivative Instrument Assets (Liabilities)
		September 30,			December 31,
Investment Type	Balance Sheet Location	2010			2009
		(In thousands)
Crude oil collar	Derivative Instruments — current assets	$	54		$	219
Crude oil swap	Derivative Instruments — current liabilities		—			(26	)
Crude oil collar	Derivative Instruments — current liabilities		(1,277	)		(1,061	)
Crude oil collar	Derivative Instruments — non-current liabilities		(1,846	)		(2,085	)

	Total Derivative Instruments	$	(3,069	)	$	(2,953	)

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


		Three Months Ended					Nine Months Ended
		September 30,					September 30,
	Income Statement Location	2010			2009		2010			2009
		(In thousands)
Derivative Contracts	Change in Unrealized Gain (Loss) on Derivative Instruments	$	(3,124	)	$	234	$	(116	)	$	(5,367	)
Derivative Contracts	Realized Gain (Loss) on Derivative Instruments		—			130		(59	)		2,363

	Total Derivative Instruments Gain (Loss)	$	(3,124	)	$	364	$	(175	)	$	(3,004	)

7. Long-Term Debt

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

The Amended Credit Facility provides for semi-annual redeterminations on April 1 and October 1 of each year, commencing October 2, 2010. At the Company’s request, the semi-annual redetermination of the borrowing base under its Amended Credit Facility was completed on August 11, 2010. As a result of this redetermination, the Company’s borrowing base increased from $70 million to $120 million. Contemporaneously with this redetermination, the Company amended its Amended Credit Facility to ease certain limitations on the Company’s ability to enter into derivative financial instruments. All other rates, terms and conditions of the Amended Credit Facility remain the same.

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


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

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

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

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 Debt (as defined in the Amended Credit Facility) to consolidated EBITDAX (as defined in the Amended Credit Facility) to be greater than 4.0 to 1.0 for the four quarters ended on the last day of each quarter; and

	•		a requirement that the Company maintain a Current Ratio of consolidated current assets (with exclusions as described in the Amended Credit Facility) to consolidated current liabilities (with exclusions as described in the Amended Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

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

As of September 30, 2010, the Company had no borrowings under the Amended Credit Facility and $110,000 of outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $119.9 million. The weighted average interest rate incurred on the outstanding Amended Credit Facility borrowings for the three and nine months ended September 30, 2010 was 0% and 3.11%, respectively. The Company was in compliance with the financial covenants of the Amended Credit Facility as of September 30, 2010.

The Company recorded $1.8 million of deferred financing costs, which are being amortized over the term of the Amended Credit Facility. The deferred financing costs are included in Deferred costs and other assets on the Company’s Consolidated Balance Sheet at September 30, 2010. The amortization of deferred financing costs is included in Interest expense on the Consolidated Statement of Operations. The Company also wrote off $132,000 of unamortized deferred financing costs related to the Credit Facility, included in Interest expense on the Company’s Consolidated Statement of Operations, for the nine months ended September 30, 2010.

8. Asset Retirement Obligations

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


	(In thousands)
Asset retirement obligation — January 1, 2010	$	6,511
Liabilities incurred		730
Liabilities settled		(164	)
Accretion expense		303
Revisions to estimates		(610	)

Asset retirement obligation — September 30, 2010	$	6,770

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

9. Stock-Based Compensation

Restricted Stock Awards - The Company has granted restricted stock awards to employees and directors under its 2010 Long-Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. As of September 30, 2010, the Company assumed no annual forfeiture rate because of the Company’s lack of turnover and lack of history for this type of award.

The following table summarizes information related to restricted stock held by the Company’s employees and directors at September 30, 2010:


			Weighted Average
			Grant Date
	Shares		Fair Value
Non-vested shares outstanding at December 31, 2009		—		—
Granted		216,545	$	15.73
Vested		—		—
Forfeited		—		—

Non-vested shares outstanding at September 30, 2010		216,545	$	15.73

Stock-based compensation expense recorded for restricted stock awards for both the three and nine months ended September 30, 2010 was approximately $0.6 million and is included in General and administrative expenses on the Company’s Consolidated Statement of Operations. Unrecognized expense as of September 30, 2010 for all outstanding restricted stock awards was $2.8 million and will be recognized over a weighted average period of 2.2 years. No stock-based compensation expense was recorded for the three and nine months ended September 30, 2009 as the Company had not historically issued stock-based compensation awards to its employees and directors.

Class C Common Unit Interests — In March 2010, the Company recorded a $5.2 million stock-based compensation expense associated with OPM’s grant of 1.0 million Class C Common Unit interests (“C Units”) to certain employees of the Company. The C Units were granted on March 24, 2010 to individuals who were employed by the Company as of February 1, 2010, and who were not executive officers or key employees with an existing capital investment in OPM (“Oasis Petroleum Management LLC Capital Members”). All of the C Units vested immediately on the grant date, are non-voting and provide an opportunity for employees to participate in appreciation realized through the IPO and/or future sales or distributions of the Company’s shares indirectly held by OPM.

Based on the characteristics of the C Units awarded to employees, the Company concluded that the C Units represented an equity-type award and accounted for the value of this award as if it had been awarded by the Company. The C Units shareholders are entitled to receive a portion of the distributions made to OPM, but only after those future distributions have satisfied a complete return of the capital investment previously made by the Oasis Petroleum Management LLC Capital Members, plus a specified return on their capital investment.

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

Under the FASB’s authoritative guidance for share-based payments, stock-based compensation expense is measured based on the calculated fair value of the award on the grant date. The expense is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award. The Company used a fair-value-based method to determine the value of stock-based compensation awarded to its employees and recognized the entire grant date fair value of $5.2 million as stock-based compensation expense on the Consolidated Statement of Operations due to the immediate vesting of the awards and no future requisite service period required of the employees.

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

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

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

10. Income Taxes

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

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

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

Following the completion of the corporate reorganization, the Company recorded federal and state income tax expense of $3.7 million at an effective tax rate of 39.4% on pre-tax income. The Company’s effective tax rate for this period differs 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. The Company expects to generate a tax loss in the current year and thus no current income taxes are anticipated to be paid.

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


	September 30, 2010
	Three Months		Nine 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

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


	(In thousands)
Derivatives instruments	$	462
Oil and natural gas properties		(39,568	)

Total net deferred tax asset (liability)	$	(39,106	)

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

11. Loss Per Share

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

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


	September 30, 2010
	Three Months		Nine Months
	Ended		Ended
	(In thousands)
Weighted average basic common shares outstanding(1)		92,000		33,700
Effect of dilutive securities(2)		—		—

Weighted average diluted common shares outstanding		92,000		33,700


(1)		The weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from June 22, 2010, the closing date of the IPO, to September 30, 2010.

(2)		Because the Company reported a net loss for the three and nine months ended September 30, 2010, the non-vested restricted stock awards of 216,545 shares were excluded from the computation of loss per share because the effect would be anti-dilutive.

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


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

Weighted average diluted common shares outstanding		92,000		92,000		92,000		92,000


(1)		Because the Company reported a net loss for the three and nine months ended September 30, 2010, the non-vested restricted stock awards of 216,545 shares were excluded from the computation of loss per share because the effect would be anti-dilutive.

12. Commitments and Contingencies

Lease Obligations — On June 29, 2010, the Company executed an amendment to its office space lease agreement for relocation to a new floor within its current office building. The amended lease agreement has a term of 84 months. As of September 30, 2010, the outstanding rental commitment for the remainder of the amended lease term is $5.4 million.

Drilling Contracts —During the nine months ended September 30, 2010, the Company entered into two new drilling rig contracts. In the event of early contract termination under these new contracts, the Company would be obligated to pay approximately $3.8 million as of September 30, 2010 for the days remaining through the end of the primary terms of the contracts.

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

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.

Asset Acquisition — On November 5, 2010, the Company closed on the acquisition of approximately 16,700 net acres of land in Roosevelt County, Montana and approximately 300 Boepd of current production. Total consideration for the transaction was $48.0 million set at the effective date of the acquisition of August 1, 2010 ($49.9 million of cash paid at closing due to closing adjustments). The transaction was funded by cash on the Company’s Consolidated Balance Sheet.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with management’s discussion and analysis contained in our prospectus dated June 16, 2010 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 4 24(b) on June 17, 2010, as well as the unaudited consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q .

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

Forward-looking statements may include statements about our:

	•		business strategy;

	•		reserves;

	•		technology;

	•		cash flows and liquidity;

	•		financial strategy, budget, projections and operating results;

	•		oil and natural gas realized prices;

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

	•		availability of drilling and production equipment;

	•		availability of oil field labor;

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

	•		availability and terms of capital;

	•		drilling of wells;

	•		competition and government regulations;

	•		marketing of oil and natural gas;

	•		exploitation or property acquisitions;

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

	•		general economic conditions;

	•		competition in the oil and natural gas industry;

	•		effectiveness of our risk management activities;

	•		environmental liabilities;

	•		counterparty credit risk;

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

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

	•		uncertainty regarding our future operating results;

	•		estimated future net reserves and present value thereof; and

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

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

Overview

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

Since our inception, we have emphasized the acquisition of properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken formation. Substantially all of our revenues are generated through the sale of oil and natural gas production at market prices and the settlement of commodity derivative contracts. Our cash flows depend on many factors, including the prices of oil and natural gas, the success of our acquisition and drilling activities, the operational performance of our producing properties, and the costs of services for drilling, completing and operating our oil and gas natural properties.

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;

	•		Commodity price differentials (difference between market index prices and actual realized prices);

	•		Transportation capacity; and

	•		Availability and cost of services (primarily drilling and completion services).

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 two years and currently have five 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 a multi-year inventory of drilling projects and requires some forward planning visibility for obtaining services.

Third Quarter 2010 Highlights:

	•		Completed and placed on production 33 gross wells (7.3 net wells) in the Bakken and Three Forks formations;

	•		Drilling or in the process of completing 33 gross wells (10.7 net wells) in the Bakken and Three Forks formations at September 30, 2010;

	•		Average daily production of 5,507 Boe per day during the three months ended September 30, 2010;

	•		Capital expenditures of $74.8 million, consisting primarily of $72.6 million in drilling expenses; and

	•		Increased our borrowing base from $70 million to $120 million, as a result of our semi-annual redetermination on August 11, 2010.

Results of Operations

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

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


	Three Months Ended September 30,							Nine Months Ended September 30,
	2010		2009		% Change			2010		2009		% Change
Operating results (in thousands):
Revenues
Oil	$	32,082	$	10,537		204	%	$	76,641	$	19,559		292	%
Natural gas		896		509		76	%		3,139		739		325	%

Total oil and gas revenues		32,978		11,046		199	%		79,780		20,298		293	%
Production data:
Oil (MBbls)		483		185		161	%		1,134		399		184	%
Natural gas (MMcf)		142		111		28	%		451		179		152	%
Oil equivalents (MBoe)		507		204		149	%		1,209		429		182	%
Average daily production (Boe/d)		5,507		2,212		149	%		4,429		1,571		182	%
Average sales prices:
Oil, without realized derivatives (per Bbl)	$	66.42	$	56.96		17	%	$	67.58	$	49.02		38	%
Oil, with realized derivatives (1) (per Bbl)		66.42		57.66		15	%		67.53		54.94		23	%
Natural gas (per Mcf)		6.31		4.59		38	%		6.96		4.13		69	%


(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. We incurred no cash settlements during the third quarter ended September 30, 2010.

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

Oil and Natural Gas Revenues . Our oil and natural gas sales revenues increased $21.9 million, or 199%, to $33.0 million during the quarter ended September 30, 2010 as compared to the quarter ended September 30, 2009. 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 3,295 Boe per day, or 149%, to 5,507 Boe per day during the quarter ended September 30, 2010 as compared to the quarter ended September 30, 2009. The increase in average daily production sold was primarily a result of our well completions during the fourth quarter of 2009 and the first three quarters of 2010. These well completions in our Sanish, East Nesson and West Williston project areas increased average daily production by approximately 1,045 Boe per day, 1,220 Boe per day and 1,585 Boe per day, respectively, during the third quarter of 2010. The higher production amounts sold increased revenues by $20.0 million, and the remaining $1.9 million increase in revenues was attributable to higher oil sales prices during the quarter ended September 30, 2010. Average oil sales prices, without realized derivatives, increased by $9.46 per barrel, or 17%, to an average of $66.42 per barrel for the quarter ended September 30, 2010 as compared to the quarter ended September 30, 2009.

Nine months ended September 30, 2010 as compared to nine months ended September 30, 2009

Oil and Natural Gas Revenues . Our oil and natural gas sales revenues increased $59.5 million, or 293%, to $79.8 million during the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. 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 2,858 Boe per day, or 182%, to 4,429 Boe per day during the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. The increase in average daily production sold was primarily a result of our well completions during the fourth quarter of 2009 and the first three quarters of 2010. These well completions in our Sanish, East Nesson and West Williston project areas increased average daily production by approximately 819 Boe per day, 849 Boe per day and 831 Boe per day, respectively, during the first nine months of 2010. The higher production amounts sold increased revenues by $51.6 million, and the remaining $7.9 million increase in revenues was attributable to higher oil sales prices during the nine months ended September 30, 2010. Average oil sales prices, without realized derivatives, increased by $18.56 per barrel, or 38%, to an average of $67.58 per barrel for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009.

Expenses

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


	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			% Change			2010			2009			% Change
	(In thousands, except cost and expense (per Boe of production))
Expenses:
Lease operating expenses	$	3,208		$	2,063			56	%	$	9,112		$	5,976			52	%
Production taxes		3,519			1,023			244	%		8,131			1,754			364	%
Depreciation, depletion and amortization		9,753			4,928			98	%		24,385			10,138			141	%
Exploration expenses		(6	)		181			(103	%)		36			240			(85	%)
Rig termination		—			—			—			—			3,000			(100	%)
Impairment of oil and gas properties		825			1,613			(49	%)		11,809			2,863			312	%
Stock-based compensation expense		—			—			—			5,200			—			N/A
General and administrative expenses		4,848			1,567			209	%		12,107			4,283			183	%

Total expenses	$	22,147		$	11,375			95	%	$	70,780		$	28,254			151	%

Operating income (loss)		10,831			(329	)		(3,392	%)		9,000			(7,956	)		(213	%)

Other income (expense):
Change in unrealized gain (loss) on derivative instruments		(3,124	)		234			(1,435	%)		(116	)		(5,367	)		(98	%)
Realized gain (loss) on derivative instruments, net		—			130			(100	%)		(59	)		2,363			(102	%)
Interest expense		(236	)		(209	)		13	%		(1,083	)		(601	)		80	%
Other income (expense)		67			3			2,133	%		82			(5	)		(1,740	%)

Total other income (expense)		(3,293	)		158			(2,184	%)		(1,176	)		(3,610	)		(67	%)

Income (loss) before income taxes		7,538			(171	)		(4,508	%)		7,824			(11,566	)		(168	%)
Income tax expense		9,239			—			N/A			39,106			—			N/A

Net loss	$	(1,701	)	$	(171	)		895	%	$	(31,282	)	$	(11,566	)		170	%


Cost and expense (per Boe of production):
Lease operating expenses	$	6.33		$	10.14			(38	%)	$	7.54		$	13.94			(46	%)
Production taxes		6.95			5.03			38	%		6.72			4.09			64	%
Depreciation, depletion and amortization		19.25			24.22			(21	%)		20.17			23.64			(15	%)
General and administrative expenses		9.57			7.70			24	%		10.01			9.99			0	%
Stock-based compensation expense		—			—			—			4.30			—			N/A

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

Lease Operating Expenses . Lease operating expenses increased $1.1 million to $3.2 million for the three months ended September 30, 2010 compared to the three months ended September 30, 2009. This increase was primarily due to the higher number of productive wells as a result of our well completions during the fourth quarter of 2009 and the first three quarters of 2010, and from our East Nesson acquisition that was completed at the end of the third quarter of 2009. The 149% increase in production volumes from the three months ended September 30, 2009 to the three months ended September 30, 2010 resulted in a 38% decrease in our unit operating costs, from $10.14 per Boe to $6.33 per Boe.

Production Taxes . Our production taxes for the three months ended September 30, 2010 and 2009 were 10.67% and 9.26%, respectively, as a percentage of oil and natural gas sales. The production tax rate for the three months ended September 30, 2010 was higher than the production tax rate for the three months ended September 30, 2009 due to the increased weighting of oil revenues in North Dakota, which imposes an 11.5% production tax rate. The production taxes for the three months ended September 30, 2009 were primarily for oil and natural gas sales revenue associated with properties in the Montana portion of our West Williston project area, which generate revenues subject to lower production tax rates in Montana.

Depreciation, Depletion and Amortization (DD&A) . Depreciation, depletion and amortization expense increased $4.8 million to $9.8 million for the three months ended September 30, 2010 compared to the three months ended September 30, 2009. The increase in DD&A expense for the three months ended September 30, 2010 was primarily due to the production increases from our well completions during the fourth quarter of 2009 and the first three quarters of 2010, and from our East Nesson acquisition completed at the end of the third quarter of 2009. The DD&A rate for the three months ended September 30, 2010 was $19.25 per Boe compared to $24.22 per Boe for the three months ended September 30, 2009. The lower DD&A rate was due to the lower cost of reserve additions associated with our 2009 acquisitions and drilling activities over the last 12 months ending September 30, 2010.

Impairment of Oil and Gas Properties . During the three months ended September 30, 2010, we recorded non-cash impairment charges of $0.8 million for unproved property leases that expired during the period. During the three months ended September 30, 2009, we recorded a non-cash impairment charge of $1.2 million for unproved property leases that expired during the period and $0.4 million on our proved oil and natural gas properties related to certain dry holes.

General and Administrative . Our general and administrative expenses increased to $4.8 million for the three months ended September 30, 2010 from $1.6 million for the three months September 30, 2009. Of this increase, approximately $1.5 million was due to higher advisory, audit, legal, tax and filing fees incurred in the third quarter of 2010, primarily related to our IPO. In addition, we recorded approximately $0.6 million of stock-based compensation for restricted stock awards for the three months ended September 30, 2010 (see Note 9). The remaining increase was primarily due to higher compensation costs related to additional employees.

Derivatives . As a result of our derivative activities, we incurred no cash settlement losses for the three months ended September 30, 2010 and cash settlement gains of $0.1 million for the three months ended September 30, 2009. In addition, as a result of forward oil price changes, we recognized a non-cash $3.1 million unrealized mark-to-market derivative loss for the three months ended September 30, 2010 and a non-cash $0.2 million unrealized mark-to-market derivative gain for the three months ended September 30, 2009.

Interest Expense . Interest expense increased $27,000 for the three months ended September 30, 2010 compared to the three months ended September 30, 2009. The increase was primarily a result of our increased amortization of the deferred financing costs related to the Amended Credit Facility (see Note 7). There was no debt outstanding during the three months ended September 30, 2010 compared to a weighted average outstanding debt balance of $22.7 million at a weighted average interest rate of 2.78% for the three months ended September 30, 2009.

Nine months ended September 30, 2010 compared to nine months ended September 30, 2009

Lease Operating Expenses . Lease operating expenses increased $3.1 million to $9.1 million for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. This increase was primarily due to the higher number of productive wells from our Sanish and East Nesson acquisitions that were completed at the end of the second and third quarters of 2009, respectively, and from our well completions during the fourth quarter of 2009 and the first three quarters of 2010. The 182% increase in production volumes from the nine months ended September 30, 2009 to the nine months ended September 30, 2010 resulted in a 46% decrease in unit operating costs to $7.54 per Boe.

Production Taxes . Our production taxes for the nine months ended September 30, 2010 and 2009 were 10.19% and 8.64%, respectively, as a percentage of oil and natural gas sales. The production tax rate for the nine months ended September 30, 2010 was higher than the production tax rate for the nine months ended September 30, 2009 due to the increased weighting of oil revenues in North Dakota, which imposes an 11.5% production tax rate. The production taxes for the nine months ended September 30, 2009 were primarily for oil and natural gas sales revenue associated with properties in the Montana portion of our West Williston project area, which generate revenues subject to lower production tax rates in Montana.

Depreciation, Depletion and Amortization (DD&A) . Depreciation, depletion and amortization expense increased $14.2 million to $24.4 million for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. The increase in DD&A expense for the nine months ended September 30, 2010 was primarily due to the production increases from the Sanish and East Nesson acquisitions completed at the end of the second and third quarters of 2009, respectively, and as a result of our well completions during the fourth quarter of 2009 and the first three quarters of 2010. The DD&A rate for the nine months ended September 30, 2010 was $20.17 per Boe compared to $23.64 per Boe for the nine months ended September 30, 2009. The lower DD&A rate was due to the lower cost of reserve additions associated with our 2009 Sanish and East Nesson acquisitions and drilling activities over the last 12 months ending September 30, 2010.

Rig Termination . During the first quarter of 2009, we paid a total of $3.0 million in rig termination expenses in connection with the early termination of two drilling rig contracts entered into in 2008. We did not have any rig termination expenses during the nine months ended September 30, 2010.

Impairment of Oil and Gas Properties . During the nine months ended September 30, 2010 and 2009, we recorded non-cash impairment charges of $11.8 million and $2.9 million, respectively, for unproved property leases that expired during the period. The 2009 non-cash impairment charge also included $0.4 million related to certain dry holes.

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 OPM’s grant of Class C Common Unit interests (“C Units”) to certain employees of the Company. Based on the characteristics of the C Units awarded, we concluded that the C Units represent an equity-type award and we accounted for the value of this award as if it had been awarded by the Company. We used fair-value-based methods to determine the value of stock-based compensation awarded to our employees and recognized the entire amount as expense due to the immediate vesting of the awards and no future requisite service period required by the employees. No stock-based compensation expense was recorded for the nine months ended September 30, 2009 as we had not historically issued stock-based compensation awards to our employees. See Note 9 to our unaudited consolidated financial statements.

General and Administrative . Our general and administrative expenses increased $7.8 million for the nine months ended September 30, 2010 from $4.3 million for the nine months ended September 30, 2009. Of this increase, approximately $3.6 million was due to higher advisory, audit, legal, tax and filing fees, primarily related to our IPO. In addition, we recorded approximately $0.6 million of stock-based compensation for restricted stock awards for the nine months ended September 30, 2010 (see Note 9). The remaining increase was primarily due to higher costs related to employee compensation (including bonuses paid during the first quarter of 2010) and contract labor. As of September 30, 2010, we had 55 full-time employees and contractors compared to 30 full-time employees and contractors as of September 30, 2009.

Derivatives . As a result of our derivative activities, we incurred a cash settlement loss of $59,000 for the nine months ended September 30, 2010 and a cash settlement gain of $2.4 million for the nine months ended September 30, 2009. In addition, as a result of forward oil price changes, we recognized $0.1 million and $5.4 million of non-cash unrealized mark-to-market derivative losses during the nine months ended September 30, 2010 and 2009, respectively.

Interest Expense . Interest expense increased $0.5 million to $1.1 million for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. The increase was the result of our higher weighted average outstanding debt balance at a higher weighted average borrowing rate during the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009, and the increased amortization of the deferred financing costs related to the Amended Credit Facility. In addition, we wrote off $0.1 million of remaining deferred financing costs associated with our previous revolving credit facility in February 2010. Our weighted average debt balance increased to $20.5 million for the nine months ended September 30, 2010 compared to $20.2 million for the nine months ended September 30, 2009. Our weighted average borrowing rate increased to 3.11% million for the nine months ended September 30, 2010 compared to 2.76% for the nine months ended September 30, 2009.

Income Tax Expense. Prior to our corporate reorganization, we were a limited liability company not subject to entity-level income tax. Accordingly, no provision for federal or state corporate income taxes was recorded for the nine months ended September 30, 2009 as the taxable income was allocated directly to our equity holders. In connection with the closing of our IPO, we merged into a corporation and became subject to federal and state entity-level taxation. In connection with our corporate reorganization, an initial net deferred tax liability of $29.2 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 have recorded federal and state income tax expense of $3.7 million at an effective tax rate of 39.4% on pre-tax income. In addition, we recorded 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 10).

Liquidity and Capital Resources

On September 30, 2010, we had $269.6 million of cash and cash equivalents and no indebtedness. Our primary sources of liquidity and capital are existing cash on hand and our operating cash flow, which we believe are sufficient to cover our near-term capital plan. We also maintain an undrawn credit facility, which can be accessed as needed to supplement our primary sources of liquidity and capital. We actively review acquisition opportunities on an ongoing basis, which may require us to obtain additional equity or debt financing.

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

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

Senior Secured Revolving Line of Credit . On February 26, 2010, we entered into the Amended Credit Facility which matures in February 2014. The Amended Credit Facility increased the initial borrowing base to a maximum of $70 million, extended the maturity date to February 26, 2014, and included BNP Paribas, JP Morgan Chase Bank, UBS Loan Finance LLC and Wells Fargo Bank as lenders (collectively, the “Lenders”). Borrowings under the Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports. The Amended Credit Facility provides for semi-annual redeterminations on April 1 and October 1 of each year, commencing October 2, 2010. At our request, our semi-annual redetermination was completed on August 11, 2010, and our borrowing base increased from $70 million to $120 million.

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

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

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

	•		a Current Ratio of consolidated current assets (with exclusions as described in the Amended Credit Facility) to consolidated current liabilities (with exclusions as described in the Amended Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

As of September 30, 2010, we had no borrowings under the Amended Credit Facility and $110,000 of outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $119.9 million. The weighted average debt outstanding for the three and nine months ended September 30, 2010 was $0 and $20.5 million, respectively, and $22.7 million and $20.2 million for the three and nine months ended September 30, 2009, respectively. The weighted average interest rate incurred on the outstanding Amended Credit Facility borrowings for the three and nine months ended September 30, 2010 was 0% and 3.11%, respectively, and 2.78% and 2.76% for the three and nine months ended September 30, 2009, respectively. We were in compliance with the financial covenants of the Amended Credit Facility as of September 30, 2010.

Cash Flow Activity

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


	Nine Months Ended
	September 30,
	2010			2009
Net cash provided by (used in) operating activities	$	30,885		$	(481	)
Net cash used in investing activities		(164,705	)		(68,375	)
Net cash provided by financing activities		362,881			69,584

Net increase in cash and cash equivalents	$	229,061		$	728

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 prices of a portion of our production, thereby mitigating our exposure to price declines, but these transactions may also limit our earnings potential in periods of rising oil prices.

Net cash provided by operating activities was $30.9 million for the nine months ended September 30, 2010 and net cash used in operating activities was $0.5 million for the nine months ended September 30, 2009. The increase in cash flows from operations was primarily the result of an increase in oil and natural gas production of 182% for the nine months ended September 30, 2010 as compared to the same period in 2009. In addition, at September 30, 2010, we had a working capital surplus of $258.3 million. This surplus for the first nine months of 2010 was primarily attributable to our cash balance as a result of the proceeds from the sale of common stock in our IPO.

Cash flows used in investing activities

We had cash flows used in investing activities of $164.7 million and $68.4 million during the nine months ended September 30, 2010 and 2009, respectively, as a result of our capital expenditures for drilling and development costs. For the nine months ended September 30, 2009, expenditures for the development of properties were only for our West Williston and Sanish project areas and did not include properties acquired in the East Nesson project area on September 30, 2009.

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


	Nine Months Ended
	September 30, 2010
Project Area:
West Williston	$	97,357
East Nesson		65,849
Sanish		20,043
Other(1)		33

Total(2)	$	183,282


(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 Consolidated Statement of Cash Flows in our unaudited consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statement of Cash Flows are presented on a cash basis. The capital expenditures amount presented in the Consolidated Statement of Cash Flows also includes cash paid for other property and equipment as well as cash paid for asset retirement costs.

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

On November 4, 2010, our Board of Directors further increased our 2010 capital budget to $328.5 million. This increase is primarily due to the $49.9 million of cash paid at closing (subject to customary post-close purchase price adjustments) for the acquisition of approximately 16,700 net acres of land in Montana and approximately 300 Boepd of current production on November 5, 2010 (see Note 13). This increase in our capital expenditure budget is also due to an increase in expected wells drilled within the acreage acquired from the effective date of the acquisition until the end of 2010. Total gross operated well count is expected to increase from 39 projects (26.2 net wells) to 44 projects (28.2 net wells).

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 $362.9 million for the nine months ended September 30, 2010 and $69.6 million for the nine months ended September 30, 2009. 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. For the nine months ended September 30, 2009, cash sourced through financing activities was primarily provided by capital contributions from EnCap and other private investors and borrowings under our Amended Credit Facility. Our long-term debt, including the current portion, was $26.0 million at September 30, 2009. As of September 30, 2010, we had no borrowings under our Amended Credit Facility and $110,000 of outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $119.9 million.

Contractual obligations

We have the following contractual obligations and commitments as of September 30, 2010 (in thousands):


			Less Than						More Than
Contractual Obligations	Total		1 Year		1-3 Years		3-5 Years		5 Years
Operating leases (1)	$	5,372	$	701	$	1,564	$	1,563	$	1,544
Drilling rig commitments (1)		3,820		3,820		—		—		—
Asset retirement obligations (2)		6,770		282		1,848		74		4,566

Total	$	15,962	$	4,803	$	3,412	$	1,637	$	6,110


(1)		See Note 12 to our unaudited consolidated financial statements for a description of our operating lease obligations and a description of our drilling rig commitments.

(2)		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 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 prospectus dated June 16, 2010 and filed with the SEC pursuant to Rule 424(b) on June 17, 2010, other than those listed below.

Stock-based compensation

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

Income taxes

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

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

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. We do not have uncertain tax positions outstanding and, as such, did not record a liability for the three and nine months ended September 30, 2010.

Recent accounting pronouncements

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

Off-Balance Sheet Arrangements

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

Item 3. — Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

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

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


		Total
		Notional
Settlement	Derivative	Amount of		Average		Average		Average		Fair Value Asset
Period	Instrument	Oil (Barrels)		Sub-Floor Price		Floor Price		Ceiling Price		(Liability)
										(In thousands)
2010	NYMEX Collar		144,102			$	69.28	$	90.38	$	(39	)
2011	NYMEX Collar		465,744			$	68.15	$	90.48		(1,518	)
2011	NYMEX Collar		267,200	$	55.00	$	75.00	$	91.87		(458	)
2012	NYMEX Collar		205,918			$	73.71	$	92.55		(622	)
2012	NYMEX Collar		192,300	$	59.36	$	79.36	$	99.39		(343	)
2013	NYMEX Collar		15,500			$	75.00	$	93.00		(49	)
2013	NYMEX Collar		15,500	$	60.00	$	80.00	$	100.50		(40	)

										$	(3,069	)

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

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

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

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

Item 4. — Controls and Procedures

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

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

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

PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

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

Item 1A. — Risk Factors

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

For a discussion of our potential risks and uncertainties, see the information under the heading “Risk Factors” in our prospectus dated June 16, 2010, filed with the SEC in accordance with Rule 424(b) of the Securities Act on June 17, 2010, and the information described under “Item 1A. Risk Factors,” in our quarterly report on Form 10-Q for the three months ended June 30, 2010, which is accessible on the SEC’s website at www.sec.gov .

Item 5. — Other Information

On November 5, 2010, the Company closed on the acquisition of approximately 16,700 net acres of land in Roosevelt County, Montana and approximately 300 Boepd of current production. Total consideration for the transaction was $48.0 million set at the effective date of the acquisition of August 1, 2010 ($49.9 million of cash paid at closing due to closing adjustments). The transaction was funded by cash on the Company’s Consolidated Balance Sheet.

Item 6. — Exhibits


Exhibit
No.			Description of Exhibit
	3.1		Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).

	3.2		Amended and Restated Bylaws of Oasis Petroleum Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).

	4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on May 19, 2010, and incorporated herein by reference).

	10.1		Second Amendment to Amended and Restated Credit Agreement dated as of August 11, 2010, among Oasis Petroleum North America LLC, as borrower, Oasis Petroleum LLC and Oasis Petroleum Inc., as guarantors, BNP Paribas, as Administrative Agent, and the lenders party thereto (filed as Exhibit 10.18 to the Company’s quarterly report on Form 10-Q on August 13, 2010, and incorporated herein by reference).

	10.2		Indemnification Agreement, dated September 15, 2010, between Oasis Petroleum Inc. and William J. Cassidy (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 17, 2010, and incorporated herein by reference).

	10.3	(a)	Indemnification Agreement, dated September 27, 2010, between Oasis Petroleum Inc. and Nickolas J. Lorentzatos.


Exhibit
No.			Description of Exhibit
	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.


(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 10, 2010	By:	/s/ Thomas B. Nusz
		Thomas B. Nusz
		Chairman, President and Chief Executive Officer (Principal Executive Officer)


	By:	/s/ Roy W. Mace
		Roy W. Mace
		Senior Vice President and Chief Accounting Officer (Principal Financial and Accounting Officer)

EXHIBIT INDEX


Exhibit
No.			Description of Exhibit
	3.1		Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).

	3.2		Amended and Restated Bylaws of Oasis Petroleum Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K on June 24, 2010, and incorporated herein by reference).

	4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on May 19, 2010, and incorporated herein by reference).

	10.1		Second Amendment to Amended and Restated Credit Agreement dated as of August 11, 2010, among Oasis Petroleum North America LLC, as borrower, Oasis Petroleum LLC and Oasis Petroleum Inc., as guarantors, BNP Paribas, as Administrative Agent, and the lenders party thereto (filed as Exhibit 10.18 to the Company’s quarterly report on Form 10-Q on August 13, 2010, and incorporated herein by reference).

	10.2		Indemnification Agreement, dated September 15, 2010, between Oasis Petroleum Inc. and William J. Cassidy (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 17, 2010, and incorporated herein by reference).

	10.3	(a)	Indemnification Agreement, dated September 27, 2010, between Oasis Petroleum Inc. and Nickolas J. Lorentzatos.

	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.


(a)		Filed herewith.

(b)		Furnished herewith.

TABLE OF CONTENTS

Part I Financial Information 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 5. Other Information Item 6. Exhibits

Exhibits

Exhibit 10.3 Exhibit 31.1 Exhibit 31.2 Exhibit 32.1 Exhibit 32.2

CHRD 10-Q Quarter ended Sept. 30, 2010

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Exhibits